Pioneer Natural Resources Company Annual Report 2011

FY2011 Annual Report · Pioneer Natural Resources Company

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A no th e r

2011 10-K AND ANNUAL REPORT

With substantial assets in four of the primary oil and
liquids-rich plays in Texas, we expect to deliver strong
production growth again in 2012.

2 0 1 2 d r i l l i n g
f o c u s e d i n
h Te x a s
o i l - r i c

Barnett Shale Combo

Spraberry Vertical

TEXAS

Wolfcamp Horizontal

Eagle Ford Shale

NA-US-0710

2011 Annual Report

Texas and the Barnett Shale Combo play in North Texas.
The Spraberry ﬁ eld, including the underlying Wolfcamp
formation, and the Eagle Ford Shale are the two most
active plays in the U.S., with the industry operating more
than 200 rigs in each area.

We broke the records that the Company
set in 2010, reporting earnings of
$834 million, or $6.88 per diluted
share, and cash ﬂ ow from operations
of $1.5 billion.

Scott D. Shefﬁ eld
Chairman and CEO

FELLOW SHAREHOLDERS:

I am pleased to report that 2011 was another truly stellar
year for Pioneer. Our portfolio of oil and liquids-rich
assets in Texas, aggressive drilling program and integrated
services model was again a winning combination. We
broke the records that the Company set in 2010, reporting
earnings of $834 million, or $6.88 per diluted share, and
cash ﬂ ow from operations of $1.5 billion. Production from
continuing operations grew 16% compared to 2010. Oil
prices continued to rise during 2011, further enhancing
the returns on investment for our oil and liquids-rich
drilling programs in the Spraberry ﬁ eld in the Permian
Basin of West Texas, the Eagle Ford Shale in South

The Permian Basin has been a rich source of hydrocarbons
since oil was ﬁ rst discovered there in 1923. As a result
of strong oil prices and improved fracture stimulation
technology, what were previously viewed as marginal and
unrecoverable oil reserves are receiving renewed interest.
Pioneer has long been the largest and most active operator
in the Spraberry ﬁ eld and signiﬁ cantly accelerated drilling
when oil prices strengthened in 2010. During 2011,
Pioneer further expanded its activity by drilling 690
vertical wells in the Spraberry ﬁ eld and increased its net
daily production from the ﬁ eld by 33%. Vertical wells
were completed in the Spraberry formation as well as in

2011 YEAR-END PROVED RESERVES

SPRABERRY DAILY PRODUCTION

1.1 billion BOE

Net MBOE

TEXAS

COLORADO

KANSAS

ALASKA

5
4

2
3

4
3

9
0
0
2

0
1
0
2

1
1
0
2

– Essentially all of Pioneer’s proved reserves are in the United States
– 60% of proved reserves are oil and natural gas liquids and 40% are gas
– Has long-lived reserves with a reserves-to-production ratio of 22 years

2011 Annual Report

additional shale and silt pay zones, and most were drilled
deeper to access additional reserves from the Wolfcamp,
Strawn, Atoka and Mississippian intervals.

Our integrated services model
provided tremendous cost savings
during 2011 and gave us access
to critical equipment and services
that were essential to meeting our
aggressive growth goals.

As we reported last year, in vertical wells that include the
additional shale and silt pay zones and the deeper Wolfcamp
formation, average production generally exceeds that of
a typical Spraberry-only well by approximately 30%. In
the 246 wells that Pioneer drilled into the deeper Strawn
interval during 2011, average production rose another 25%.
Fewer wells were drilled into the Atoka and Mississippian
intervals, but adding these intervals also materially enhanced
production and recoverable reserves. The Wolfcamp interval
underlies the Spraberry interval in essentially all of Pioneer’s
approximately 900,000 gross acres under lease in the
Permian Basin, much of which is also prospective for the
Strawn, Atoka and Mississippian intervals.

Late in 2011, Pioneer initiated horizontal drilling in the
Wolfcamp formation in the Spraberry ﬁ eld, completing
two wells with very encouraging early results. These wells
included 5,800-foot laterals and 30+ stage hydraulic
fracture stimulations, and early production has been
seven times that of a vertical Spraberry well. Pioneer
holds leases covering more than 400,000 acres that could
be prospective for horizontal Wolfcamp drilling, and the
Company is currently acquiring 260 square miles of 3-D
seismic data to further delineate horizontal drilling plans
for this acreage.

In the Eagle Ford Shale ﬁ eld, Pioneer executed an aggressive
growth program in 2011, drilling 111 horizontal wells and
growing the Company’s share of daily production to 20,000
barrels oil equivalent (BOE) per day during the fourth quarter.
Our drilling program is focused on the area of the play that

holds oil and natural gas liquids which are priced in relation
to oil prices and at a signiﬁ cant premium to dry natural
gas. Through our joint venture with Reliance Industries, we
signiﬁ cantly increased our drilling program, running 12 rigs
by mid-year, and completed construction of essential central
gathering facilities and other infrastructure during 2011.

Pioneer drilled 44 wells in what is known as the Barnett
Shale Combo play, a section of the Barnett Shale that holds
oil, natural gas liquids and natural gas. We have built a
position of almost 80,000 net acres, which represents more
than 1,000 drilling locations, and operated two rigs in the
play for much of 2011.

Pioneer’s operations on the North Slope of Alaska
progressed during the year with a focus on oil production
operations and continued development drilling.

We invested $2 billion in drilling during 2011, and each of
our asset teams played an important role in providing the
cash ﬂ ow to support our growth initiatives. Our Rockies,
Mid-Continent and South Texas Edwards Trend areas
produce predominantly dry natural gas, and considering the
outlook for low natural gas prices, maximizing revenue and
minimizing costs in these areas is especially important. Our
success in 2011 was driven by strong execution across all
operations and corporate functions, and our employees got
the job done while respecting the health, safety and general
well-being of others and the environment.

I am particularly proud of the progress we’ve made in
evaluating and testing technologies for reducing our use
of fresh water and in measuring, reporting and reducing
other environmental impacts. We expanded our ﬂ eet of
lower-emission natural gas vehicles, participated in industry
efforts to establish a system for disclosing the components
of hydraulic fracturing ﬂ uids, joined other companies in
collaborative efforts to reduce water consumption and
participated in a number of initiatives aimed at better
educating and informing the public about our industry and
the safety of our operating practices.

Our integrated services model provided tremendous
cost savings during 2011 and gave us access to critical
equipment and services that were essential to meeting
our aggressive growth goals. Under this model, which we
expanded during 2011, we own and operate many of our
own services, including fracture stimulation, drilling and
well servicing.

2011 Annual Report

P la n t o h a v e
r ig s r u n n i n g i n
H o r i z o n ta l Wo l f c a m p
b y y e a r e n d

AGGRESSIVE DRILLING PROGRAM

Continuing Liquids-Rich Focus for 2012

Rigs Running at Year End

8
5

0
4

0
1
0
2

1
1
0
2

4
1

9
0
0
2

During 2011, we drilled 904 wells while also reducing debt.
Standard and Poor’s (S&P) recently upgraded Pioneer’s
corporate debt rating to investment grade. Pioneer’s proved
reserve additions totaled 124 million BOE during 2011,
reﬂ ecting our strong drilling results and strong oil prices
offset by the impact of negative natural gas price revisions.
Despite the reduction related to low natural gas prices, we
replaced 256% of 2011 production at an all-in ﬁ nding and
development cost of $17.51 per BOE.

Stock price performance during 2011 was signiﬁ cantly
constrained by a 30% drop in the price of natural gas
over the course of the year. While the average stock prices
for Pioneer’s peer group dropped 17% during the year,
Pioneer’s stock price rose 3% reﬂ ecting our strong operating
results and liquids-weighted asset portfolio. For the three-
year period covering 2009 through 2011, Pioneer was the
top performing energy stock and the fourth best overall
performer in the S&P 500.

With substantial assets in four of the primary oil and
liquids-rich plays in Texas, we expect to deliver strong
production growth again in 2012. We are expanding
activities in the Permian Basin to include an active
horizontal Wolfcamp drilling program and plan to actively
continue our Spraberry, Eagle Ford Shale and Barnett Shale
Combo drilling programs. The capital program for drilling
for 2012 is expected to total $2.4 billion, with 89% of the
spending allocated to drilling and infrastructure in these
four areas. We also expect to spend approximately $400
million to expand our integrated services to control drilling
costs and support the execution of our drilling programs.

We plan to drill approximately 750 vertical wells in the
Spraberry ﬁ eld, completing roughly 50% of these wells in
the underlying Wolfcamp interval and taking the remaining
50% even deeper into the Strawn, Atoka or Mississippian
intervals. Approximately 50 of these wells will be on
locations downspaced from 40 acres to 20 acres. For the
34 wells Pioneer drilled on 20-acre locations over the past
two years, production performance approximates the type
curve for a 40-acre well.

Pioneer has recently increased its rig count in the horizontal
Wolfcamp play from one to three rigs, and we plan an
additional increase to seven rigs by the end of this year.
Two wells are currently being drilled in southern Reagan
County and a third in southern Upton County. All three
wells will be testing longer laterals and additional fracture
stimulation stages.

In the Eagle Ford Shale, Pioneer plans to run 12 rigs and
drill approximately 125 horizontal wells, primarily in the

2011 Annual Report

Strong execution was critical across
all operations and corporate functions,
and our employees got the job done
while respecting the health, safety
and general well-being of others and
the environment.

liquids-rich area of the play. Production is expected to
double in 2012, and we continue to work to control costs,
further reduce drilling times and optimize completion
techniques. To reduce costs, we are testing the use of lower-
cost proppant for fracture stimulation with good results to
date. Build out of our midstream facilities continues, and
we have added agreements for third-party processing and
transportation of our growing production.

Pioneer’s production from the Barnett Shale is expected to
approximately double during 2012 as we continue to run
two rigs in the Combo play. Production there is comprised of
60% oil and natural gas liquids and 40% dry natural gas.

On the North Slope of Alaska, Pioneer continues to drill
development wells from our island facility, and we have
contracted a second rig to drill two exploration wells that
cannot be reached from the island during the current winter
drilling season.

We will continue to rely on our long-lived natural gas
assets in the Rockies, Mid-Continent and Edwards Trend,
with their steady production and slow declines, to provide
essential cash ﬂ ow.

WELL COUNT INCREASING

Gross Wells Drilled

4
0
9

1
1
0
2

1
8
4

0
1
0
2

8
7

9
0
0
2

In February, we announced plans to sell our assets in South
Africa, completely exiting international operations.

As we look forward to another exciting year, I want to
commend Pioneer employees for consistently demonstrating
our commitment to strong corporate values and for their
dedication to Pioneer’s continued success. Employees
again honored Pioneer by voting the Company a top place
to work, and they positively impacted their communities
by generously giving of their time and ﬁ nancial resources,
many times in joint effort with Pioneer.

In 2012, we will continue to build on the strength of
dominant operations in four of the best oil and liquids-rich
plays in Texas and expect yet another year of stellar results.
As always, I appreciate your support.

Scott D. Shefﬁ eld
Chairman and CEO

FORWARD-LOOKING STATEMENTS:

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.

“All-in ﬁ nding and development cost” means total costs incurred divided by 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. 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.

2011 Annual Report

R. Hartwell Gardner 2,4
Retired Treasurer
Mobil Corporation

Andrew D. Lundquist 3,4
Managing Partner
BlueWater Strategies LLC

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

Scott J. Reiman 3,4
President
Hexagon Investments

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

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

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

BOARD OF DIRECTORS

Scott D. Shefﬁ eld
Chairman and
Chief Executive Ofﬁ cer

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

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

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

Committee Membership:

1 Lead Director

2 Audit Committee

3 Compensation and

Management Development
Committee

4 Nominating and Corporate
Governance Committee

OFFICERS

Scott D. Shefﬁ eld
Chairman and
Chief Executive Ofﬁ cer

Timothy L. Dove
President and
Chief Operating Ofﬁ cer

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 Ofﬁ cer

William F. Hannes
Executive Vice President,
South Texas Operations

Danny L. Kellum
Executive Vice President,
Permian Operations

Jay P. Still
Executive Vice President,
Domestic Operations

Frank E. Hopkins
Senior Vice President,
Investor Relations

Denny B. Bullard
Vice President,
Operations Services

Robert C. Hagens
Vice President, Land

Thomas C. Halbouty
Vice President,
Chief Information Ofﬁ cer and
Chief Technology Ofﬁ cer

Frank W. Hall
Vice President and
Chief Accounting Ofﬁ cer

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

Larry N. Paulsen
Vice President,
Administration and
Risk Management

Kenneth H. Shefﬁ eld, Jr.
Vice President, Corporate Engineering

Tom Spalding
Vice President, Geoscience

Susan A. Spratlen
Vice President,
Sustainable Development and
Communication

Roger W. Wallace
Vice President,
Government Affairs

2011 Annual Report

STOCK PERFORMANCE

The information included in the remainder of this document, including this “Stock Performance” section of the 2011
Annual Report, is not a part of Pioneer’s Annual Report on Form 10-K for the ﬁ scal year ended December 31, 2011, and
shall not be deemed to be “soliciting material” or to be “ﬁ led” with the Securities and Exchange Commission (SEC). Such
information shall not be deemed to be incorporated by reference into any ﬁ ling under the Securities Act of 1933 or the
Securities Exchange Act of 1934, except to the extent that Pioneer speciﬁ cally incorporates such information.

The following graph and chart compare Pioneer’s cumulative total stockholder return on common stock during the ﬁ ve-year
period ended December 31, 2011, 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 2007, 2008, 2009,
2010 and 2011 of $100 invested at December 31, 2006, 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

2006

2007

2008

2009

2010

2011

Year ended December 31,

2006

2007

2008

2009

2010

2011

Pioneer

$ 100.00 $ 123.83 $ 41.26 $ 123.23 $ 222.41 $ 229.45

S&P 500 Index

$ 100.00 $ 105.49 $ 66.46 $ 84.05 $ 96.71 $ 98.75

S&P E&P Index

$ 100.00 $ 144.62 $ 88.78 $ 127.06 $ 141.60 $ 137.50

(a) Assumes $100 invested at December 31, 2006, in stock or index, including reinvestment of dividends.

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

/x/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2011
or

/ / 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)

75-2702753
(I.R.S. Employer Identification No.)

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

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

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)(cid:58) No (cid:134)

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:134) 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:134)

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:134)

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:58)

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
Non-accelerated filer

(cid:58)
(cid:134)

(Do not check if a smaller reporting company)

Accelerated filer
Smaller reporting company

(cid:134)
(cid:134)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes (cid:134) No (cid:58)

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

Number of shares of Common Stock outstanding as of February 24, 2012

$10,243,708,609

123,260,358

(1) Proxy Statement for the 2012 Annual Meeting of Shareholders to be held during May 2012 — Referenced in Part III of this
report.

DOCUMENTS INCORPORATED BY REFERENCE:

TABLE OF CONTENTS

Page
Definitions of Certain Terms and Conventions Used Herein ...............................................................................................
4
Cautionary Statement Concerning Forward-Looking Statements ........................................................................................ 5

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 Rule Changes ...................................................................................................................................
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 2012 Continuing Operations Outlook ......................................................................................
2012 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 ..........................................................................................................
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure ............................
Item 9.
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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43
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119
127
127
127
128
129

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 ............................................................................................................

129
129
129
129
130
130

PART IV

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

130

ASDFASDFASDFSADF

Definitions of Certain Terms and Conventions Used Herein

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

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•

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"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" means the daily average natural gas liquids components as priced in Oil Price Information Services ("OPIS") 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.
"LNG" means liquefied natural gas.
"MBbl" means one thousand Bbls.
"MBOE" means one thousand BOEs.
"Mcf" means one thousand cubic feet and is a measure of 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 ("OPIS") in the table "U.S. and Canada LP – Gas Weekly Averages" at Mont Belvieu, Texas.
"NGL" means natural gas liquid.
"NYMEX" means the New York Mercantile Exchange.
"NYSE" means the New York Stock Exchange.
"Pioneer" or the "Company" means Pioneer Natural Resources Company and its subsidiaries.
"Pioneer Southwest" means Pioneer Southwest Energy Partners L.P. and its subsidiaries.
"Proved reserves" mean the 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
("LKH") as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology
establishes a lower contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil ("HKO") elevation and the potential
exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only
if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable
certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not
limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area
of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in
the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of
the engineering analysis on which the project or program was based; and (B) The project has been approved for
development by all necessary parties and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be
determined. The price shall be the average during the 12-month period prior to the ending date of the period covered by the
report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such
period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
"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.

ASDFASDFASDFSADF

"U.S." means United States.
"VPP" means volumetric production payment.
"WTI" means a light, sweet blend of oil produced from fields in western Texas.

•
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• 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.

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.
The forward-looking statements are based on the Company's current expectations, assumptions, estimates and
projections about the Company and the industry in which the Company operates. Although the Company believes
that the expectations and assumptions reflected in the forward-looking statements are reasonable, they involve risks
and uncertainties that are difficult to predict and, in many cases, beyond the Company's control. 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

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

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; Midland, Texas and Capetown, South Africa. At December 31, 2011, the Company had 3,304
employees, 2,282 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
Report 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 approximately 93 percent of the Company's proved oil and gas reserves as of December
31, 2011.

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. Oil and NGL prices have steadily improved since the beginning of 2009, while gas
prices have remained volatile and have generally trended lower since 2009. The decline in gas prices is primarily a
result of growing gas production associated with discoveries of significant gas reserves in United States shale plays,
combined with the warmer than normal 2011/2012 winter, which has resulted in gas storage levels being at
historically high levels, and minimal economic demand growth in the United States.

PIONEER NATURAL RESOURCES COMPANY

During 2009, 2010 and 2011, economic stimulus initiatives implemented in the United States and worldwide
served to stabilize the United States and certain other economies in the world with resulting improvements in
industrial demand and consumer confidence. However, other economies, such as those of certain European Union
(or "Eurozone") nations, continue to face economic struggles. The outlook for a continued worldwide economic
recovery is cautiously optimistic, but remains 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,
especially North American gas prices, will continue to be volatile during 2012.

Significant factors that will impact 2012 commodity prices include: the ongoing impact of economic stimulus
initiatives in the United States and worldwide and continuing economic struggles in Eurozone nations' economies;
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 impact 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 impact the Company's liquidity, financial
position and future results of operations. See "Item 7A. Quantitative and Qualitative Disclosures About Market
Risk" and Notes I and J of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for information regarding the impact to oil and gas revenues during 2011, 2010 and 2009 from
the Company's derivative price risk management activities and the Company's open derivative positions as of
December 31, 2011.

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. Additionally, the
Company has a team of dedicated employees that represent the professional disciplines and sciences that 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 United States and South
Africa subsidiaries that explore for, develop and produce proved reserves. The Company's continuing operations are
principally located in the United States 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,
2011, the Company's production from continuing operations, excluding field fuel usage, of 44.0 MMBOE
represented a 16 percent increase over production from continuing operations during 2010. Production, price and
cost information with respect to the Company's properties for 2011, 2010 and 2009 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, 2011, the Company drilled 1,236 gross (1,112 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 $2.5 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, 2011 include proved

PIONEER NATURAL RESOURCES COMPANY

undeveloped reserves and proved developed reserves that are behind pipe of 259.0 MMBbls of oil, 98.7 MMBbls of
NGLs and 850.8 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.

Exploratory activities. The Company has devoted significant efforts and resources to hiring and developing a
highly skilled geoscience staff as well as acquiring a portfolio of lower-risk exploration opportunities. 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 costs and
support the execution of its accelerating drilling program. The Company has 15 owned drilling rigs operating in the
Spraberry field, and at the end of 2011, had Company-owned fracture stimulation fleets totaling 250,000 horsepower
supporting drilling operations in the Spraberry, Eagle Ford Shale and Barnett Shale Combo areas. 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 2011, 2010 and 2009, the Company spent
$131.9 million, $181.6 million and $88.9 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.

During December 2011, the Company committed to a plan to divest its South Africa assets ("Pioneer South
Africa"). The plan is expected to result in the sale of Pioneer South Africa assets during 2012. In accordance with
GAAP, the Company has classified its South Africa assets and liabilities as discontinued operations held for sale in
the Company's accompanying consolidated balance sheet as of December 31, 2011, and has recast Pioneer South
Africa's results of operations as income from discontinued operations, net of tax in the Company's accompanying
consolidated statements of operations.

During February 2011, the Company completed the sale of its share holdings in Pioneer Natural Resources
Tunisia Ltd. and Pioneer Natural Resources Anaguid Ltd. (referred to in the aggregate as "Pioneer Tunisia") for cash
proceeds of $853.6 million, including normal closing adjustments. As a result of having committed to a plan to sell
the Tunisian subsidiaries during 2010, the Company classified its Tunisian assets and liabilities as discontinued
operations held for sale in the Company's accompanying consolidated balance sheet as of December 31, 2010, and
recorded the historical results of operations of its Tunisian assets as income from discontinued operations, net of tax
in the Company's 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

PIONEER NATURAL RESOURCES COMPANY

improve profitability. See Notes M and U 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 planned 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 2011, the Company's significant purchasers of oil, NGLs and gas were Plains
Marketing LP (16 percent), Occidental Energy Marketing Inc. (14 percent) and Enterprise Products Partners L.P. (12
percent). The Company believes that the loss of any one purchaser would not have an adverse effect on its ability to
sell its oil, NGL and gas production.

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, (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. Effective
February 1, 2009, the Company discontinued hedge accounting on all of its then-existing hedge contracts and began
accounting 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 I 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 2011, 2010 and 2009, as well as the Company's open commodity
derivative positions at December 31, 2011.

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 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 of the Company's

PIONEER NATURAL RESOURCES COMPANY

common stock. Compliance with some of these rules and regulations is costly, and regulations are subject to change
or reinterpretation.

Environmental matters and regulations. The Company's operations are subject to stringent and complex
foreign, federal, state and local laws and regulations governing environmental protection as well as the discharge of
materials into the environment. These laws and regulations may, among other things:

•
•
•

•

require the acquisition of various permits before drilling commences;
enjoin some or all of the operations of facilities deemed in non-compliance 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;
and
require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to
close pits and plug abandoned wells.

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 United States Congress and state legislatures,
federal and state regulatory agencies and foreign government and agencies frequently revise environmental laws and
regulations, and the clear 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 impact on the Company's operating costs.

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

operations are or may be subject.

Waste handling. The 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. Certain processes used to produce oil and gas may enhance the radioactivity of
NORM, which may be present in oilfield wastes. 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 Comprehensive
Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the Superfund law, imposes
joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to
be 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.

PIONEER NATURAL RESOURCES COMPANY

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 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 disposal. In addition, some of the Company's properties have
been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous
substances, wastes or hydrocarbons were not under the Company's control. In fact, there is evidence that petroleum
spills or releases have occurred in the past at some of the properties owned or leased by the Company. These
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.

Water discharges and use. The 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. 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. Spill prevention, control and countermeasure 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 non-compliance 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.

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(cid:486)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 many of its drilling and completion
programs. The process involves the injection of water, sand and chemicals under pressure into rock formations to
stimulate oil and gas production. The process is typically regulated by state oil and gas commissions. The EPA,
however, recently asserted federal regulatory authority over hydraulic fracturing involving diesel fuels under the
SDWA Underground Injection Control Program. In addition, legislation has been introduced before the United
States Congress to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure
of the chemicals used in the fracturing process. At the state level, several states have adopted or are considering
legal requirements that could impose more stringent permitting, disclosure and well construction requirements on
hydraulic fracturing activities. The Company believes that it follows applicable standard industry practices and legal
requirements for groundwater protection in its hydraulic fracturing activities. Nonetheless, if new or more stringent
federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where the

PIONEER NATURAL RESOURCES COMPANY

Company operates, the Company could incur potentially significant added costs to comply with such requirements,
experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps
even be precluded from drilling wells.

In addition, certain governmental reviews are either underway or proposed 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 a committee of the United States House of
Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study
of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results
expected to be available by late 2012 and final results 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 ongoing or
proposed 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.

To the Company's knowledge, there have been no citations, suits or contamination of potable drinking water
arising from its fracturing operations. The Company does not have insurance policies in effect that are intended to
provide coverage for losses solely related to hydraulic fracturing operations; however, the Company believes its
existing insurance policies would cover third-party claims related to hydraulic fracturing operations and associated
legal expenses, subject to the terms of such policies.

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 Federal Clean Air Act (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 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 non-compliance 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. In addition, 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. Gas and oil exploration and production
facilities may be required to incur certain capital expenditures in the future for air pollution control equipment in
connection with obtaining and maintaining operating permits and approvals for air emissions.

PIONEER NATURAL RESOURCES COMPANY

In July 2011, the EPA issued proposed rules that would subject all oil and gas operations (production,
processing, transmission, storage and distribution) to regulation under the New Source Performance Standards
("NSPS") and National Emission Standards for Hazardous Air Pollutants programs. The EPA's proposed rules also
include NSPS standards for completions of hydraulically fractured gas wells. These standards include the reduced
emission completion techniques developed in the EPA's Natural Gas STAR program along with the flaring of gas.
If finalized, these rules could require a number of modifications to the Company's operations, including the
installation of new equipment. Compliance with such rules could result in significant new costs to the Company and
make it more costly and time-consuming to complete oil and gas wells. Any delay or decrease in the completion of
new oil and gas wells could have a material adverse effect on the Company's liquidity, results of operations and
financial condition. Moreover, 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. The TCEQ may expand the application
of the requirements to facilities in other areas of the state in 2012. These new requirements could increase the cost
and time associated with drilling wells in the Barnett Shale or other areas of the state in the future. 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 the state that result in more stringent drilling or operating conditions or limit or
prohibit the drilling of new gas wells for any extended period of time could increase the Company's costs and/or
reduce its production, which could have a material adverse effect on the Company's results of operations and cash
flows.

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 and/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 of or
limitations on the Company's ability to perform operations and thus have an adverse effect on the Company's
business.

The United States Fish and Wildlife Service has proposed listing the Dunes Sagebrush Lizard as endangered
under the ESA and expects to make a final determination on the listing by June 2012. Some of the Company's
operations in the Permian Basin are located in or near areas that may potentially be designated as Dunes
Sagebrush Lizard habitat. If the lizard is classified as an endangered species, the Company's operations in any area
that is designated as the lizard's habitat may be limited, delayed or, in some circumstances, prohibited, and the
Company may be required to comply with expensive mitigation measures intended to protect the lizard and its
habitat. 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 under the ESA and issue decisions with respect to the 250 candidate species over the next several years.
The designation of previously unprotected species in areas where the Company operates as threatened or endangered
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 reserves.

Health and safety. The Company's operations are subject to the requirements of the federal Occupational
Safety and Health Act (the "OSH Act") and comparable state statutes. These laws and the related regulations strictly
govern the protection of the health and safety of employees. The OSH Act 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 Company's operations. The
Company believes that it is in substantial compliance with these applicable requirements and with other OSH Act
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," or "GHGs," present an endangerment to public

PIONEER NATURAL RESOURCES COMPANY

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. These findings by the EPA allow the agency to proceed with the
adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the
CAA. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of
GHGs under existing provisions of the CAA. The EPA adopted two sets of rules that regulate greenhouse gas
emissions under the CAA, one of which requires a reduction in emissions of GHGs from motor vehicles and the
other of which regulates emissions of GHGs from certain large stationary sources. The EPA has also adopted rules
requiring the reporting, on an annual basis, of greenhouse gas emissions from specified greenhouse gas emission
sources in the United States, including petroleum refineries, as well as certain oil and gas production facilities. The
Company is monitoring GHG emissions from its operations in accordance with the GHG emissions reporting rule
and believes its monitoring activities are in substantial compliance with applicable reporting obligations.

In addition, the United States Congress has from time to time considered adopting legislation to reduce
emissions of GHGs and almost one-half of the states have already taken legal measures to reduce emissions of
GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade
programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric
power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender
emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve
the overall GHG emission reduction goal.

The adoption of legislation or regulatory programs to reduce emissions of GHGs could require the Company
to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire
emissions allowances or comply with new regulatory or reporting requirements. 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. It should be noted that 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 events. If any such effects were to occur, they could
have an adverse effect on the Company's financial condition and results of operations.

Finally, other nations have been seeking to reduce emissions of GHGs pursuant to the United Nations
Framework Convention on Climate Change, also known as the "Kyoto Protocol," an international treaty pursuant to
which participating countries (not including the United States) have agreed to reduce their emissions of GHGs.
Depending on the particular jurisdiction in which the Company's operations are located, it could be required to
purchase and surrender allowances for GHG emissions resulting from the Company's operations.

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 instance, the
Company did not incur any material capital expenditures for remediation or pollution control activities for the year
ended December 31, 2011. Additionally, the Company is not aware of any environmental issues or claims that will
require material capital expenditures during 2012. However, 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.

Other regulation of the oil and gas industry. The oil and gas industry is regulated by numerous foreign,
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, state and foreign
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 foreign, federal, state and local levels. These types of regulation include requiring permits for the

PIONEER NATURAL RESOURCES COMPANY

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.

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. Foreign, 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, including the Railroad Commission of Texas (the "TRRC"). 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"). Since 1985, FERC has endeavored to make gas transportation more accessible to gas buyers
and sellers on an open 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 for violations of the NGA up to $1.0 million per day per violation.
The anti-manipulation rule applies to activities of otherwise non-jurisdictional entities 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 rules ("Order 704") requiring that 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 during a calendar year annually report such sales and purchases to FERC. 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.

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

PIONEER NATURAL RESOURCES COMPANY

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
impacted by the rates charged by such third parties for gathering services. To the extent that changes in foreign,
federal and/or state regulation affect the rates charged for gathering services, the Company also may be affected by
such 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 availability, terms and cost of transportation
significantly affect sales of oil and NGLs. Foreign, federal and state regulations govern the price and terms for
access to pipeline transportation of oil and NGLs. Intrastate pipeline transportation activities are subject to various
state laws and regulations, as well as orders of state regulatory bodies, including the TRRC. Interstate common
carrier pipeline operations are subject to rate regulation by FERC under the Interstate Commerce Act (the "ICA").
The ICA requires that tariff rates for petroleum pipelines, which include both oil pipelines and refined products
pipelines, be just and reasonable and non-discriminatory.

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 United States
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 United States 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.

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 Pioneer'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;

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overall domestic and global political and economic conditions;
actions of OPEC and other state-controlled oil companies relating to oil price and production controls;

PIONEER NATURAL RESOURCES COMPANY

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the effect of LNG deliveries to 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 2011, oil prices fluctuated from a high of $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. During 2010, oil prices fluctuated from a low of $68.01 per Bbl in May to a high of $91.51 per Bbl in
December, while gas prices fluctuated from a high of $6.01 per Mcf in January to a low of $3.29 per Mcf in
October. 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.

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 statement of operations each quarter, which may
result in significant 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

PIONEER NATURAL RESOURCES COMPANY

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 2012.

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 estimated fair
value. For example, during 2011 and 2009, the Company recognized impairment charges of $354.4 million and
$21.1 million, respectively, due to the impairment of the Company's Edwards and Austin Chalk gas fields in South
Texas and the Uinta/Piceance area in Colorado, 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.

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, 2011, the Company carried unproved property costs of $235.5 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,
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 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.

PIONEER NATURAL RESOURCES COMPANY

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 impact 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 may be unable to dispose of nonstrategic assets on attractive terms, and may be required to retain
liabilities for certain matters.

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 nonstrategic
assets or complete announced dispositions, including the availability of purchasers willing to purchase the
nonstrategic assets at prices acceptable to the Company. 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 sale, 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 periodically evaluates its goodwill for impairment and could be required to recognize noncash
charges in the earnings of future periods.

At December 31, 2011, the Company carried goodwill of $298.1 million associated with its United States
reporting unit. 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 related
to the Company's United States reporting unit. 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's gas processing operations are subject to operational risks, which could result in significant
damages and the loss of revenue.

As of December 31, 2011, the Company owned interests in four gas processing plants and ten treating
facilities. The Company operates 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.

PIONEER NATURAL RESOURCES COMPANY

The Company's operations involve many operational risks, some of which could result in substantial losses to the
Company and unforeseen interruptions to the Company's operations 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 ruptures and discharges of toxic gases, brine, well
stimulation and completion fluids or other pollutants in to the surface and subsurface environment;
high costs, shortages or delivery delays of equipment, labor or other services;
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. The Company's ability to drill and develop these
locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory
approvals, negotiation of agreements with third parties, commodity prices, costs, access to and availability of
equipment, services and personnel and drilling results. Because of these uncertainties, the Company cannot give any
assurance as to the timing of these activities or that they will ultimately result in the realization of proved reserves or
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, gas gathering, transportation, storage and processing
facilities to market its oil, NGL and gas production.

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 and refining
facilities, as well as the existence of adequate markets. If there were insufficient capacity available on these systems,
or if these systems were unavailable to the Company, 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 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

PIONEER NATURAL RESOURCES COMPANY

provide sufficient transportation, storage or processing facilities to the Company, especially in areas of planned
expansion where such facilities do not currently exist.

The nature of the Company's assets and operations exposes it to significant costs and liabilities with respect to
environmental and operational 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 and ruptures and
discharges of substances or gases that could expose the Company to substantial liability due to pollution and other
environmental damage. A variety of United States federal, state and local, as well as foreign 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 matters and regulations" above for additional discussion
related to environmental risks.

No assurance can be given that existing or future environmental laws 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. Pollution and
similar environmental risks generally are not fully insurable.

The Company's credit facility 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, senior convertible notes and a credit facility. The
terms of the Company's borrowings under the senior notes, senior convertible notes and the credit facility 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 E 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, 2011 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;

•
• marketing oil, NGL and gas production; and
•

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, local and foreign laws and regulations. For
instance, the TCEQ recently adopted rules establishing new air emissions limitations and permitting requirements
for oil and gas activities in the Barnett Shale area, which may increase the cost and time associated with drilling
wells in that area. In addition, 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

PIONEER NATURAL RESOURCES COMPANY

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 and NGLs, and any derivative activities related to such energy commodities,
expose the Company to potential regulatory risks.

FERC, the Federal Trade Commission and the Commodity Futures Trading Commission (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 and NGLs, 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 financial condition or results of
operations.

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.

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:

•
•
•
•
•
•

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:

•
•
•
•

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:

•
•
•
•

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.

PIONEER NATURAL RESOURCES COMPANY

The Company reports all proved reserves held under concessions utilizing the "economic interest" method,
which excludes the host country's share of proved reserves. Estimated quantities reported under the "economic
interest" method are subject to fluctuations in commodity prices and recoverable operating expenses and capital
costs. If costs remain stable, reserve quantities attributable to recovery of costs will change inversely to changes in
commodity prices.

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.
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% limited partner interest and a 0.1% 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 United States 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

PIONEER NATURAL RESOURCES COMPANY

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 was 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 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 markets, the availability of credit and the equity markets have improved during 2010 and
2011, the economic outlook for 2012 remains uncertain. 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 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
United States 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 the Eurozone 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.

PIONEER NATURAL RESOURCES COMPANY

Certain United States 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
United States tax laws, including elimination of certain key United States 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 United States 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.

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

During 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 two sets of rules that regulate greenhouse gas emissions under the CAA, one of which requires a reduction
in emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large
stationary sources. The EPA has also adopted rules requiring the reporting, on an annual basis, of greenhouse gas
emissions from specified greenhouse gas emission sources in the United States, including petroleum refineries as
well as certain oil and gas production facilities. The Company is monitoring GHG emissions from its operations in
accordance with the GHG emissions reporting rule and believes that its monitoring activities are in substantial
compliance with applicable reporting obligations.

The adoption of legislation or regulatory programs to reduce emissions of GHGs could require the Company
to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire
emissions allowances or comply with new regulatory or reporting requirements. 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. Finally, it should be noted that 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 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."

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

The United States Congress recently adopted comprehensive financial reform legislation that establishes
federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Company, that
participate in that market. The legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection
Act (the "Act"), was signed into law by the President in July 2010 and requires the CFTC and the SEC to
promulgate rules and regulations to implement the new legislation. In December 2011, the CFTC extended
temporary exemptive relief from certain regulations applicable to swaps until no later than July 16, 2012. In its

PIONEER NATURAL RESOURCES COMPANY

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. It is not possible at this time to predict when the
CFTC will make these regulations effective. The financial reform legislation may also require the Company to
comply with margin requirements and with certain clearing and trade-execution requirements in connection with its
derivatives activities, although the application of those provisions to the Company is uncertain at this time. The
financial reform legislation may also require the counterparties to the Company's derivative instruments to spin off
some of their derivatives activities to a separate entity, which may not be as creditworthy as the current
counterparty. The legislation 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 legislation and regulations, the Company's results of operations may become more volatile and its
cash flows may be less predictable, which could adversely affect the Company's ability to plan for and fund capital
expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and 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 legislation and regulations is to
lower commodity prices. Any of these consequences could have a material, adverse effect on the Company, its
financial condition and its results of operations.

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

Hydraulic fracturing is an important and common practice that is used to stimulate production of
hydrocarbons from tight formations. The Company routinely utilizes hydraulic fracturing techniques in many of its
drilling and completion programs. The process involves the injection of water, sand and chemicals under pressure
into rock formations to stimulate oil and gas production. The process is typically regulated by state oil and gas
commissions. The EPA, however, recently asserted federal regulatory authority over hydraulic fracturing involving
diesels under the SDWA's Underground Injection Control Program. Moreover, the EPA issued proposed rules in
July 2011 that would subject oil and gas production activities to regulation under the NSPS air emissions program,
including, among other things, the implementation of standards for reduced emission completion techniques to be
used during hydraulic fracturing activities. In addition, legislation has been introduced before the United States
Congress to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the
chemicals used in the fracturing process. At the state level, several states have adopted or are considering legal
requirements that could impose more stringent permitting, disclosure and well construction requirements on
hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state or local legal restrictions relating
to the hydraulic fracturing process are adopted in areas where the Company operates, it could incur potentially
significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of
exploration, development or production activities, and perhaps even be precluded from drilling wells.

In addition, certain governmental reviews are either underway or being proposed 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 a committee of the United States House of
Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study
of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results
expected to be available by late 2012 and final results 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 ongoing or
proposed 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.

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

PIONEER NATURAL RESOURCES COMPANY

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 impact 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 strategy is to expand drilling activity in areas in which industry activity has increased rapidly,
particularly in the Spraberry field area, the Eagle Ford Shale play in South Texas and the Barnett Shale Combo play
in North Texas. As a result, demand for personnel, equipment, hydraulic fracturing services, proppant for fracture
stimulation operations, water and other services and resources, as well as access to transportation, processing and
refining facilities in these areas has increased, as has the costs for those items. A delay or inability to secure the
personnel, equipment, services, resources and facilities access necessary for the Company to complete its
development activities as planned could result in a rate of oil and gas production below the rate forecasted, and
significant increases in costs would impact 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 state and federal 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 United States 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 substances or
other regulated materials, and may seek damages and, in some cases, criminal penalties. The United States Fish and
Wildlife Service has proposed listing the Dunes Sagebrush Lizard as endangered under the ESA and expects to
make a final determination on the listing by June 2012. Some of the Company's operations in the Permian Basin are
located in or near areas that may potentially be designated as Dunes Sagebrush Lizard habitat. If the lizard is
classified as an endangered species, the Company's operations in any area that is designated as the lizard's habitat
may be limited, delayed or, in some circumstances, prohibited, and the Company may be required to comply with
expensive mitigation measures intended to protect the lizard and its habitat.

ITEM 1B. UNRESOLVED STAFF COMMENTS

As of December 31, 2011, the Company did not have any SEC staff comments that have been unresolved

for more than 180 days.

ITEM 2.

PROPERTIES

Reserve Rule Changes

During 2009, the SEC issued its final rule on the modernization of oil and gas reporting (the "Reserve
Ruling") and, during 2010, the Financial Accounting Standards Board (the "FASB") issued Accounting Standards
Update No. 2010-03 ("ASU 2010-03") "Extractive Industries – Oil and Gas," which aligned the estimation and
disclosure requirements of FASB Accounting Standards Codification Topic 932 with the Reserve Ruling. The
Reserve Ruling and ASU 2010-03 became effective for Annual Reports on Form 10-K for fiscal years ending on or
after December 31, 2009. The key provisions of the Reserve Ruling and ASU 2010-03 are as follows:

Expanding the definition of oil- and gas-producing activities to include the extraction of saleable hydrocarbons,
in the solid, liquid or gaseous state, from oil sands, coalbeds or other nonrenewable natural resources that are
intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction;

PIONEER NATURAL RESOURCES COMPANY

Amending the definition of proved oil and gas reserves to require the use of an average of the first-day-of-the-
month commodity prices during the 12-month period ending on the balance sheet date rather than period-end
commodity prices;

Adding to and amending other definitions used in estimating proved oil and gas reserves, such as "reliable

technology" and "reasonable certainty;"

Broadening the types of technology that a reporter may use to establish reserves estimates and categories; and
Changing disclosure requirements and providing formats for tabular reserve disclosures.

Reserve Estimation Procedures and Audits

The information included in this Report about the Company's proved reserves as of December 31, 2011, 2010
and 2009, which were located in the United States, South Africa and Tunisia, is based on evaluations prepared by (i)
the Company's engineers and audited by Netherland, Sewell & Associates, Inc. ("NSAI"), with respect to the
Company's major properties, and (ii) the Company's engineers, with respect to all other properties. 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 Notes B and U 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, which owned the Company's Tunisia proved
reserves.

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.

The management of Pioneer's oil and gas assets is decentralized geographically by individual asset teams who
are responsible for the oil and gas activities in each of the Company's Permian Basin, Rockies, Mid-Continent, South
Texas - Eagle Ford Shale, South Texas - Edwards, Barnett Shale, Alaska and Africa asset teams (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 Chief
Operating Officer ("COO") and management committee ("MC"). The Company's MC is comprised of its Chief
Executive Officer, COO, 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 by 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 NSAI (for the portion of the reserves audited by NSAI) 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 on the Reserve Ruling 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 in the aggregate represented 90
percent, 90 percent and 93 percent of the Company's 2011, 2010 and 2009 proved reserves, respectively; and, 91
percent, 79 percent and 86 percent of the Company's 2011, 2010 and 2009 associated pre-tax present value of proved
reserves discounted at ten percent, respectively.

NSAI follows 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:

PIONEER NATURAL RESOURCES COMPANY

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 its external and internal engineering and geoscience technical
data and analyses. Following NSAI's review of that data, it had the option of honoring Pioneer's interpretation, or
making its own interpretation. No data was withheld from NSAI. NSAI 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 its evaluation something came to its attention that brought into question the validity or sufficiency of any
such information or data, NSAI did not rely on such information or data until it had satisfactorily resolved its
questions relating thereto or had independently verified such information or data.

In the course of its evaluations, NSAI prepared, for all of the audited properties, its own estimates of the
Company's proved reserves and the pre-tax present value of such reserves discounted at ten percent. NSAI reviewed
its audit differences with the Company, and, in a number of cases, held joint meetings with the Company to review
additional reserves work performed by the 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.
NSAI's 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 NSAI and some were less than the estimates of NSAI. When
such differences do not exceed ten percent in the aggregate and NSAI is satisfied that the proved reserves and pre-tax
present value of such reserves discounted at ten percent are reasonable and that its audit objectives have been met,
NSAI 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 NSAI. At the conclusion of the audit process, it was NSAI's
opinion, as set forth in its audit letter, which is included as an exhibit to this Report, that Pioneer's estimates of the
Company's proved oil and gas reserves and associated pre-tax present value 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 34 years
of experience as a petroleum engineer, with 27 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 ("CFA") and a member of the Oil and Gas Reserves Committee of the SPE.

PIONEER NATURAL RESOURCES COMPANY

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 33 years of practical experience in petroleum engineering, including 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.

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 is 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 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

The Company's proved reserves totaled 1,063 MMBOE, 1,011 MMBOE and 899 MMBOE at December 31,
2011, 2010 and 2009, respectively, representing $7.8 billion, $5.4 billion and $3.3 billion, respectively, of
Standardized Measure. The Company's proved reserves include field fuel, which is gas consumed to operate field
equipment (primarily compressors) prior to the gas being delivered to a sales point.

The following table shows the changes in the Company's proved reserve volumes by geographic area during

the year ended December 31, 2011 (in MBOE):

Production

Extensions and
Discoveries

Improved
Recovery

Purchases of
Minerals-in-
Place

Sales of
Minerals-in-
Place

Revisions of
Previous
Estimates

United States .........................
South Africa ..........................
Tunisia ..................................
Total ......................................

(46,907)
(1,445)
(230)
(48,582)

155,728
585
-
156,313

1,394
-
-
1,394

4,435
-
-
4,435

-
-
(23,447)
(23,447)

(38,328)
315
-
(38,013)

Production. Production volumes include 2,954 MBOE of field fuel.

Extensions and discoveries. Extensions and discoveries are primarily comprised of extensions in the Spraberry

field and discoveries in the Eagle Ford Shale and Barnett Shale Combo plays.

Improved recovery. Additions from improved recovery relate to recognizing secondary recovery reserves

attributable to waterflooding the Nuiqsut horizon of the Alaskan Oooguruk development project.

Purchases of minerals-in-place. Purchases of minerals-in-place are primarily attributable to acquisitions in

the Company's Spraberry field.

PIONEER NATURAL RESOURCES COMPANY

Sales of minerals-in-place. Sales of minerals-in-place are related to the divestment of Pioneer Tunisia. See
Notes M and U of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data."

Revisions of previous estimates. Revisions of previous estimates are comprised of 28 MMBOE of negative
price revisions and 10 MMBOE of negative revisions due to updated performance profiles and cost estimates. The
Company's proved reserves at December 31, 2011 were determined using an average of the NYMEX spot prices for
sales of oil and gas on the first calendar day of each month during 2011. On this basis, the NYMEX price for oil and
gas for proved reserve reporting purposes at December 31, 2011 was $96.13 per barrel of oil and $4.12 per Mcf of
gas, compared to the comparable average NYMEX prices of $79.28 per barrel of oil and $4.37 per Mcf of gas at
December 31, 2010.

Tabular proved reserves disclosures. On a BOE basis, 58 percent of the Company's total proved reserves at

December 31, 2011 were proved developed reserves.

The following table provides information regarding the Company's proved reserves and standardized measure

by geographic area as of and for the year ended December 31, 2011:

Summary of Oil and Gas Reserves as of December 31, 2011
Based on Average Fiscal Year Prices
NGLs
(MBbls)

(MMcf) (a) MBOE

Standardized
Measure

Gas

Oil
(MBbls)

Developed:
United States .........................................................
South Africa ..........................................................

Undeveloped:
United States .........................................................

189,975
231
190,206

120,405
-
120,405

1,840,697
12,666
1,853,363

617,164 $
2,342
619,506

5,453,321
40,686
5,494,007

239,799

90,630

677,675

443,375

2,319,016

(in thousands)

Total Proved .............................................................
___________
(a) The gas reserves contain 301,123 MMcf of gas that will be produced and utilized as field fuel.

2,531,038

430,005

211,035

1,062,881 $

7,813,023

Proved undeveloped reserves. The following table summarizes the Company's proved undeveloped

reserves activity during the year ended December 31, 2011 (in MBOE):

Beginning proved undeveloped reserves .........................................................................................................................
Extensions and discoveries ..........................................................................................................................................
Purchases of minerals-in-place ....................................................................................................................................
Improved recovery .......................................................................................................................................................
Revisions of previous estimates ...................................................................................................................................
Transfers to proved developed .....................................................................................................................................
Sales of minerals-in-place ............................................................................................................................................

433,244
103,224
4,345
1,274
(28,582)
(62,436)
(7,694)

Ending proved undeveloped reserves...............................................................................................................................

443,375

As of December 31, 2011, the Company had 4,599 proved undeveloped well locations (all of which are
expected to be developed during the five year period ending December 31, 2016), as compared to 4,727 and 4,582 at
December 31, 2010 and 2009, respectively. The changes in proved undeveloped reserves during 2011 are comprised
of the following items:

Extensions and discoveries. Extensions and discoveries are primarily comprised of extensions in the Spraberry

field and discoveries in the Eagle Ford Shale and Barnett Shale Combo plays.

Purchases of minerals-in-place. Purchases of minerals-in-place are primarily attributable to acquisitions in the

Company's Spraberry field.

PIONEER NATURAL RESOURCES COMPANY

Improved recovery. Additions from improved recovery relate to recognizing secondary recovery reserves

attributable to waterflooding the Nuiqsut horizon of the Alaskan Oooguruk development project.

Revisions of previous estimates. Revisions of previous estimates are comprised of 34 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 5 MMBOE of positive technical revisions, primarily in the Spraberry field.

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 2011.

Sales of minerals-in-place. Sales of minerals-in-place are primarily related to the divestment of Pioneer

Tunisia.

During 2011, the Company added approximately 32 MMBOE of proved undeveloped reserves for locations
that are more than one location removed from developed locations in the Spraberry field. 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 our internal core analysis facility. After the geologic area was shown to be continuous,
statistical analysis of existing producing wells was conducted to generate area of reasonable certainty at distances
from established production. As a result of this analysis, proved undeveloped reserves for drilling locations within
this area of reasonable certainty were recorded during 2011.

The Company's proved undeveloped reserves and well locations that have remained undeveloped for five
years or more decreased during the year ended December 31, 2011 by 38 percent and 42 percent, respectively, to 80
MMBOE of proved undeveloped reserves and 858 well locations compared to 130 MMBOE and 1,467 locations at
year end 2010. The Company's inventory of proved undeveloped reserves and well locations that have remained
undeveloped for five years or more is decreasing as a result of the Company's annual increases in its capital
expenditures since 2009. The Company's proved undeveloped reserves and well locations that have remained
undeveloped for five years or more are all located in the Spraberry field where approximately 70 percent of the
Company's $2.5 billion capital budget for 2012 is expected to be spent.

Based on management's commodity price outlook, the Company expects that future operating cash flows will
provide adequate funding for future development of its proved undeveloped reserves within the next five years. The
following table represents the estimated timing and cash flows of developing the Company's proved undeveloped
reserves as of December 31, 2011 (dollars in thousands):

Year Ended December 31, (a)

2012 ........................................................
2013 ........................................................
2014 ........................................................
2015 ........................................................
2016 ........................................................
Thereafter (b) ...........................................

Estimated
Future
Production
(MBOE)

Future Cash
Inflows

Future
Production
Costs

Future
Development
Costs

Future Net
Cash Flows

5,193 $

385,942 $

15,707
23,504
29,475
33,783
335,713
443,375 $ 29,051,490 $

1,118,140
1,609,820
1,997,551
2,229,206
21,710,831

55,517 $
160,479
251,653
336,961
411,086
6,501,238
7,716,934 $

1,152,395 $
1,488,576
1,577,529
1,546,016
1,466,408
321,791

(821,970)
(530,915)
(219,362)
114,574
351,712
14,887,802
7,552,715 $ 13,781,841

___________
(a) Production and cash flows represent the drilling results from the respective year plus the incremental effects of proved

(b)

undeveloped drilling.
The $321.8 million of future development costs includes (i) $125.3 million of completion costs forecasted in 2017 and (ii)
$196.5 million of net abandonment costs in future years.

PIONEER NATURAL RESOURCES COMPANY

Description of Properties

United States

Approximately 83 percent of the Company's proved reserves at December 31, 2011 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, Raton field, Eagle Ford
Shale play, Barnett Shale Combo play and Alaska.

The following tables summarize the Company's United States development and exploration/extension drilling

activities during 2011:

Development Drilling

Beginning
Wells In
Progress

Wells Spud

Successful
Wells

Unsuccessful
Wells

Ending Wells
In Progress

Permian Basin ...............................................
Mid-Continent ..............................................
Raton Basin...................................................
South Texas - Edwards and Austin Chalk .....
Alaska ...........................................................
Total United States .......................................

144
-
-
1
1
146

696
2
57
1
1
757

668
2
52
2
1
725

11
-
-
-
-
11

161
-
5
-
1
167

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 ....................
South Texas - Edwards and Austin Chalk .....
Barnett Shale .................................................
Alaska ...........................................................
Total United States .......................................

3
-
22
2
11
-
38

24
5
111
1
59
1
201

27
-
94
2
44
-
167

-
-
-
1
-
-
1

-
5
39
-
26
1
71

The following table summarizes the Company's United States average daily oil, NGL, gas and total

production by asset area during 2011:

Oil (Bbls)

NGLs (Bbls) Gas (Mcf) (a) Total (BOE)

Permian Basin ........................................................................
Mid-Continent .......................................................................
Raton Basin.............................................................................
Barnett Shale ...........................................................................
South Texas - Eagle Ford Shale ..............................................
South Texas - Edwards and Austin Chalk ...............................
Alaska ....................................................................................
Other .......................................................................................
Total United States .................................................................
__________
(a)

Gas production excludes gas produced and utilized as field fuel.

27,514
3,593
-
598
4,383
93
4,432
5
40,618

11,027
7,107
-
1,369
2,982
1
-
1
22,487

47,600
51,291
160,550
11,013
28,020
45,324
-
81
343,879

46,475
19,249
26,758
3,803
12,035
7,648
4,432
18
120,418

PIONEER NATURAL RESOURCES COMPANY

The following table summarizes the Company's United States costs incurred by geographic area during 2011:

Property
Acquisition Costs
Proved

Unproved Costs

Exploration Development

Asset
Retirement
Obligations

Total

Costs
(in thousands)

7,252 $
14
210
-
-
69
20
-

30,954 $
9,955
25
26,263
1,707
44,006
32
11,384
7,565 $ 124,326 $

7,112
7,401
136,985
13,628
258,446
32,140
4,784

98,318 $ 1,254,454
15,710
58,107
4,793
10,881
14,421
90,120 (a)
-
558,814 $ 1,448,486

3,902 $ 1,394,880
34,588
1,797
65,045
(698)
174,000
5,959
32,455
6,239
319,984
3,042
125,631
3,319
15,712
(456)
23,104 $ 2,162,295

Permian Basin ............................................. $
Mid-Continent ............................................
Raton Basin.................................................
South Texas - Eagle Ford Shale ..................
South Texas - Edwards and Austin Chalk ...
Barnett Shale ...............................................
Alaska .........................................................
Other ...........................................................
Total United States ..................................... $
___________
(a)

Includes $13.4 million of capitalized interest related to the Oooguruk 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 ability to improve incremental recovery rates through infill and deeper formation drilling,
waterflood projects and horizontal drilling in certain formations; and the ability to contain operating expenses and
drilling costs through economies of scale and vertical integration of field services.

During 2011, the Company drilled 706 wells in the Spraberry field and its total acreage position now
approximates 820,000 gross acres (691,000 net acres). For 2012, the Company plans to drill approximately 750
vertical wells. The Company currently has 44 rigs operating, of which 41 are drilling vertical wells and three are
drilling horizontal wells, but plans to reduce its vertical rig count to approximately 30 rigs by year-end 2012 and
increase its horizontal Wolfcamp Shale rig count to seven by year end. In approximately 50 percent of the planned
750 well vertical drilling program, the Wolfcamp interval will be the deepest interval completed. Of the remaining
50 percent of the wells, 20 percent are planned to be deepened to the Strawn interval, 20 percent to the Atoka
interval and 10 percent to the Mississippian interval.

The Company recently completed its second successful horizontal well in the Upper/Middle Wolfcamp Shale
in Upton County, Texas with a 30-stage fracture stimulation in a 5,800-foot lateral section. This well is performing
similarly to the Company's first horizontal well in the area. The first horizontal well has produced over 45 MBOE in
its first 90 days of production, which is approximately seven times the production from a typical Spraberry vertical
well over the same time period. These wells continue to flow naturally and are producing to sales.

Based on this successful drilling activity and Pioneer's extensive geologic interpretation of the Upper/Middle
Wolfcamp Shale, the Company believes it has significant horizontal potential within its acreage. Pioneer is the
largest acreage holder in the play with more than 400,000 prospective acres.

The Company is currently focusing its horizontal efforts on more than 200,000 acres in the southern part of
the field to hold acreage that would otherwise expire by year-end 2013. Current plans call for drilling 80 to 90
horizontal wells in this area by the end of 2013, with 30 to 35 horizontal wells expected to be drilled in 2012.

PIONEER NATURAL RESOURCES COMPANY

The Company continues to test downspacing in the Spraberry field from 40 acres to 20 acres. Sixteen 20-acre
wells were drilled in 2011, with 10 of these wells having been placed on production. These 20-acre wells were
mostly drilled to the Lower Wolfcamp interval, with a few deepened to the Strawn interval. The Company plans to
drill approximately 50 additional 20-acre downspaced wells during 2012.

The Company continues to expand its integrated services to control drilling costs and support the execution of
its accelerating drilling program. The Company has increased its owned drilling rigs to 15 and has five Company-
owned fracture stimulation fleets totaling 100,000 horsepower currently operating in the Spraberry field supporting
vertical drilling operations. Two additional fleets totaling 70,000 horsepower will be added by mid-year 2012 to
support Pioneer's horizontal drilling program in the Wolfcamp Shale. To support its growing operations, the
Company also owns other field service equipment, including pulling units, fracture stimulation tanks, water
transport trucks, hot oilers, blowout preventers, construction equipment and fishing tools. In addition, the Company
has contracted for tubular and pumping unit requirements through 2012 and well cementing services through 2016.

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 approximately 284,000 gross acres
(245,000 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 680 wells on more than 259,000 gross acres (252,000 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

The Raton Basin properties are located in the southeast portion of Colorado. The Company owns
approximately 227,000 gross acres (201,000 net acres) in the center of the Raton Basin and produces CBM gas from
the coal seams in the Vermejo and Raton 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 2011 were primarily focused on delineation
and development of Pioneer's substantial acreage position in the Eagle Ford Shale play. The Company drilled 94
horizontal Eagle Ford Shale wells during 2011, with average lateral lengths of approximately 5,500 feet and 13-
stage fracture stimulations. The Company plans to utilize 12 rigs in 2012 and drill approximately 125 wells. The
2012 drilling program will continue to focus on liquids-rich drilling, with only 15 percent of the wells designated to
hold strategic dry gas acreage.

To improve the execution of its drilling and completions program in 2012 and reduce costs, the Company will
operate two Company-owned fracture stimulation fleets totaling 100,000 horsepower. One fleet was placed in
service in April 2011 and the other is expected to be operational during the first quarter of 2012. The Company is

PIONEER NATURAL RESOURCES COMPANY

also utilizing a dedicated third-party fracture stimulation fleet, which commenced operating in April 2011 under a
two-year contract.

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. Early well performance has been similar to direct offset
ceramic-stimulated wells. The Company plans to continue to monitor the performance of these wells and plans to
use white sand in 50 percent of its 2012 drilling program.

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,
including normal closing adjustments. The terms of the transaction also provided that the purchaser will pay 75
percent (up to $886.8 million) of the Company's defined exploration, drilling and completion costs attributable to the
Eagle Ford Shale assets during the six years ending on July 1, 2016, subject to extension. As of December 31, 2011,
$398.2 million of the carry obligation had been paid by the purchaser and the Company expects that the purchaser's
obligation will be satisfied by the end of 2012. 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 gathering facilities in the
Eagle Ford Shale area, 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 2013. Eight of the
12 planned central gathering plants ("CGPs") were completed as of December 31, 2011. EFS Midstream plans to
build three additional CGPs in 2012. As construction of CGPs is completed, EFS Midstream will provide gathering,
treating and transportation services for the Company during a 20-year contractual term. The Company has invested
$169.5 million of capital in EFS Midstream, $97.5 million of which was contributed during 2011. During June
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

During 2011, the Company continued to increase its acreage position in the liquid-rich Barnett Shale Combo
area in North Texas. In total, the Company has accumulated approximately 92,000 gross acres in the liquid-rich
area of the field and has acquired approximately 340 square miles of proprietary 3-D seismic covering its acreage.
The Company's total lease holdings in the Barnett Shale play now approximate 142,000 gross acres (108,000 net
acres).

During 2011, the Company had two drilling rigs operating and drilled 44 Barnett Shale Combo wells.
Pioneer plans to utilize two rigs during 2012 and is utilizing the 3-D seismic to high-grade its drilling location
selections. The Company also commenced operating a Company-owned fracture stimulation fleet in the area during
the second quarter of 2011.

Alaska

The Company owns a 70 percent working interest and is the operator of the Oooguruk development project.
The Company has drilled 12 production wells and eight injection wells of the estimated 17 production and 16
injection wells planned to fully develop this project. The Company's winter drilling program calls for two
exploration wells ("Nuna #1" and "Sikumi #1") to be drilled during the first quarter of 2012. The Nuna #1 well will
be drilled from an onshore location to further evaluate the productivity of the Torok formation and the feasibility of
future development expansion to the south. The Sikumi #1 well will be drilled from an ice pad on the west side of
the Oooguruk unit to test the deeper Ivishak zone, which is the main producing horizon in the Prudhoe Bay field.

International

During 2011, the Company's international operations were located in Tunisia and offshore South Africa.
During February 2011, the Company completed the sale of the Company's share holdings in Pioneer Tunisia to an
unaffiliated third party. During December 2011, the Company committed to a plan to divest Pioneer South Africa
during 2012. See Notes B and U of Notes to Consolidated Financial Statements included in "Item 8. Financial

PIONEER NATURAL RESOURCES COMPANY

Statements and Supplementary Data" for information regarding the sale of Pioneer Tunisia and the planned sale of
Pioneer South Africa.

Selected Oil and Gas Information

The following tables set forth selected oil and gas information from continuing operations for the Company
as of and for each of the years ended December 31, 2011, 2010 and 2009. 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 produced is largely
a function of market supply and demand. Demand is impacted 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
2011, 2010 and 2009. 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 agree to the reserve volume tables in the "Unaudited Supplementary Information"
section included in "Item 8. Financial Statements and Supplementary Data" due to field fuel volumes being included
in the reserve volume tables.

PIONEER NATURAL RESOURCES COMPANY

PRODUCTION, PRICE AND COST DATA

Year Ended December 31, 2011

United States

Spraberry
Field

Raton
Field

Total

South
Africa

Tunisia

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):
Oil (per Bbl) .............................................................. $
NGL (per Bbl) ........................................................... $
Gas (per Mcf) ............................................................ $
Revenue (per BOE) ................................................... $
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 .......................................................................... $

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

-
-

14,825
8,208
58,601 125,516
43,953

9,767

193
-
7,508
1,445

201
-
181
229

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

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

-
-

40,618
22,487
160,550 343,879
26,758 120,418

530
-
20,570
3,958

547
-
496
630

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

95.93 $
42.38 $
3.44 $
71.37 $

- $
- $
3.81 $
22.86 $

96.60 $
46.27 $
3.84 $
52.19 $

108.14 $
- $
7.62 $
54.09 $

99.03 $
- $
13.04 $
96.29 $

91.44 $
42.38 $
3.44 $
68.65 $

- $
- $
3.81 $
22.86 $

91.35 $
46.27 $
3.84 $
50.42 $

108.14 $
- $
7.62 $
54.09 $

99.03 $
- $
13.04 $
96.29 $

10.40 $
-
(1.45)
1.74
10.69 $

6.49 $
3.01
2.15
-
11.65 $

8.09 $
1.26
0.15
0.82
10.32 $

2.35 $
-
-
-
2.35 $

7.61 $
1.91
-
( 0.27)
9.25 $

1.73 $
3.87
5.60 $

0.41 $
0.31
0.72 $

1.24 $
2.11
3.35 $

-
-
-

- $
-
- $

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

Depletion expense ...................................................... $
___________
(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, 2011, the Company had an obligation to deliver 1.3 million Bbls of oil under the
VPP obligation. See Notes H and S of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for more information about the Company's gathering, processing, transportation and fractionation
agreements and VPP obligation, respectively.

14.46 $

12.55 $

11.41 $

29.00

- $

13.01

PIONEER NATURAL RESOURCES COMPANY

PRODUCTION, PRICE AND COST DATA - (Continued)

Year Ended December 31, 2010

United States

Spraberry
Field

Raton
Field

Total

South
Africa

Tunisia

Total

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

-
-

10,297
7,203
62,311 122,369
37,895
10,385

225

-
10,862
2,035

1,781
-
1,040
1,954

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

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

-
-

28,211
19,736
170,716 335,256
28,453 103,823

616
-
29,760
5,576

4,880
-
2,849
5,355

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

91.53 $
33.11 $
3.41 $
60.40 $

- $
- $
4.20 $
25.19 $

90.56 $
38.14 $
4.18 $
45.34 $

78.07 $
- $
6.20 $
41.74 $

78.42 $
- $
11.25 $
77.46 $

88.57
38.14
4.40
46.67

77.24 $
33.11 $
3.41 $
53.14 $

- $
- $
4.20 $
25.19 $

74.21 $
37.12 $
4.15 $
40.61 $

78.07 $
- $
6.20 $
41.74 $

78.42 $
- $
11.25 $
77.46 $

74.89
37.12
4.37
42.39

11.40 $
-
(1.66)
1.88
11.62 $

6.11 $
2.35
1.93
0.07
10.46 $

7.74 $
0.87
0.08
0.92
9.61 $

0.68 $
-
-
-
0.68 $

4.98 $
1.50

0.36
6.84 $

2.30 $
3.53
5.83 $

0.46 $
0.52
0.98 $

1.49 $
1.47
2.96 $

- $
-
- $

7.28
0.86
0.08
0.85
9.07

1.35
1.33
2.68

14.39 $

12.40 $

36.50 $

12.07 $

9.02 $

13.56

activities at a field level.

PIONEER NATURAL RESOURCES COMPANY

PRODUCTION, PRICE AND COST DATA - (Continued)

Year Ended December 31, 2009

United States

Spraberry
Field

Raton
Field

Total

South
Africa

Tunisia

Total

5,836
3,454
15,313
11,842

-
-

9,113
7,183
67,991 128,753
37,756
11,332

137

-
9,321
1,690

2,384
-
609
2,485

11,634
7,183
138,683
41,931

15,989
9,461
41,954
32,443

-
-

24,968
19,680
186,278 352,749
31,046 103,440

375
-
25,538
4,631

6,531
-
1,668
6,809

31,874
19,680
379,955
114,880

73.12 $
25.91 $
2.84 $
47.27 $

- $
- $
3.26 $
19.59 $

75.60 $
29.76 $
3.88 $
37.15 $

65.94 $
- $
5.17 $
33.85 $

60.98 $
- $
8.14 $
60.49 $

72.49
29.76
3.99
38.40

56.25 $
25.91 $
2.84 $
38.96 $

- $
- $
3.26 $
19.59 $

55.04 $
28.45 $
3.32 $
30.02 $

65.94 $
- $
5.17 $
33.85 $

60.98 $
- $
8.14 $
60.49 $

56.38
28.45
3.47
31.98

10.47 $
-
(1.23)
1.30
10.54 $

5.14 $
2.39
1.79
0.10
9.42 $

7.39 $
0.95
0.27
0.55
9.16 $

3.26 $
-
-
-
3.26 $

7.38 $
1.69
-
2.58
11.65 $

2.10 $
2.72
4.82 $

0.39 $
0.12
0.51 $

1.51 $
1.10
2.61 $

- $
-
- $

7.22
0.96
0.25
0.65
9.08

1.36
0.99
2.35

18.19 $

14.20 $

38.33 $

8.69 $

8.77 $

14.85

activities at a field level.

PIONEER NATURAL RESOURCES COMPANY

Productive wells. The following table sets forth the number of productive oil and gas wells attributable to the

Company's properties as of December 31, 2011, 2010 and 2009:

PRODUCTIVE WELLS (a)

Gross Productive Wells
Gas

Total

Oil

Net Productive Wells
Gas

Oil

Total

6,111
-
6,111

5,533
-
33
5,566

5,332
-
29
5,361

5,268
6
5,274

4,836
6
-
4,842

5,021
6
-
5,027

11,379
6
11,385

10,369
6
33
10,408

10,353
6
29
10,388

5,525
-
5,525

4,769
-
10
4,779

4,566
-
9
4,575

4,502
3
4,505

4,347
3
-
4,350

4,604
3
-
4,607

10,027
3
10,030

9,116
3
10
9,129

9,170
3
9
9,182

As of December 31, 2011:
United States .................................
South Africa ..................................
Total ..............................................

As of December 31, 2010:
United States .................................
South Africa ..................................
Tunisia ..........................................
Total ..............................................

As of December 31, 2009:
United States .................................
South Africa ..................................
Tunisia ..........................................
Total ..............................................
__________
(a)

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. If any well in which one of the multiple completions is
an oil completion, then the well is classified as an oil well. As of December 31, 2011, the Company owned interests in
two gross wells containing multiple completions.

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

and royalty leasehold acreage as of December 31, 2011:

LEASEHOLD ACREAGE

Developed Acreage

Undeveloped Acreage

Gross Acres Net Acres

Royalty
Acreage

United States:
Onshore ......................................................
Offshore .....................................................

South Africa .................................................
Total .............................................................

1,603,656
-
1,603,656
119,579
1,723,235

1,348,040
-
1,348,040
53,281
1,401,321

1,459,058
-
1,459,058
3,508,421
4,967,479

964,537
-
964,537
1,578,789
2,543,326

302,316
5,000
307,316
-
307,316

PIONEER NATURAL RESOURCES COMPANY

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

acres as of December 31, 2011:

2012 (b) ....................................................................................................................................
2013 .........................................................................................................................................
2014 .........................................................................................................................................
2015 .........................................................................................................................................
2016 .........................................................................................................................................
Thereafter..................................................................................................................................
Total ..........................................................................................................................................
__________
(a) Acres expiring are based on contractual lease maturities.
(b) All acres subject to expiration during 2012 are in the United States. The Company may extend the leases prior to their
expiration based upon 2012 planned activities or for other business reasons. In certain leases, the extension is only subject to
the Company's election to extend and the fulfillment of certain capital expenditures commitments. In other cases, the
extensions are subject to the consent of third parties, and no assurance can be given that the requested extensions will be
granted. See "Description of Properties" above for information regarding the Company's drilling operations.

258,119
157,758
85,759
40,974
831,714
3,593,155
4,967,479

Gross

Acres Expiring (a)
Net
217,103
112,063
57,992
23,866
484,074
1,648,228
2,543,326

Drilling and other exploratory and development activities. The following table sets forth the number of
gross and net wells drilled by the Company during 2011, 2010 and 2009 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

Net Wells

Year Ended December 31,
2009
2010

2011

Year Ended December 31,
2009
2010

2011

United States:
Productive wells:

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

Dry holes:

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

Tunisia:
Productive wells:

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

Dry holes:

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

725
167

11
1
904

433
34

3
3
473

-
-

-
-
-

3
5

-
-
8

60
13

-
2
75

1
-

-
2
3

661
115

10
1
787

378
22

3
1
404

-
-

-
-
-

2
2

-
-
4

58
7

-
2
67

-
-

-
1
1

Total ........................................................................................

904

481

787

408

Success ratio (a) ......................................................................
__________
(a) Represents the ratio of those wells that were successfully completed as producing wells or wells capable of

95%

99%

96%

producing to total wells drilled and evaluated.

PIONEER NATURAL RESOURCES COMPANY

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

of being drilled as of December 31, 2011:

Gross Wells

Net Wells

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

167
71
238

153
49
202

ITEM 3.

LEGAL PROCEEDINGS

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

ITEM 4.

MINE SAFETY DISCLOSURES

Not applicable.

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 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, 2011 and 2010. 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, 2011 and 2010:

Year ended December 31, 2011
Fourth quarter ............................................................................................................ $
Third quarter .............................................................................................................. $
Second quarter ........................................................................................................... $
First quarter................................................................................................................ $
Year ended December 31, 2010
Fourth quarter ............................................................................................................ $
Third quarter .............................................................................................................. $
Second quarter ........................................................................................................... $
First quarter................................................................................................................ $

High

Low

Dividends
Declared
Per Share

97.10 $
99.64 $
106.07 $
104.29 $

88.00 $
67.77 $
74.00 $
56.88 $

58.63 $
65.73 $
82.41 $
85.90 $

64.97 $
54.89 $
54.72 $
41.88 $

-
0.04
-
0.04

On February 24, 2012, the last reported sales price of the Company's common stock, as reported in the NYSE

composite transactions, was $116.24 per share.

As of February 24, 2012, the Company's common stock was held by approximately 15,217 holders of record.

On February 23, 2012, the Board declared a cash dividend of $.04 per share on the Company's outstanding
common stock. The dividend is payable April 12, 2012 to stockholders of record at the close of business on March
30, 2012.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table summarizes the Company's purchases of treasury stock during the three months ended

December 31, 2011:

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

Average Price
Paid per Share

(or Unit)

Period

Total Number of Shares Approximate Dollar
Amount of Shares
that May Yet Be
Purchased under
Plans or Programs

(or Units) Purchased
as Part of Publicly
Announced Plans
or Programs

October 2011 ........................
November 2011 ....................
December 2011 .....................
Total .....................................
__________
(a) Consists of shares withheld to satisfy tax withholding on employees' share-based awards.

63 $
58 $
155 $
276 $

71.98
87.46
89.01
84.80

-
-
-
- $

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, 2011 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."

Year Ended December 31,

Statements of Operations Data:
Oil and gas revenues (a) .................................................................... $
Total revenues (b) ............................................................................. $
Total costs and expenses (c) ............................................................. $
Income (loss) from continuing operations ........................................ $
Income from discontinued operations, net of tax (d) ........................ $
Net income (loss) attributable to common stockholders ................... $
Income (loss) from continuing operations attributable
to common stockholders per share:
Basic ............................................................................................ $

2011

2010

2009
(in millions, except per share data)

2008

2007

2,294.1 $
2,786.6 $
2,130.2 $
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 $

1,507.2
1,533.1
1,299.3
162.2
210.2
372.7

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

3.39 $

3.96 $

(1.33) $

1.02 $

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

7.01 $

5.14 $

(0.46) $

1.76 $

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

6.88 $

5.08 $

(0.46) $

1.76 $

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

0.08 $

0.30 $

3.45 $

4.00 $

(1.33) $

1.02 $

1.30

3.05

3.04

0.27

Balance Sheet Data (as of December 31):
Total assets ...................................................................................... $ 11,524.2 $
4,861.2 $
Long-term obligations....................................................................... $
Total stockholders' equity ................................................................ $
5,651.1 $
__________
(a)

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 $

8,617.0
4,568.1
3,054.7

(b)

The Company's oil and gas revenues for 2011, as compared to those of 2010, increased by $575.8 million (or 34 percent) due to
increases in average oil and NGL sales prices and United States 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 $392.8 million of net derivative gains in its total revenues for 2011, including $225.5 million of
noncash MTM gains, as compared to $448.4 million of net derivative gains during 2010, including $364.4 million of noncash
MTM gains. See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" and Notes B and I 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 T 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 2011, the Company recorded an impairment charge of $354.4 million related to its Edwards and Austin Chalk net assets in
South Texas. During 2009 and 2008, the Company recorded impairment charges of $21.1 million and $89.8 million, respectively,
to its Uinta/Piceance net assets in Colorado. During 2007, the Company recorded charges of $10.2 million on Block 320 in
Nigeria, $10.3 million related to Block H in Equatorial Guinea and $5.7 million related to properties in the United States for a
total of $26.2 million. See Note R of Notes to the Consolidated Financial Statements included in "Item 8. Financial Statements
and Supplementary Data."

(d) During December 2011, the Company committed to a plan to divest Pioneer South Africa. In accordance with GAAP, the
Company has classified the Pioneer South Africa results of operations as discontinued operations in each of the years presented,
rather than as a component of continuing operations. 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 $853.6 million, including normal post-closing adjustments, 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
Company's Gulf of Mexico shelf properties were sold effective July 1, 2009. 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 Notes B and U 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 2011 included the following highlights:

Earnings attributable to common stockholders increased to $834.5 million ($6.88 per diluted share), as
compared to $605.2 million ($5.08 per diluted share) in 2010. The increase in earnings attributable to common
stockholders is primarily due to:

- A $575.8 million increase in oil and gas revenues as a result of increasing sales volumes and higher

average oil and NGL sales prices;

- A $289.1 million increase 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; and

- A $68.3 million decrease in exploration and abandonments expense, primarily due to a reduction in

exploratory dry hole provisions; partially offset by:

- A $354.4 million impairment provision on dry gas properties in the Edwards and Austin Chalk fields

in South Texas;

- A $137.5 million decrease in net hurricane activity due to the receipt in 2010 of $140 million of

insurance proceeds;

- A $107.5 million increase in DD&A, primarily due to increased sales volumes;
- An $88.3 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; and

- A $55.7 million decrease in net derivative gains, primarily due to reduced interest rate derivative gains

during 2011;

Daily sales volumes from continuing operations increased on a BOE basis by 16 percent to 120,418 BOEPD
during 2011, as compared to 103,823 BOEPD during 2010, primarily due to the success of the Company's
drilling programs;

Average reported oil and NGL prices from continuing operations increased during 2011 to $96.60 and $46.27
per Bbl, respectively, as compared to respective average reported prices of $90.56 and $38.14 per Bbl during
2010. Partially offsetting the increases in average reported oil and NGL prices was a decrease in average
reported gas prices to $3.84 per Mcf during 2011, as compared to $4.18 per Mcf during 2010;

Average oil and gas production costs and total ad valorem and production taxes per BOE from continuing
operations increased during 2011 to $10.32 and $3.35, respectively, as compared to respective per BOE costs of
$9.61 and $2.96 during 2010, primarily as a result of inflation of well servicing costs, increased transportation
and treating costs and higher commodity prices;

Net cash provided by operating activities increased by $244.7 million, or 19 percent, to $1.5 billion for 2011, as
compared to $1.3 billion during 2010, primarily due to the increases in oil and gas sales volumes, oil and NGL
prices and realized derivative gains;

Long-term debt was reduced by $72.8 million and the Company's cash and cash equivalents increased by

$426.3 million during 2011;

During November 2011, the Company completed an offering of 5.5 million shares of its common stock at a per-
share offering price of $92.03 and realized $484.2 million of associated proceeds, net of offering costs. The
Company is using the net proceeds from this offering for general corporate purposes, including expansion of its
drilling in the horizontal Wolfcamp Shale play in the Spraberry field;

During 2011, the Company continued to expand its integrated services to control drilling and completion costs
and support the execution of its accelerated drilling program. The Company has increased its owned drilling
rigs to 15 and increased its owned fracture stimulation fleets to ten during 2011;

PIONEER NATURAL RESOURCES COMPANY

During December 2011, Pioneer Southwest completed a public offering of 4.4 million common units, including
1.8 million common units owned by Pioneer, at a per-unit offering price of $29.20. The Company realized
$123.0 million of consolidated proceeds, net of offering costs, associated with this offering;

During December 2011, the Company committed to a plan to sell Pioneer South Africa. The Company expects
to complete the sale of Pioneer South Africa during 2012. In accordance with GAAP, the Company has
classified Pioneer South Africa assets and liabilities as discontinued operations held for sale in the Company's
accompanying consolidated balance sheet as of December 31, 2011, and has recast Pioneer South Africa's
results of operations as income from discontinued operations, net of associated income taxes, in the
accompanying consolidated statements of operations included in "Item 8. Financial Statements and
Supplementary Data"; and

As of December 31, 2011, the Company's net debt to book capitalization was 26 percent, as compared to 37
percent as of December 31, 2011. The Company was upgraded to investment grade by one of its debt rating
agencies during the fourth quarter of 2011.

First Quarter 2012 Continuing Operations Outlook

Based on current estimates, the Company expects that first quarter 2012 production will average 141,000 to

146,000 BOEPD, reflecting increased 2012 drilling activity.

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

Total exploration and abandonment expense for the quarter is expected to be $35 million to $60 million, the
higher limit of which reflects the potential dry hole costs associated with two exploration wells being drilled in
Alaska. General and administrative expense is expected to be $49 million to $54 million. Interest expense is
expected to be $45 million to $49 million, and other expense is expected to be $20 million to $30 million. Accretion
of discount on asset retirement obligations from continuing operations 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 $9 million to $12 million, primarily reflecting the public ownership in Pioneer
Southwest.

During January 2012, the Company sold a portion of its interest in an unproved oil and gas property in the
Eagle Ford Shale to unaffiliated third parties for $54.8 million. The Company expects to record a pretax gain of $40
million to $43 million attributable to this transaction during the three months ended March 31, 2012.

The Company's first quarter effective income tax rate from continuing operations 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 $5 million and are primarily
attributable to state taxes.

2012 Capital Budget

Pioneer's capital program for 2012 totals $2.5 billion, consisting of $2.4 billion for drilling operations,
including budgeted land capital for existing assets, and $100 million for vertical integration. The 2012 budget
excludes acquisitions, asset retirement obligations, capitalized interest and geological and geophysical general and
administrative expense.

The 2012 drilling capital of $2.4 billion continues to be focused on oil- and liquids-rich drilling, with 89
percent of the capital allocated to the Spraberry field, including the horizontal Wolfcamp Shale play, the Eagle Ford
Shale play and the Barnett Shale Combo play. Following is a breakdown of the forecasted spending by asset area:

Spraberry field, excluding Horizontal Wolfcamp Shale – $1.5 billion;

Horizontal Wolfcamp Shale -- $275 million;
Eagle Ford Shale – $130 million (reflecting 25 percent of anticipated 2011 drilling costs, with the remaining 75

percent to be funded by a contractual drilling carry benefit);

PIONEER NATURAL RESOURCES COMPANY

Barnett Shale Combo play – $215 million;
Alaska – $135 million; and
Other spending –$120 million, including land capital for existing assets.

Funds for the expansion of Pioneer's integrated fracture stimulation and well service operations are budgeted

at $100 million in 2012.

The 2012 capital budget is expected to be funded from cash and cash equivalents and forecasted operating

cash flow.

Acquisitions

During 2011, 2010 and 2009, the Company spent $131.9 million, $181.6 million and $88.9 million,
respectively, to acquire primarily undeveloped acreage for future exploitation and exploration activities. 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. The 2009 acquisitions primarily increased the Company's
acreage positions in the South Texas Eagle Ford Shale play.

Divestitures and Discontinued Operations

Pioneer South Africa. As referred to in Financial and Operating Performance above, in December 2011 the
Company committed to a plan 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 and the results of operations of Pioneer South Africa are reported as income from discontinued
operations, net of tax in all periods presented in the Company's accompanying consolidated statements of operations
(see Notes B and U 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 Tunisia. During December 2010, the Company committed to a plan to sell Pioneer Tunisia. The
assets and liabilities of Pioneer Tunisia are classified as discontinued operations held for sale in the Company's
accompanying consolidated balance sheet as of December 31, 2010. In February 2011 the Company sold its share
holdings in Pioneer Tunisia for net proceeds of $853.6 million and recorded an associated pretax gain of $645.2
million during the year ended December 31, 2011. 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.

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, including normal closing adjustments. Under the terms
of the transaction, the purchaser is also paying 75 percent (up to $886.8 million) of the Company's defined
exploration, drilling and completion costs attributable to the Eagle Ford Shale assets during the six years ending on
July 1, 2016, subject to extension. As of December 31, 2011, the purchaser had satisfied $398.2 million of the
obligation to pay 75 percent of the Company's defined exploration, drilling and completion costs attributable to
Eagle Ford Shale assets and continues to be obligated to pay $488.6 million of the Company's future qualifying
costs. The Company's current expectations are that the purchaser's obligation to pay 75 percent of the Company's
defined exploration, drilling and completion costs attributable to Eagle Ford Shale assets will be satisfied by the end
of 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. The historical results and the related
gain on disposition are reported as discontinued operations, net of tax.

Mississippi and Gulf of Mexico Shelf. During June and August 2009, the Company sold its Mississippi and
shelf properties in the Gulf of Mexico, respectively, for aggregate net proceeds of $23.6 million, resulting in a pretax
gain of $17.5 million. The historical results and the related gain on disposition are reported as discontinued
operations, net of tax.

PIONEER NATURAL RESOURCES COMPANY

Results of Operations

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

$1.4 billion during 2011, 2010 and 2009, 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; partially offset by an eight percent decrease in average reported gas
prices.

The increase in 2010 oil and gas revenues relative to 2009 is reflective of 20 percent, 28 percent and eight
percent increases in average reported oil, NGL and gas prices, respectively and a 13 percent increase in oil volumes;
partially offset by a five percent decrease in gas volumes.

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

2009:

Year Ended December 31,
2010

2009

2011

Oil (Bbls) ...........................................................................................................................
NGLs (Bbls) ......................................................................................................................
Gas (Mcf) ...........................................................................................................................
Total (BOE) .......................................................................................................................

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

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

24,968
19,680
352,749
103,440

Average daily BOE sales volumes in 2011 increased by 16 percent as compared to 2010 principally due to the
Company's successful United States drilling program and declines in scheduled VPP deliveries. Oil volumes
delivered under the Company's VPPs decreased by 45 percent from 2010 to 2011. The Company's only remaining
obligations under VPP agreement are to deliver 1,281,000 Bbls of oil during 2012.

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

and in total during 2011, 2010 and 2009:

Year Ended December 31,
2010

2009

2011

Oil (Bbls):
United States ...............................................................................................................
South Africa .................................................................................................................
Tunisia .........................................................................................................................
Worldwide ..................................................................................................................

NGLs (Bbls):
United States ...............................................................................................................

Gas (Mcf):
United States ...............................................................................................................
South Africa .................................................................................................................
Tunisia .........................................................................................................................
Worldwide ..................................................................................................................

Total (BOE):
United States ...............................................................................................................
South Africa .................................................................................................................
Tunisia .........................................................................................................................
Worldwide ..................................................................................................................

-
530
547
1,077

-
616
4,880
5,496

554
375
6,531
7,460

-
20,570
496
21,066

-
3,958
630
4,588

-
29,760
2,849
32,609

-
5,576
5,355
10,931

1,899
25,538
1,668
29,105

900
4,631
6,809
12,340

In South Africa, sales volumes in 2011 declined by 29 percent from 2010, primarily due to unplanned
production curtailments resulting from third-party gas-to-liquid plant downtime and normal well declines. In
Tunisia, sales volumes in 2011 decreased from those of 2010, due to the sale of Pioneer Tunisia during February
2011.

PIONEER NATURAL RESOURCES COMPANY

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 2011, 2010
and 2009:

Year Ended December 31,

2011

2010

2009

Average reported prices:

Oil (per Bbl) ........................................................................................................................... $
NGL (per Bbl) ....................................................................................................................... $
Gas (per Mcf) ......................................................................................................................... $
Total (per BOE) ..................................................................................................................... $
Average realized prices:

96.60 $
46.27 $
3.84 $
52.19 $

90.56 $
38.14 $
4.18 $
45.34 $

75.60
29.76
3.88
37.15

91.35 $
46.27 $
3.84 $
50.42 $

74.21 $
37.12 $
4.15 $
40.61 $

55.04
28.45
3.32
30.02

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 hedge contracts. Changes in the fair value of effective cash flow hedges prior
to the Company's discontinuance of hedge accounting were recorded as a component of AOCI – Hedging in the
stockholders' equity section of the Company's accompanying consolidated balance sheets, and are being transferred
to earnings during the same periods in which the hedged transactions are recognized in the Company's earnings.
Since February 1, 2009, the Company has recognized all changes in the fair values of its derivative contracts as
gains or losses in the earnings of the periods in which they occur.

The 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, 2011,
2010 and 2009 (in thousands):

Year Ended December 31,

2011

2010

2009

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

32,918 $

-
-

32,918 $

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

88,873
9,402
22,791
121,066

The Company will transfer $3.1 million of deferred hedge losses to oil revenues during the year ended
December 31, 2012, which transfer represents the remaining deferred hedge losses recorded in AOCI – Hedging as
of December 31, 2011. See Note I of Notes to Consolidated Financial Statements in "Item 8. Financial Statements
and Supplementary Data" for further information concerning the Company's commodity derivatives and scheduled
amortization of net deferred losses on discontinued commodity hedges that will be recognized as decreases to future
oil revenues.

PIONEER NATURAL RESOURCES COMPANY

Deferred revenue. During 2011 and 2010, the Company's amortization of deferred VPP revenue increased
annual oil revenues by $45.0 million and $90.2 million, respectively, and during 2009, increased oil and gas
revenues by $147.9 million. The Company's amortization of deferred VPP revenue will increase 2012 annual oil
revenues by $42.1 million, representing the remaining deferred revenues associated with VPP that is recorded in the
Company's accompanying balance sheet as of December 31, 2011. See Note S 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
$102.0 million, $57.0 million and $101.6 million during 2011, 2010 and 2009, respectively. The $45.0 million
increase during 2011, as compared to 2010, is primarily attributable to a $45.0 million increase in third-party income
associated with vertical integration services provided by the Company on operated wells and an $8.7 million
increase in equity earnings from EFS Midstream, partially offset by an $8.7 million decrease in Alaskan Petroleum
Production Tax ("PPT") credit recoveries. The $44.6 million decrease in interest and other income during 2010, as
compared to 2009, is primarily attributable to a $47.3 million decrease in PPT credit recoveries and a $2.2 million
increase in interest income.

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

for the years ending December 31, 2011, 2010 and 2009 (in thousands):

Year Ended December 31,
2010

2009

2011

Unrealized mark-to-market changes in fair value:
Oil derivative gains (losses) ................................................................................. $
NGL derivative gains (losses) ..............................................................................
Gas derivative gains (losses) ................................................................................
Diesel derivative gains .........................................................................................
Interest rate derivative gains (losses) ...................................................................
Total unrealized mark-to-market derivative gains (losses), net (a) ....................

68,376 $
10,243
179,787
270

(33,206)
225,470

41,094 $
10,690
277,585
-

35,040
364,409

(150,799)
(20,206)
(6,612)
-
(13,928)
(191,545)

Cash settled changes in fair value:
Oil derivative losses .............................................................................................
NGL derivative losses ..........................................................................................
Gas derivative gains .............................................................................................
Diesel derivative gains .........................................................................................
Interest rate derivative gains (losses) ...................................................................
Total cash derivative gains (losses), net .............................................................
Total derivative gains (losses), net ................................................................... $
__________
(a) Unrealized mark-to-market changes in fair value are subject to continuing market risk.

(36,664)
(15,418)
182,993
67
36,304
167,282
392,752 $

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

(60,604)
(8,340)
66,428
-
(1,496)
(4,012)
(195,557)

Gain (loss) on disposition of assets. The Company recorded a net loss on the disposition of assets of $3.6

million during 2011, a net gain of $19.1 million during 2010 and a net loss of $774 thousand during 2009.

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 and recorded net hurricane activity expenses of $17.3 million during 2009.

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.

PIONEER NATURAL RESOURCES COMPANY

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 the insurance policy dispute, resulting in an additional
payment to the Company of $140 million during November 2010. See Note T of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary Data" for specific information regarding
the Company's East Cameron platform facilities reclamation and abandonment.

Oil and gas production costs. The Company's oil and gas production costs from continuing operations totaled
$453.1 million, $364.8 million and $345.9 million during 2011, 2010 and 2009, 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.

During 2011, total production costs per BOE increased by seven 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.

During 2010, total production costs per BOE increased by five percent as compared to 2009. The increase in
production costs per BOE during 2010 was primarily due to (i) inflation in well servicing costs and (ii) increases in
workover expenditures incurred to mitigate production declines, partially offset by the expiration of a portion of the
Company's VPP delivery commitments.

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

2010 and 2009:

Year Ended December 31,
2010

2009

2011

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

8.09 $
1.26
0.15
0.82
10.32 $

7.74 $
0.87
0.08
0.92
9.61 $

7.39
0.95
0.27
0.55
9.16

Production and ad valorem taxes. The Company recorded production and ad valorem taxes of $147.7
million during 2011, as compared to $112.1 million and $98.4 million for 2010 and 2009, 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 2011, the Company's production taxes per BOE increased by 44 percent as compared to 2010,
primarily reflecting the impact of higher oil and NGL prices on production taxes. On a per BOE basis, ad valorem
taxes decreased 17 percent as compared to 2010, which is primarily a result of an increase in sales volumes from
new wells first brought on production during 2011. During 2010, the Company's production taxes per BOE
increased 34 percent over 2009, reflecting the year-to-year increase in commodity prices, while ad valorem taxes
decreased by one percent.

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 2011, 2010 and 2009:

Year Ended December 31,
2010

2009

2011

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

1.24 $
2.11
3.35 $

1.49 $
1.47
2.96 $

1.51
1.10
2.61

PIONEER NATURAL RESOURCES COMPANY

Depletion, depreciation and amortization expense. The Company's total DD&A expense from continuing
operations was $607.4 million ($13.82 per BOE), $499.9 million ($13.19 per BOE), and $564.1 million ($14.94 per
BOE) for 2011, 2010 and 2009, respectively. Depletion expense on oil and gas properties, the largest component of
DD&A expense, was $12.55, $12.40 and $14.20 per BOE during 2011, 2010 and 2009, respectively.

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 Combo play, 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 are carried by a third party. During 2010, the decrease in per BOE
depletion expense was primarily due to (i) proved reserve additions associated with the Company's successful 2010
capital expenditures program and (ii) adding end-of-life reserves that became economic as a result of commodity
price increases since 2009.

During the fourth quarter of 2009, the Company adopted the provisions of the Reserve Ruling and ASU
2010-03. The provisions of the Reserve Ruling and ASU 2010-03, which became effective for annual reports on
Form 10-K for fiscal years ending on or after December 31, 2009, changed the definition of proved oil and gas
reserves to require the use of an average of the first-day-of-the-month commodity prices during the 12-month period
ending on the balance sheet date rather than the period-end commodity prices; added to and amended certain
definitions used in estimating proved oil and gas reserves, such as "reliable technology" and "reasonable certainty;"
and broadened the types of technology that an issuer may use to establish reserves estimates and categories. The
adoption of the provisions of the Reserve Ruling and ASU 2010-03 reduced the Company's total proved reserves by
11 percent as of December 31, 2009.

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

During the third and fourth quarters of 2011, events and circumstances provided indications of possible
impairment of certain of the Company's dry gas assets, including oil and gas proved properties in the Company's
Edwards, Austin Chalk, Raton and Barnett Shale fields. The events and circumstances indicating possible
impairment of these fields are primarily related to reductions in management's gas price outlooks that led to a
decrease in estimated future undiscounted net cash flows attributable to each field's proved reserves. 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 Outlook"). During the fourth quarter of 2011, the
estimate of undiscounted future net cash flows attributable to the Company's Edwards and Austin Chalk fields in
South Texas indicated that their carrying amounts were partially unrecoverable. Consequently, the Company
recorded $354.4 million of impairment charges to reduce the carrying values of these fields to their estimated fair
values.

The Company's estimates of undiscounted future net cash flows attributable to the Raton and Barnett Shale
fields' oil and gas properties indicated on December 31, 2011 that their carrying amounts were expected to be
recovered, but continue 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 Outlook, of approximately $5.15 per Mcf as of December 31, 2011, were to decline by
approximately $0.50 to $0.60 per Mcf. Similarly, the Company estimates that the carrying value of the Barnett
Shale field may become partially impaired if the average price of gas in Management's Price Outlook were to
decline by approximately $0.80 to $1.20 per Mcf. The Company's Raton and Barnett Shale fields are relatively
long-lived assets that had carrying values of $2.3 billion and $456.8 million, respectively, as of December 31, 2011.
If the Raton and Barnett Shale fields were to become impaired in a future quarter, the Company would recognize
impairment charges in that period and such noncash pretax charges could range from $1.6 billion to $1.8 billion for
the Raton field and $250 million to $350 million for the Barnett Shale field.

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

PIONEER NATURAL RESOURCES COMPANY

During the year ended December 31, 2009, the Company recognized impairment charges of $21.1 million to
reduce the carrying value of the Company's oil and gas properties in the Uinta/Piceance areas. Declines in gas
prices and downward adjustments to the economically recoverable resource potential of these properties led to the
impairment charges.

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

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

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 2011, 2010 and 2009 (in thousands):

Year Ended December 31,
2010

2011

2009

Geological and geophysical .................................................................................... $
Exploratory dry holes ..............................................................................................
Leasehold abandonments and other ........................................................................

73,552 $
3,112
44,656
121,320 $

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

40,919
6,873
31,303
79,095

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.

During 2009, the Company's exploration and abandonment expense was primarily attributable to geological
and geophysical costs, dry hole expense in the South Texas, Lay Creek and Raton Basin areas and unproved
property abandonments in the Permian Basin, Barnett Shale and Raton Basin areas. The significant components of
the Company's 2009 exploratory dry hole provisions and leasehold abandonments expense included (i) $6.9 million
of dry hole provisions, primarily associated with the write off of suspended well costs and (ii) $29.4 million of
unproved property abandonments. During 2009, the Company completed and evaluated 15 exploration/extension
wells, 13 of which were successfully completed as discoveries.

General and administrative expense. General and administrative expense from continuing operations totaled
$193.2 million, $164.3 million and $130.9 million during 2011, 2010 and 2009, respectively. The increase in general
and administrative expense during 2011, as compared to 2010, was primarily due to increases in compensation,
occupancy and contract labor expenses related to staffing increases in support of the Company's capital expansion
initiatives and vertical integration efforts, partially offset by an increase in producing, drilling and other overhead
recoveries. In support of the Company's strategic growth initiatives, the Company anticipates continued growth in
total employees and compensation-related expenses.

The increase in general and administrative expense during 2010, as compared to 2009, was primarily due to
increases in performance-related compensation expense and staffing increases to support the Company's increased
activity level during 2010.

Accretion of discount on asset retirement obligations. Accretion of discount on asset retirement obligations
from continuing operations was $8.3 million, $7.9 million and $8.1 million during 2011, 2010 and 2009,
respectively. Accretion of discount on asset retirement obligations increased slightly during 2011, as compared to

PIONEER NATURAL RESOURCES COMPANY

2010 and 2009, primarily due to additional well completions resulting from the Company's drilling activities. See
Note K 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 $181.7 million, $183.1 million and $173.4 million during 2011, 2010
and 2009, respectively. The weighted average interest rate on the Company's indebtedness for the year ended
December 31, 2011 was 7.2 percent, as compared to 7.1 percent and 5.7 percent for the years ended December 31,
2010 and 2009, respectively.

The $9.7 million increase in interest expense during the year ended December 31, 2010, as compared to 2009,
was primarily due to (i) a $29.0 million increase in cash interest expense on senior notes due to an increase in
average senior note borrowings, which was primarily attributable to the issuance of $450 million of 7.5% Senior
Notes during November 2009, partially offset by (ii) a $10.6 million decrease in cash interest expense on credit
facility indebtedness and (iii) a $5.6 million increase in capitalized interest related to the Oooguruk project in Alaska
as a result of the Company's weighted average interest rate increasing.

See Notes B and E 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 $63.2 million during 2011, as compared to
$78.4 million during 2010 and $94.7 million during 2009. The $15.2 million decrease in other expense during 2011,
as compared to 2010, is primarily due to a $17.4 million decrease in charges recorded for the difference between
Pioneer contracted rig rates and market rig rates that are charged to joint operations and idle rig costs, a $13.1
million decrease in idle well servicing operations 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.

The $16.3 million decrease in other expense during 2010, as compared to 2009, is primarily due to a $16.7
million decrease in excess and terminated rig-related costs, a $5.3 million decrease in transportation commitment
charges, a $4.8 million decrease in bad debt expense and a $2.2 million decrease in contingency and environmental
accrual adjustments, partially offset by an $8.5 million increase in inventory impairment and a $3.3 million increase
in tax penalties and adjustments.

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 benefit (provision). The Company recognized income tax provisions attributable to earnings from
continuing operations of $197.6 million and $269.6 during 2011 and 2010, respectively and an income tax benefit of
$83.2 million during 2009. The Company's effective tax rates on earnings from continuing operations, excluding
income from noncontrolling interest, for 2011, 2010 and 2009 were 33 percent, 36 percent and 35 percent,
respectively, as compared to the combined United States federal and state statutory rates of approximately 37
percent.

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 attributes.

Income (loss) from discontinued operations, net of tax. During December 2011, the Company committed to
a plan to sell Pioneer South Africa. The plan is expected to result in the sale of the Pioneer South Africa during
2012. In accordance with GAAP, the Company classified Pioneer South Africa assets and liabilities as discontinued
operations held for sale in the Company's accompanying consolidated balance sheet as of December 31, 2011, and
has recast the Pioneer South Africa's results of operations as income from discontinued operations, net of tax in the
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 net cash proceeds of $853.6 million, including
normal post-closing adjustments, resulting in a pretax gain of $645.2 million. Accordingly, the Company classified
the assets and liabilities of Pioneer Tunisia as discontinued operations held for sale in the accompanying balance
sheet as of December 31, 2010 and classified the results of operations of Pioneer Tunisia as income from
discontinued operations, net of tax in the accompanying consolidated statements of operations. During 2009, the

PIONEER NATURAL RESOURCES COMPANY

Company sold its oil and gas properties in Mississippi and substantially all of its shelf properties in the Gulf of
Mexico. The results of operations of these assets and the related gains on disposition are reported as discontinued
operations in the accompanying consolidated statements of operations.

The Company recognized income from discontinued operations, net of tax of $423.2 million for 2011 as
compared to income of $134.1 million for 2010 and $99.7 million for 2009. 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.

The $34.3 million increase in income from discontinued operations, net of tax during 2010, as compared to
2009 is attributable to (i) the after tax impact of the 2010 receipt of $35.3 million of interest associated with the
recovery of excess deepwater Gulf of Mexico oil and gas royalties paid during 2003 through 2005, (ii) a $24.0
million increase in Tunisian income from discontinued operations, (iii) a 2010 deferred tax benefit adjustment
related to Tunisia of $56.5 million and (iv) a $21.4 million increase in Pioneer South Africa's income from
discontinued operations, partially offset by (v) the after tax impact of the 2009 recognition of $119.3 million of
pretax gain from the aforementioned excess royalty recovery. See Note U 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
$47.4 million, $40.8 million and $9.8 million for the years ended December 31, 2011, 2010 and 2009, 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 $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.

The $31.0 million increase in net income attributable to noncontrolling interest in 2010, compared to 2009, is
primarily due to an increase in Pioneer Southwest's noncash mark-to-market derivative gains. 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, including EFS Midstream capital funding requirements in excess of its ability to internally fund capital
commitments, dividends/distributions and working capital obligations. Funding for these cash needs, which is
mitigated by the $488.6 million third-party obligation to pay 75 percent of the Company's future qualifying Eagle
Ford Shale costs, may be provided by any combination of internally-generated cash flow, cash and cash equivalents
on hand, proceeds from the disposition of nonstrategic assets or external financing sources as discussed in "Capital
resources" below. During 2012, the Company expects that it will be able to fund its needs for cash (excluding
acquisitions) with internally-generated cash flows and cash and cash equivalents on hand. Although the Company
expects that internal operating cash flows and cash and cash equivalents on hand will be adequate to fund capital
expenditures and dividend/distribution payments, and that available borrowing capacity under the Company's credit
facility will provide adequate liquidity to fund other needs, no assurances can be given that such funding sources
will be adequate to meet the Company's future needs.

During 2012, the Company plans to continue to focus its capital spending primarily on liquids-rich drilling
activities. The Company's 2012 capital budget totals $2.5 billion (excluding effects of acquisitions, asset retirement
obligations, capitalized interest, geological and geophysical administrative costs and EFS Midstream capital
contributions), consisting of $2.4 billion for drilling operations and $100 million for vertical integration additions.
Based on the Company's current commodity prices outlook, Pioneer expects its net cash flows from operating
activities, together with approximately $300 million of cash and cash equivalents on hand, to be sufficient to fund its
planned capital expenditures and contractual obligations.

Investing activities. Net cash used in investing activities during 2011 was $1.6 billion, as compared to net
cash used in investing activities of $954.9 million and $411.0 million during 2010 and 2009, respectively. The
increase in net cash flow used in investing activities during 2011, as compared to 2010, was comprised of a $915.5

PIONEER NATURAL RESOURCES COMPANY

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 the
Company's share holdings in Pioneer Tunisia during February 2011). The increase in net cash flow used in investing
activities during 2010, as compared to 2009, was comprised of a $574.2 million increase in additions to oil and gas
properties, a $159.0 million increase in additions to other assets and other property and equipment and a $72.9
million increase in investment in unconsolidated subsidiaries, partially offset by an increase of $262.2 million in
proceeds from disposition of assets. During 2010, the $313.8 million of proceeds from disposition of assets was
mainly comprised of $212.0 million of joint venture cash proceeds from the sale of a 45 percent interest in the
Company's Eagle Ford Shale properties, $23.7 million of past cost recoveries from Enterprise Tunisiene d'Activities
Petrolieres ("ETAP") associated with its participation in the Cherouq concession and $77.4 million of net proceeds
from the sale of other assets. See "Results of Operations" above and Note M 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, 2011, 2010 and 2009, the Board
declared semiannual dividends of $0.04 per common share. Associated therewith, the Company paid $9.6 million,
$9.5 million and $9.4 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 2011, the board of directors of the general partner of Pioneer
Southwest (the "Pioneer Southwest Board") declared quarterly distributions of $0.50, $0.51, $0.51, and $0.51 per
limited partner unit, respectively. During January, April, July and October of 2010 and 2009, the Pioneer Southwest
Board declared quarterly distributions of $0.50 per limited partner unit. Associated therewith, Pioneer Southwest
paid aggregate distributions to noncontrolling unitholders of $25.6 million, $25.2 million and $19.0 million during
the years ended December 31, 2011, 2010 and 2009, respectively. Future distributions of Pioneer Southwest are at
the discretion of the Pioneer Southwest Board, and, if declared, the Pioneer Southwest Board may change the
distribution amount based on Pioneer Southwest's liquidity and capital resources at the time.

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,
2011, 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)
VPP obligations (to physically deliver volumes and pay related lease operating expenses and capital costs in the
future), (v) open purchase commitments, (vi) EFS Midstream capital funding commitments, (vii) take-or-pay
obligations that allow the payer to recover make up volumes in the future and (viii) 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 and transportation commitments on
uncertain volumes of future throughput. Other than the off-balance sheet arrangements described above, the
Company has no transactions, arrangements or other relationships with unconsolidated entities or other 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.

liabilities (including postretirement benefit obligations), firm

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
transportation
commitments, minimum annual gathering, treating and transportation commitments, and VPP obligations. The
Company's contractual obligations include obligations to purchase goods and services for properties that the
Company operates, including certain drilling commitments, open purchase commitments and firm gathering,
processing and transportation commitments. Other joint owners in the properties operated by the Company will
incur portions of the costs represented by these commitments, including qualifying Eagle Ford Shale costs that are
subject to a counterparty's obligation to carry up to 75 percent of the Company's costs (see "Financial and Operating
Performance" and Note M of Notes to Consolidated Financial Statements included in "Item 8. Consolidated
Financial Statements and Supplementary Data").

PIONEER NATURAL RESOURCES COMPANY

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

estimated as of December 31, 2011:

2012

Payments Due by Year

2013 and
2014

2015 and
2016

(in thousands)

Thereafter

Long-term debt (a) .......................................................................... $
Operating leases (b) ........................................................................
Drilling commitments (c) ...............................................................
Derivative obligations (d) ...............................................................
Open purchase commitments (e).....................................................
Other liabilities (f) ..........................................................................
Firm gathering, processing and transportation commitments (g) ....
VPP obligations (h) .........................................................................

- $

455,385 $ 1,634,600
41,459
24,931
-
510
-
-
-
-
177,354
21,183
1,069,159
640,908
-
-
$ 1,080,436 $ 1,205,879 $ 1,142,917 $ 2,922,572

511,930 $
39,729
100,106
33,561
16,990
23,058
480,505
-

26,843
367,897
74,415
381,398
36,174
151,640
42,069

__________
(a) Long-term debt includes $479.9 million principal amount of the Company's 2.875% Convertible Senior Notes due 2038
(the "2.875% Convertible Senior Notes"). Holders of the 2.875% Convertible Senior Notes may elect to convert their
notes if the last reported sale price of the Company's common stock is greater than 130 percent of the base conversion
price as defined in the indenture. The price of the Company's common stock has recently been trading at prices above
130 percent of the base conversion price and, accordingly, if the common stock continues to trade above 130 percent of
the base conversion price, the holders of the 2.875% Convertible Senior Notes may, at their option, be able to convert the
notes as early as the second quarter of 2012. If any holders elect to convert, the Company expects that the cash portion of
the conversion payment will be available from cash on hand and that the conversion of the 2.875% Convertible Senior
Notes would not have a material adverse effect on the Company's liquidity. See "Item 7A. Quantitative and Qualitative
Disclosures About Market Risk" for information regarding estimated future interest payment obligations under long-term
debt obligations and Note E of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data." The amounts included in the table above represent principal maturities only.

(b) See Note H of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary

Data" for more information about the Company's operating leases.

commitments under contracts to which the Company was a party on December 31, 2011.

(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, 2011. 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 I 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, 2011.

(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 G, H
and K 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, litigation and environmental
contingencies and asset retirement obligations, respectively.

(g) Gathering, processing and transportation commitments represent estimated fees on production throughput commitments.
See "Item 2. Properties" and Note H 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.

(h) VPP obligations represent the amortization of the deferred revenue associated with the Company's remaining VPP. The
Company's ongoing obligation is to deliver the specified volumes sold under the VPP free and clear of all associated
production costs and capital expenditures. See Note S of Notes to Consolidated Financial Statements included in "Item 8.
Financial Statements and Supplementary Data."

Capital resources. The Company's primary capital resources are cash and cash equivalents, net cash provided
by operating activities, proceeds from sales of nonstrategic assets and proceeds from financing activities (principally
borrowings under the Company's credit facility). If cash and cash equivalents together with internal cash flows do
not meet the Company's expectations, the Company may reduce its level of capital expenditures, reduce dividend

PIONEER NATURAL RESOURCES COMPANY

payments, and/or fund a portion of its capital expenditures using borrowings under its credit facility, issuances of
debt or equity securities or from other sources, such as asset sales or joint ventures.

Operating activities. Net cash provided by operating activities for the years ended December 31, 2011, 2010
and 2009 was $1.5 billion, $1.3 billion and $543.1 million, respectively. The increase in net cash flow provided by
operating activities in 2011, as compared to 2010, is primarily due to increases in oil and gas sales volumes, oil and
NGL prices and cash derivative gains. The increase in net cash flow provided by operating activities in 2010, as
compared to 2009, was primarily due to increases in average oil, NGL and gas prices, an increase in cash derivative
gains and working capital changes, partially offset by decreases in NGL and gas sales volumes.

Asset divestitures. During December 2011, the Company committed to a plan to sell Pioneer South Africa
and expects to complete a sale of the assets during 2012. During 2011, the Company completed the sale of the
Company's share holdings in Pioneer Tunisia to an unaffiliated party for net cash proceeds of $853.6 million,
including normal post-closing adjustments, resulting in a pretax gain of $645.2 million.

During 2010 the Company (i) sold certain proved and unproved oil and gas properties associated with an
Eagle Ford Shale joint venture transaction for net proceeds of $212.0 million, (ii) sold certain proved and unproved
properties in the Uinta/Piceance area for net proceeds of $11.8 million and (iii) received $23.7 million from ETAP
as contractual reimbursement of a portion of the Company's past capital costs incurred in Tunisia. See Note M 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 2011 was $457.4 million, as compared
to net cash used in financing activities during 2010 and 2009 of $246.4 million and $153.0 million, respectively.
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. During 2009, significant components of financing activities included
$159.9 million of net principal payments on long-term debt and $63.3 million of payments associated with
dividends, distributions to noncontrolling interests, financing fees and stock repurchases, partially offset by $61.0
million of net proceeds from a secondary unit offering by Pioneer Southwest.

The following provides a description of the Company's significant financing activities during 2011, 2010 and

2009:

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;

During November 2011, the Company completed the sale of 5.5 million shares of its common stock for $484.2
million of net proceeds (the "Equity Offering"). The Company used the net proceeds to increase cash and cash
equivalents, a portion of which will be used during 2012 to fund the Company's planned drilling program;

The Company's stock price during March 2011 caused the Company's 2.875% Convertible Senior Notes to be
convertible at the option of the holders during the three months ended June 30, 2011. Associated therewith,
holders of the 2.875% Convertible Senior Notes tendered $70 thousand principal amount of the notes for
conversion during the three months ended June 30, 2011. During July and August 2011, the Company paid the
holders a total of $71 thousand of cash and issued 340 shares of the Company's common stock. The Company's
2.875% Convertible Senior Notes may become convertible in future quarters depending on the Company's stock
price performance or under certain other conditions. The price of the Company's common stock has recently
been trading at prices above 130 percent of the base conversion price of the 2.875% Convertible Senior Notes
and, accordingly, if the common stock continues to trade above 130 percent of the base conversion price, the
holders, at their option, will be able to convert the notes as early as the second quarter of 2012. The Company
intends to fund the cash portion of future conversion payments, if any, with cash on hand;

PIONEER NATURAL RESOURCES COMPANY

During March 2011, the Company entered into a Second Amended and Restated 5-Year Revolving Credit
Agreement (the "Credit Facility") with a syndicate of financial institutions that matures in March 2016, unless
extended in accordance with the terms of the Credit Facility. The Credit Facility replaces the Company's
Amended and Restated 5-Year Revolving Credit Agreement entered into in April 2007 and provides for
aggregate loan commitments of $1.25 billion;

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

During November 2009, the Company issued 7.50% senior notes due 2020 and received net proceeds of $438.6
million. The Company used the net proceeds to reduce outstanding borrowings under its credit facility; and

During November 2009, Pioneer Southwest completed a public offering of 3.1 million common units for $61.0
million of net proceeds. Pioneer Southwest used the net proceeds to repay amounts outstanding under its credit
facility.

See Note E 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. There were no outstanding borrowings under the Credit Facility as of
December 31, 2011. Including $65.1 million of undrawn and outstanding letters of credit under the Credit Facility,
the Company had $1.2 billion of unused borrowing capacity under the Credit Facility as of December 31, 2011. If
cash and cash equivalents together with internal cash flows do not meet the Company's expectations, the Company
may reduce its level of capital expenditures, reduce dividend payments, and/or fund a portion of its capital
expenditures using borrowings under the Credit Facility, issuances of debt or equity securities or from other sources,
such as asset sales or joint ventures. The Company cannot provide any assurance that needed short-term or long-
term liquidity will be available on acceptable terms or at all. Although the Company expects that internal cash flows
and cash and cash equivalents on hand will be adequate to fund capital expenditures and dividend payments, and
that available borrowing capacity under the Credit Facility will provide adequate liquidity, no assurances can be
given that such funding sources will be adequate to meet the Company's future needs. For instance, the amount that
the Company may borrow under the Credit Facility in the future could be reduced as a result of lower oil, NGL or
gas prices, among other items.

Debt ratings. The Company receives debt credit ratings from several of the major ratings agencies, which are
subject to regular reviews. The Company believes that each of the rating agencies 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 impact the
Company's ability to obtain additional financing or the interest rate, fees and other terms associated with such
additional financing. In November 2011, the Company achieved an investment grade rating with one of the credit
rating agencies.

Book capitalization and current ratio. The Company's net book capitalization at December 31, 2011 was
$7.6 billion, consisting of $537.5 million of cash and cash equivalents, debt of $2.5 billion and stockholders' equity
of $5.7 billion. The Company's debt to book capitalization decreased to 26 percent at December 31, 2011 from 37
percent at December 31, 2010, primarily due to a decrease in indebtedness, an increase in cash and cash equivalents
and stockholders' equity as a result of the Equity Offering completed in November 2011 and $834.5 million of net
income attributable to common stockholders during 2011. The Company's ratio of current assets to current liabilities
was 1.46 to 1.00 at December 31, 2011, as compared to 1.56 to 1.00 at December 31, 2010.

PIONEER NATURAL RESOURCES COMPANY

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 K 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 2011, 2010 and 2009, the
Company recognized exploration, abandonment, geological and geophysical expense from continuing operations of
$121.3 million, $189.6 million and $79.1 million, respectively. During 2011, 2010 and 2009, the Company
recognized exploration, abandonment, geological and geophysical expense from discontinued operations of $4.3
million, $15.9 million and $19.2 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;
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, 2011, 2010 and 2009
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.

PIONEER NATURAL RESOURCES COMPANY

It should not be assumed that the Standardized Measure included in this Report as of December 31, 2011 is
the current market value of the Company's estimated proved reserves. In accordance with SEC requirements, the
Company based the 2011 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, its outlook of future
commodity prices, 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 Note R 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, 2011, the Company carried unproved
property costs of $235.5 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,
commodity price outlooks, 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 oil and gas 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 C of Notes to 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 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

PIONEER NATURAL RESOURCES COMPANY

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. This requires the
Company 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, 2010 and 2009. 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 H 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.

Valuations of defined benefit pension and postretirement plans. The Company is the sponsor of certain
defined benefit pension and postretirement plans. In accordance with GAAP, the Company is required to estimate
the present value of its unfunded pension and accumulated postretirement benefit obligations. Based on those values,
the Company records the unfunded obligations of those plans and records ongoing service costs and associated
interest expense. The valuation of the Company's pension and accumulated postretirement benefit obligations
requires management assumptions and judgments as to benefit cost inflation factors, mortality rates and discount
factors. Changes in these factors may materially change future benefit costs and pension and accumulated
postretirement benefit obligations. See Note G of Notes to Consolidated Financial Statements included in "Item 8.
Consolidated Financial Statements and Supplementary Data" for additional information regarding the Company's
pension and accumulated postretirement benefit obligations.

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 G 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 reports 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

The effects of new accounting pronouncements are discussed in Note B of Notes to Consolidated Financial

Statements included in "Item 8. Financial Statements and Supplementary Data."

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, 2011, and from which the Company may incur future gains or losses from
changes in commodity prices, interest rates or foreign exchange 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, 2011, 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 I of
Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for
additional information regarding the Company's derivative contracts, including deferred gains and losses on
terminated derivative contracts. The following table reconciles the changes that occurred in the fair values of the
Company's open derivative contracts during 2011:

Derivative Contract Net Assets (Liabilities) (a)

Commodities Interest Rate

Total

(in thousands)

Fair value of contracts outstanding as of December 31, 2010 ............................ $
Changes in contract fair values (b) ...................................................................
Contract maturities ............................................................................................
Fair value of contracts outstanding as of December 31, 2011 ............................ $
__________
(a) Represents the fair values of open derivative contracts subject to market risk.
(b) At inception, new derivative contracts entered into by the Company generally have no intrinsic value.

167,567 $
389,654
(167,468)
389,753 $

17,552 $
3,098
(36,304)
(15,654) $

185,119
392,752
(203,772)
374,099

Quantitative Disclosures

Interest rate sensitivity. The following tables provide information about financial instruments to which the
Company was a party as of December 31, 2011 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, 2011. 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 24, 2012.

PIONEER NATURAL RESOURCES COMPANY

INTEREST RATE SENSITIVITY
DEBT OBLIGATIONS AND DERIVATIVE FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 2011

2012

Year Ending December 31,
2015
2014
2013

2016

Thereafter

Total

Liability Fair
Value at
December 31,
2011

6.05%

Total Debt:
Fixed rate principal
maturities (a) ............................. $
Weighted average
interest rate ................................
Variable rate principal
maturities:
Pioneer Southwest
credit facility .............................. $
Weighted average
interest rate ................................
Interest Rate Swaps:
Notional debt amount (b) .............. $ 117,222 $
3.06%
Fixed rate payable (%) ..................
0.52%
Variable rate receivable (%) (c) ....

1.41%

- $

- $ 479,930 $

- $

- $ 455,385 $ 1,634,600 $ 2,569,915 $ (3,073,192)

6.74% 6.78%

6.78%

6.88%

7.13%

32,000 $

- $

32,000 $

(32,393)

1.56%

- $
-
-

-
-
-

(15,654)

__________
(a) Represents maturities of principal amounts excluding debt issuance discounts and net deferred fair value hedge losses.
(b) Represents weighted average notional contract amounts of interest rate derivatives.
(c) Represents forward six-month LIBOR received by the Company.

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, 2011. Declines in commodity prices would reduce Pioneer's revenues and increases in
diesel prices would increase the Company's internally-provided services costs, 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") 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.

The Company uses ''roll adjustment'' swap derivatives to mitigate the timing risk associated with the sales
price of oil in the Permian Basin. In the Permian Basin, the Company generally sells its oil at a sales price based on
the calendar month average NYMEX price of oil during that month, plus an adjustment calculated as the weighted
average spread between the NYMEX price for that delivery month and (i) the next month and (ii) the following
month during the period when the delivery month is prompt.

The Company purchases diesel derivative swap contracts to mitigate fuel price risk. The diesel derivative
swap contracts that the Company enters into are priced at an index that is highly correlated to the prices that the
Company incurs to fuel its drilling rigs, fracture stimulation fleet equipment and well servicing equipment.

See Notes B, D and I 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, diesel or gas prices.

PIONEER NATURAL RESOURCES COMPANY

OIL PRICE SENSITIVITY
DERIVATIVE FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 2011

Year Ending December 31,

2012

2013

2014

Asset (Liability)
Fair Value at
December 31,
2011

(in thousands)

2,217

(36,518)

(34,375)

41,610

34,000

10,000 $

- $
-
- $
-
-

3,000
79.32 $
2,000

3,000
81.02 $
-
- $
- $

Oil Derivatives:
Average daily notional Bbl volumes (a):
Swap contracts ...............................................................................
Weighted average fixed price per Bbl .......................................... $
Collar contracts ...............................................................................
Weighted average ceiling price per Bbl ....................................... $ 127.00 $
Weighted average floor price per Bbl .......................................... $
90.00 $
Collar contracts with short puts ......................................................
Weighted average ceiling price per Bbl ....................................... $ 118.24 $ 119.38 $ 127.46
Weighted average floor price per Bbl .......................................... $
87.50
72.50
Weighted average short put price per Bbl .................................... $
Average forward NYMEX oil prices (b) ......................................... $ 110.31 $ 106.86 $ 100.34
Roll Adjustment Swap contracts (c) ...............................................
Weighted average fixed price per Bbl .......................................... $
Average forward NYMEX roll adjustment prices (d) ...................... $
__________
(a) During the period from January 1, 2012 to February 24, 2012, the Company entered into additional collar contracts with
short puts for (i) 8,500 Bbls per day of the Company's July through December 2012 production with a ceiling price of
$120.47 per Bbl, a floor price of $95.00 per Bbl and a short put price of $80.00 per Bbl, (ii) 11,500 Bbls per day of the
Company's October through December 2012 production with a ceiling price of $121.10 per Bbl, a floor price of $95.00
per Bbl and a short put price of $80.00 per Bbl, (iii) 32,250 Bbls per day of the Company's 2013 production with a ceiling
price of $121.62 per Bbl, a floor price of $93.45 per Bbl and a short put price of $76.90 per Bbl and (iv) 13,000 Bbls per
day of the Company's 2014 production with a ceiling price of $118.78 per Bbl, a floor price of $90.00 per Bbl and a short
put price of $70.00 per Bbl.
The average forward NYMEX oil prices are based on February 24, 2012 market quotes.

(b)
(c) During the period from January 1. 2012 to February 24, 2012, the Company entered into additional roll adjustment swap
derivatives for 3,000 Bbls per day of 2013 oil sales, under which the Company pays the periodic variable roll adjustments
and receives a fixed price of $0.43 per Bbl.
The average forward roll adjustment prices were calculated from forward NYMEX oil prices.

3,000
0.43 $
0.69 $

750
0.28 $
0.06 $

84.35 $
66.56 $

82.36 $
66.52 $

- $
-
-

181

(d)

PIONEER NATURAL RESOURCES COMPANY

NGL AND DIESEL PRICE SENSITIVITY
DERIVATIVE FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 2011

Year Ending
December 31,
2012

Asset (Liability)
Fair Value at
December 31,
2011

(in thousands)

NGL and Diesel Derivatives:
Average daily notional Bbl volumes:
NGL Swap contracts ..............................................................................................................
Weighted average fixed price per Bbl ................................................................................. $
NGL 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) ............................................................................................ $
Diesel Swap contracts (b) ......................................................................................................
Weighted average fixed price per Bbl ................................................................................. $
Average forward Diesel prices (c) .......................................................................................... $
__________
(a)

(4,995)

5,682

270

750 $
35.03
3,000 $
79.99
67.70
55.76
65.65
500 $
119.49
137.70

Forward component NGL prices are derived from active-market NGL component price quotes. The forward prices
represent estimates as of February 24, 2012 provided by third parties who actively trade in NGL derivatives.
Subsequent to December 31, 2011, the Company terminated all diesel derivative swap contracts and received cash
proceeds of $1.8 million associated therewith.

(b)

PIONEER NATURAL RESOURCES COMPANY

GAS PRICE SENSITIVITY
DERIVATIVE FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 2011

Year Ending December 31,

2012

2013

2014

2015

Asset (Liability)
Fair Value at
December 31,
2011

(in thousands)

158,795

178,138

45,000

65,000

60,000

150,000

170,000

140,000

6.60 $
5.00 $

6.25 $
5.00 $

6.44 $
5.00 $

67,500
6.11 $

50,000
6.05 $

105,000
5.82 $

Gas Derivatives:
Average daily notional MMBtu volumes:
Swap contracts (a) ...................................................
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 (a) .........................
Weighted average ceiling price per MMBtu ........ $
Weighted average floor price per MMBtu ........... $
Weighted average short put price per MMBtu ..... $
Average forward NYMEX gas prices (b) ................ $
Basis swap contracts ...............................................
Weighted average fixed price per MMBtu ........... $
Average forward basis differential prices (c) ........... $
__________
(a) During the period from January 1, 2012 to February 24, 2012, the Company (i) entered into offsetting swap contracts for
20,000 MMBtus per day of the Company's March 2012 production with a fixed price of $2.41, (ii) converted 95,000
MMBtus per day of the Company's February through December 2012 collar contracts with short puts to swap contracts
with a fixed price of $4.47 per MMBtu, (iii) converted 75,000 MMBtus per day of the Company's March through
December 2012 collar contracts with short puts to swap contracts with a fixed price of $4.41 per MMBtu and (iv)
converted 45,000 MMBtus per day of the Company's 2013 collar contracts with short puts to swap contracts with a fixed
price of $4.88 per MMBtu.
The average forward NYMEX gas prices are based on February 24, 2012 market quotes.
The average forward basis differential prices are based on February 24, 2012 market quotes for basis differentials
between the relevant index prices and NYMEX-quoted forward prices.

- $
-
50,000 $
7.92
5.00
30,000 $
7.11
5.00
4.00
4.43
- $
-
(0.23) $
(0.17) $ -

7.80 $
5.83 $
4.42 $
4.18 $

7.92 $
6.07 $
4.50 $
2.98 $

7.49 $
6.00 $
4.50 $
3.79 $

(0.34) $
(0.16) $

(0.22) $
(0.16) $

115,000

136,000

142,500

137,727

(17,369)

(b)
(c)

Qualitative Disclosures

The Company's primary market risk exposures are to changes in commodity prices, interest rates and foreign

exchange rates. These risks did not change materially from December 31, 2010 to December 31, 2011.

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 E 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, interest rate
and foreign exchange rate derivative contracts to mitigate commodity price, interest rate and foreign exchange 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.

Foreign currency, operations and price risk. International investments represent a portion of the Company's
total assets. Pioneer currently has international discontinued operations in South Africa with a plan to sell Pioneer
South Africa during 2012. The Company has reflected all Pioneer South Africa assets and liabilities as of December
31, 2011 and Pioneer South Africa's historical results of operations as discontinued operations (see "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations" and Notes B and U of
Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for
information about the planned sale of Pioneer South Africa.

PIONEER NATURAL RESOURCES COMPANY

The Company's financial results and Pioneer South Africa results of operations could be affected by factors
impacting foreign operations such as changes in foreign currency exchange rates, changes in the legal or regulatory
environment, economic conditions or changes in political or economic climates and other factors. For example:

Local political and economic developments could restrict, or increase the cost of, Pioneer's foreign operations;
Exchange controls and currency fluctuations could result in financial losses;
Royalty and tax increases and retroactive tax claims could increase costs of the Company's foreign operations;
Expropriation of the Company's property could result in loss of revenue, property and equipment;
Civil uprising, riots, terrorist attacks and wars could make it impractical to continue operations, resulting in

financial losses;

Compliance with applicable U.S. law could be in conflict with the Company's contractual obligations, the laws

of foreign governments or local customs;
Import and export regulations and other foreign laws or policies could result in loss of revenues;

Repatriation levels for export revenues could restrict the availability of cash to fund operations outside a

particular foreign country; and

Laws and policies of the U.S. affecting foreign trade, taxation and investment could restrict the Company's

ability to fund foreign operations or may make foreign operations more costly.

The Company does not currently maintain political risk insurance for Pioneer South Africa.

Africa. The Company views the operating environment in South Africa as stable and the economic stability
as good. While the value of South Africa's currency fluctuates in relation to the U.S. dollar, the Company believes
that any currency risk associated with Pioneer South Africa's operations prior to its sale in 2012 would not have a
material impact on the Company's reported discontinued operations given that Pioneer South Africa's revenues are
closely tied to oil prices, which are denominated in U.S. dollars.

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, 2011 and 2010 ................................................................
Consolidated Statements of Operations for the Years Ended December 31, 2011, 2010 and 2009 ..............
Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2011,
2010 and 2009 ............................................................................................................................................
Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2011, 2010 and
2009 ............................................................................................................................................................
Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009 .............
Notes to Consolidated Financial Statements .................................................................................................
Unaudited Supplementary Information .........................................................................................................

Page

71
72
73

76
77
79
119

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, 2011 and 2010, and the related consolidated statements of operations,
comprehensive income (loss), stockholders' equity and cash flows for each of the three years in the period ended
December 31, 2011. 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, 2011 and 2010, and the
consolidated results of its operations and its cash flows for each of the three years in the period ended December 31,
2011, in conformity with U.S. generally accepted accounting principles.

As discussed in Note B to the consolidated financial statements, the Company has changed its reserve
estimates and related disclosures as a result of adopting new oil and gas reserves estimation and disclosure
requirements resulting from Accounting Standards Update No. 2010-03, "Oil and Gas Reserve Estimation and
Disclosures," effective December 31, 2009.

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,
2011, 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 29, 2012 expressed an
unqualified opinion thereon.

Dallas, Texas
February 29, 2012

/s/ Ernst & Young LLP

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS
(in thousands)

ASSETS

Current assets:
Cash and cash equivalents ...................................................................................................... $
Accounts receivable:
Trade, net of allowance for doubtful accounts of $806 and $1,155 as of
December 31, 2011 and 2010, respectively .....................................................................
Due from affiliates ...............................................................................................................
Income taxes receivable ...........................................................................................................
Inventories ..............................................................................................................................
Prepaid expenses .....................................................................................................................
Deferred income taxes ............................................................................................................
Discontinued operations held for sale ......................................................................................
Other current assets:
Derivatives ..........................................................................................................................
Other ....................................................................................................................................
Total current assets .........................................................................................................
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting:
Proved properties ................................................................................................................
Unproved properties ............................................................................................................
Accumulated depletion, depreciation and amortization ..........................................................
Total property, plant and equipment ...............................................................................
Goodwill .....................................................................................................................................
Other property and equipment, net .............................................................................................
Other assets:
Investment in unconsolidated affiliate .....................................................................................
Derivatives ..............................................................................................................................
Other, net of allowance for doubtful accounts of $340 and $2,519 as of
December 31, 2011 and 2010, respectively .........................................................................

December 31,

2011

2010

537,484 $

111,160

275,991
7,822
3
241,609
14,263
77,005
73,349

237,511
7,792
30,901
173,615
11,441
156,650
281,741

238,835
12,936
1,479,297

171,679
14,693
1,197,183

12,013,805
235,527
(3,648,465)
8,600,867
298,142
573,075

10,739,114
191,112
(3,366,440)
7,563,786
298,182
283,542

169,532
243,240

72,045
151,011

160,008
$ 11,524,161 $

113,353
9,679,102

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 STOCKHOLDERS' EQUITY

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 ................................................................................................................
Deferred revenue ........................................................................................................................
Other liabilities ...........................................................................................................................
Stockholders' equity:
Common stock, $.01 par value; 500,000,000 shares authorized; 133,121,092 and
126,212,256 shares issued at December 31, 2011 and 2010, respectively ...........................
Additional paid-in capital ........................................................................................................
Treasury stock, at cost: 11,264,936 and 10,903,743 shares at December 31, 2011
and 2010, respectively .........................................................................................................
Retained earnings .....................................................................................................................
Accumulated other comprehensive income (loss) - net deferred hedge gains (losses),
net of tax ..............................................................................................................................
Total stockholders' equity attributable to common stockholders......................................
Noncontrolling interest in consolidating subsidiaries ..............................................................
Total stockholders' equity ................................................................................................
Commitments and contingencies

December 31,

2011

2010

647,455 $
68,756
57,240
9,788
-
75,901

74,415
42,069
36,174
1,011,798

354,890
64,260
59,008
19,168
1,144
108,592

80,997
44,951
36,210
769,220

2,528,905
33,561
2,077,164
-
221,595

2,601,670
56,574
1,751,310
42,069
232,234

1,331
3,613,808

1,262
3,022,768

(458,281)
2,335,066

(421,235)
1,510,427

(3,130)
5,488,794
162,344
5,651,138

7,361
4,120,583
105,442
4,226,025

$ 11,524,161 $

9,679,102

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,
2010

2009

2011

Revenues and other income:
Oil and gas ............................................................................................................ $ 2,294,063
101,960
Interest and other ..................................................................................................
392,752
Derivative gains (losses), net .................................................................................
(3,644)
Gain (loss) on disposition of assets, net .................................................................
1,454
Hurricane activity, net ............................................................................................
2,786,585

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 ......................................................................................................................

453,085
147,664
607,405
354,408
121,320
193,215
8,256
181,660
63,166
2,130,179

Income (loss) from continuing operations before income taxes .................................
Income tax benefit (provision) ...................................................................................
Income (loss) from continuing operations .................................................................
Income from discontinued operations, net of tax .......................................................
Net income (loss) .......................................................................................................
Net income attributable to noncontrolling interests ...............................................
Net income (loss) attributable to common stockholders ............................................ $

656,406
(197,644)
458,762
423,152
881,914
(47,425)
834,489

Basic earnings per share:
Income (loss) from continuing operations attributable to common stockholders ... $
Income from discontinued operations attributable to common stockholders .........
Net income (loss) attributable to common stockholders ........................................ $

Diluted earnings per share:
Income (loss) from continuing operations attributable to common stockholders ... $
Income from discontinued operations attributable to common stockholders .........
Net income (loss) attributable to common stockholders ........................................ $

Weighted average shares outstanding:
Basic .....................................................................................................................
Diluted ..................................................................................................................

Amounts attributable to common stockholders:
Income (loss) from continuing operations, net of tax ............................................. $
Discontinued operations, net of tax ........................................................................
Net income (loss) ................................................................................................... $

3.45
3.56
7.01

3.39
3.49
6.88

$ 1,718,297
56,972
448,434
19,074
138,918
2,381,695

$ 1,402,436
101,589
(195,557)
(774)
(17,313)
1,290,381

364,764
112,141
499,856
-
189,597
164,332
7,945
183,084
78,404
1,600,123

345,885
98,371
564,149
21,091
79,095
130,863
8,050
173,353
94,702
1,515,559

781,572
(269,627)
511,945
134,050
645,995
(40,787)
605,208

4.00
1.14
5.14

3.96
1.12
5.08

(225,178)
83,195
(141,983)
99,716
(42,267)
(9,839)
(52,106)

(1.33)
0.87
(0.46)

116,904
119,215

115,062
116,330

114,176
114,176

411,337
423,152
834,489

471,158
134,050
605,208

(151,822)
99,716
(52,106)

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

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in thousands)

Year Ended December 31,
2010

2011

2009

Net income (loss) ................................................................................................... $

881,914 $

645,995 $

(42,267)

Other comprehensive activity:
Hedge fair value changes, net ........................................................................
Net hedge gains included in continuing operations ........................................
Income tax provision ......................................................................................
Other comprehensive activity .....................................................................
Comprehensive income (loss) ................................................................................
Comprehensive (income) loss attributable to the noncontrolling interests .........
Comprehensive income (loss) attributable to common stockholders ..................... $

-
(32,636)
8,407
(24,229)
857,685
(33,687)
823,998 $

-
(84,877)
23,648
(61,229)
584,766
(23,206)
561,560 $

12,974
(114,231)
50,059
(51,198)
(93,465)
9,424
(84,041)

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

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7
7

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)

Cash flows from operating activities:
Net income (loss) ........................................................................................................ $
Adjustments to reconcile net income (loss) to net cash provided by
operating activities:
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 ..................................................
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:
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 .....................................................................
Borrowings (payments) of other liabilities ..................................................................
Exercise of long-term incentive plan stock options and employee stock purchases....
Purchase of treasury stock ..........................................................................................
Excess tax (costs) benefits from share-based payment arrangements .........................
Payment of financing fees ...........................................................................................
Dividends paid ............................................................................................................
Net cash provided by (used in) financing activities ...........................................
Net increase (decrease) in cash and cash equivalents ....................................................
Cash and cash equivalents, beginning of period ............................................................
Cash and cash equivalents, end of period ...................................................................... $

Year Ended December 31,
2010

2011

2009

881,914 $

645,995 $

(42,267)

607,405
354,408
47,231
-
188,579
3,644
8,256
(376,717)
31,483
(221,899)
41,442
(44,951)
(22,412)

(47,331)
29,406
(137,401)
(3,415)
1,957
136,296
(1,768)
(7,623)
61,210
1,529,714

499,856
-
132,772
4,508
259,763
(19,074)
7,945
77,158
30,472
(419,809)
39,854
(90,216)
25,102

36,653
(5,878)
(26,281)
(3,874)
(14,270)
128,927
11,999
4,007
(40,586)
1,285,023

564,149
21,091
37,375
19,850
(72,042)
774
8,050
38,386
27,996
75,633
37,638
(147,905)
30,623

16,293
36,030
(46,708)
(3,387)
87,642
(65,862)
3,762
13,793
(97,855)
543,059

819,044
(89,620)
(1,926,965)
(363,246)
(1,560,787)

313,780
(72,864)
(1,011,442)
(184,330)
(954,856)

51,600
-
(437,240)
(25,345)
(410,985)

196,616
(294,883)
484,160
122,976
-
(26,702)
(901)
3,696
(40,355)
31,087
(8,741)
(9,556)
457,397
426,324
111,160
537,484 $

292,342
(475,252)
-
-
1,151
(26,837)
(21,329)
7,375
(14,039)
(153)
(145)
(9,488)
(246,375)
83,792
27,368
111,160 $

1,015,842
(1,175,703)
-
60,983
150
(20,012)
486
8,506
(21,921)
1
(12,005)
(9,370)
(153,043)
(20,969)
48,337
27,368

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

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

NOTE A. Organization and Nature of Operations

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

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 2010 and 2009 financial statement and footnote amounts in

order to conform to the 2011 presentations.

Discontinued operations. During December 2011, the Company committed to a plan to sell all of the assets
and liabilities of its South Africa operations ("Pioneer South Africa"). The plan is expected to result in the sale of
Pioneer South Africa during 2012. In accordance with GAAP, the Company has classified the Pioneer South Africa
assets and liabilities as discontinued operations held for sale in the Company's accompanying consolidated balance
sheet as of December 31, 2011, and Pioneer South Africa's results of operations as income from discontinued
operations, net of tax in the accompanying consolidated statements of operations.

During December 2010, the Company committed to a plan to divest the capital stock of the Company's
Tunisian subsidiaries ("Pioneer Tunisia"), which owned all of the Company's oil and gas properties in Tunisia. The
Company completed the sale of Pioneer Tunisia during February 2011. Accordingly, the Company classified the
assets and liabilities of Pioneer Tunisia as discontinued operations held for sale in the accompanying consolidated
balance sheet as of December 31, 2010. The results of operations of Pioneer Tunisia are reported as income from
discontinued operations, net of tax in the accompanying consolidated statements of operations.

During 2009, the Company sold its oil and gas properties in Mississippi and substantially all of its shelf
properties in the Gulf of Mexico. The Company classified the results of operations attributable to these divestitures as
discontinued operations, net of tax in the accompanying consolidated statement of operations.

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;
commodity price outlooks; foreign laws, restrictions and currency exchange rates; and export and excise taxes. Actual
results could differ from the estimates and assumptions utilized.

Cash equivalents. The Company's 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, 2011 and 2010, the Company had accounts receivable – trade, net of
allowances for bad debts, of $276.0 million and $237.5 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, 2011 and 2010, the Company's allowances for doubtful accounts totaled $1.1 million and
$3.7 million, respectively. The Company establishes allowances for bad debts equal to the estimable portions of

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

accounts and notes receivables for which failure to collect is considered probable. The Company estimates the
portions of joint interest receivables for which failure to collect is probable based on percentages of joint interest
receivables that are past due. The Company estimates the portions of other receivables for which failure to collect is
probable based on the relevant facts and circumstances surrounding the receivable. Allowances for doubtful accounts
are recorded as reductions to the carrying values of the receivables included in the Company's consolidated balance
sheets and as charges to other expense in the consolidated statements of operations in the accounting periods during
which failure to collect an estimable portion is determined to be probable.

Year Ended December 31,

2011

2010

(in thousands)

Beginning allowance for doubtful accounts balance ........................................................................ $
Amount credited to costs and expenses, net .................................................................................
Other net decreases ......................................................................................................................

3,674 $
(1,693)
(835)

14,299
(442)
(10,183)

Ending allowance for doubtful accounts balance ............................................................................. $

1,146 $

3,674

Investments. Investments in unaffiliated equity securities that have a readily determinable fair value are
classified as "trading securities" if management's current intent is to hold them for the near term; otherwise, they are
accounted for as "available-for-sale" securities. The Company reevaluates the classification of investments in
unaffiliated equity securities at each balance sheet date. The carrying value of trading securities and available-for-sale
securities are adjusted to fair value as of each balance sheet date and are included in other noncurrent assets in the
accompanying balance sheets.

Unrealized holding gains are recognized for trading securities in interest and other income, and unrealized

holding losses are recognized in other expense during the periods in which changes in fair value occur.

Unrealized holding gains and losses are recognized for available-for-sale securities as credits or charges to
stockholders' equity and other comprehensive income (loss) during the periods in which changes in fair value occur.
Realized gains and losses on the divestiture of available-for-sale securities are determined using the average cost
method. The Company had no investments in available-for-sale securities as of December 31, 2011 or 2010.

Investments in unaffiliated equity securities that do not have a readily determinable fair value are measured at
the lower of their original cost or the net realizable value of the investment. The Company had no significant equity
security investments that did not have a readily determinable fair value as of December 31, 2011 or 2010.

Noncontrolling interest in consolidated subsidiaries. At December 31, 2011, the Company owns a 0.1 percent
general partner interest and a 52.4 percent limited partner interest in Pioneer Southwest Energy Partners L.P.
("Pioneer Southwest"). Pioneer Southwest owns interests in certain oil and gas properties previously owned by the
Company in the Spraberry field in the Permian Basin of West Texas. The financial position, results of operations, and
cash flows of Pioneer Southwest are consolidated with those of the Company. 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 new
common units. The common unit sale resulted in the Company's limited ownership 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.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

The following table presents the Company's net income (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 during the years ended December 31, 2011 and 2009:

Net income (loss) attributable to common stockholders ............................... $
Transfers from the noncontrolling interest in consolidated subsidiaries:

Increase in additional paid in capital for Pioneer Southwest offering
of 3.1 million common units issued on November 16, 2009 ....................

Increase in additional paid in capital for the sale of 1.8 million
Pioneer Southwest common units on December 12, 2011, net of tax
of $15.4 million ........................................................................................

Increase in additional paid in capital for Pioneer Southwest offering
of 2.6 million common units issued on December 12, 2011, net of
tax of $23.7 million ...................................................................................

Net transfers from noncontrolling interest ................................................

Year Ended December 31,
2010

2011

2009

(in thousands)

834,489 $

605,208 $

(52,106)

26,915

8,104

35,019

33,388

Net income (loss) attributable to common stockholders and transfers
from noncontrolling interest ......................................................................... $

869,508 $

605,208 $

(18,718)

During January 2010, Pioneer Natural Resources USA, Inc. ("PNR USA," a wholly-owned subsidiary of the
Company) formed Sendero Drilling Company, LLC ("Sendero"). Sendero was formed to own and operate land-based
drilling rigs in the United States. As of December 31, 2011, Sendero owned 15 drilling rigs operating under contract
to PNR USA in the Spraberry field. PNR 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 $162.3 million and $105.4 million as of
December 31, 2011 and 2010, respectively. The Company recorded net income attributable to the noncontrolling
interests of $47.4 million, $40.8 million and $9.8 million for the years ended December 31, 2011, 2010 and 2009
(principally related to Pioneer Southwest), respectively.

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
area of South Texas. During June 2010, the Company sold a 49.9 percent member interest in EFS Midstream to an
unaffiliated third party for $46.4 million of cash proceeds. Associated therewith, the Company recorded a $46.2
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.

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 old
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 in the Company's accompanying consolidated statement of
operations.

See Note L for a detail of the Company's equity interest in the net income (loss) of EFS Midstream for the years

ended December 31, 2011 and 2010.

Inventories. Inventories were comprised of $297.9 million and $183.4 million of materials and supplies and
$4.5 million and $3.9 million of commodities as of December 31, 2011 and 2010, respectively. The Company's
materials and supplies inventory is primarily comprised of oil and gas drilling or repair items such as tubing, casing,

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

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. As of December 31, 2011 and 2010,
the Company's materials and supplies inventory was net of $0.9 million and $3.6 million, respectively, of valuation
reserve allowances. As of December 31, 2011 and 2010, the Company estimated that $60.8 million and $13.7 million,
respectively, of its materials and supplies inventory would not be utilized within one year. Accordingly, those
inventory values have been classified as other noncurrent assets in the accompanying consolidated balance sheets as
of December 31, 2011 and 2010. At December 31, 2010, the Company had inventory totaling $13.6 million classified
as discontinued operations held for sale in the accompanying consolidated balance sheets, representing the inventory
of Tunisia. At December 31, 2011, the Company had no inventory balance related to Pioneer South Africa.

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 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.

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:

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 the 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 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
proved reserves to sanction the project or is noncommercial and is charged to exploration and abandonments expense.
See Note C 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 operates
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,
2011, 2010 and 2009 were $46.0 million, $34.0 million and $26.5 million, respectively. Third party expenses

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

attributable to the processing plants and treating facilities for the same respective periods were $22.7 million, $14.3
million and $13.7 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.

Capitalized costs relating to 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 such time as 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 the 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 reviews 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. Estimates of the sum of expected future cash flows requires management to estimate future recoverable proved
and risk-adjusted probable and possible reserves, and forecast future commodity prices ("Management's Price
Outlook"), production timing, drilling and production cost estimates and discount rates. Management's Price Outlooks
represent longer-term outlooks that are developed based on observable third-party futures price outlooks as of a
measurement date. Uncertainties about these future cash flow variables cause impairment estimates to be inherently
imprecise. See Note R for additional information regarding the Company's impairment assessments.

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.

Goodwill. During 2004, the Company recorded $327.8 million of goodwill associated with a business
combination. The goodwill was recorded to the Company's United States reporting unit. The Company has reduced
goodwill by $29.7 million since the date of the business combination. The Company reduced the carrying value of
goodwill by $10.6 million and $1.3 million during 2010 and 2009, respectively, as a charge to the gain from the sale
of a portion of its United States reporting unit. The remaining $17.8 million reduction in goodwill was primarily for
tax benefits associated with the exercise of fully-vested stock options assumed in conjunction with the business
combination. 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 2011, the Company performed its annual assessment of goodwill for impairment and determined that there
was no impairment. See Note R for additional information regarding the Company's impairment assessments.

Other property and equipment, net. Other property and equipment is recorded at cost. At December 31, 2011
and 2010, respectively, the net carrying value of other property and equipment consisted of $160.8 million and $78.1
million of owned land and buildings, $326.0 million and $155.9 million of heavy equipment and rigs, including
drilling rigs, well servicing rigs and fracture stimulation equipment, $28.1 million and $12.9 million of transportation
equipment, $34.6 million and $22.3 million of furniture and fixtures, $20.5 million and $14.3 million of leasehold
improvements and $3.1 million and nil of other well servicing equipment. At December 31, 2011 and 2010, other
property and equipment was net of accumulated depreciation of $297.5 million and $235.3 million, respectively.

The Company's heavy equipment and rigs include assets owned by subsidiaries that provide pumping and well
services on Company-operated properties. The primary purposes of the Company's pumping and well services

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

operations are to accommodate the Company's drilling and producing operations by increasing the availability of
equipment and services, rather than being limited to third-party availability, and to contain services costs. As of
December 31, 2011, the Company owns 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 pumping and well
services operations are eliminated. Earnings from providing pumping and well services to third-party working interest
owners in Company-operated properties are included in interest and other income in the accompanying consolidated
statements of operations.

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, 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.

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. Conditional asset retirement
obligations meet the definition of liabilities and are recognized when incurred if their fair values can be reasonably
estimated.

Asset retirement obligation expenditures are classified as cash used in operating activities in the accompanying

consolidated statements of cash flows.

Derivatives and hedging. 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 are
included in accumulated other comprehensive income (loss) – net deferred hedge gains (losses), net of tax ("AOCI -
Hedging") and are being transferred to earnings during the same periods in which the forecasted hedged transactions
are recognized in the Company's earnings. Since February 1, 2009, the Company has recognized 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 225 basis points, representing Pioneer Southwest's estimated
borrowing rate.

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 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.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

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.

Issuance of common stock. In November 2011, the Company issued 5.5 million shares of its common stock

and realized $484.2 million of proceeds, net of associated offering costs.

Revenue recognition. The Company does not recognize revenues until they are 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, natural gas liquids ("NGL") 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 entitlement assets or NGL entitlement assets or liabilities as of December 31,
2011 or 2010. The following table presents the Company's oil entitlement liabilities and gas entitlement assets and
liabilities with their associated volumes as of December 31, 2011 and 2010:

December 31,

2011

2010

Amount Volume Amount Volume
(dollars in millions)

Oil entitlement liabilities (volumes in MBbls) ........................................................... $
Gas entitlement assets (volumes in MMcf) ................................................................ $
Gas entitlement liabilities (volumes in MMcf) .......................................................... $

-
7.6
2.6

- $
3,024 $
650 $

1.2
7.6
1.6

13
3,015
439

Stock-based compensation. For stock-based compensation awards granted or modified, 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 vest over a period not
exceeding three years. The amount of compensation expense recognized at any date is at least equal to the portion of
the grant date value of the award that is vested at that date. The Company utilizes (i) the Black-Scholes option pricing
model to measure the fair value of stock options, (ii) the prior day's closing stock price on the date of grant for the fair
value of restricted stock, 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 compensation expense.

New accounting pronouncements. Effective December 31, 2009, the Company adopted the SEC's final rule
on "Modernization of Oil and Gas Reporting" (the "Reserve Ruling") and the Financial Accounting Standards Board's
(the "FASB") Accounting Standards Update ("ASU") 2010-03, which conforms Accounting Standards Codification
("ASC") 932 to the Reserve Ruling. The Reserve Ruling revises oil and gas reporting disclosures, permits the use of
new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to
reliable conclusions about reserves volumes and allows companies the option to disclose probable and possible oil and
gas reserves. In addition, the new disclosure requirements require companies to: (i) report the independence and
qualifications of its reserves preparer or auditor, (ii) file reports when a third party is relied upon to prepare reserves
estimates or conduct a reserves audit and (iii) report oil and gas reserves using an average price based upon the prior

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

12-month period rather than a period-end price. See Unaudited Supplementary Information for information regarding
the adoption of the Reserve Ruling and ASU 2010-03.

During December 2010, the FASB issued ASU 2010-28, "When to Perform Step 2 of the Goodwill Impairment
Test for Reporting Units with Zero or Negative Carrying Amounts." ASU No. 2010-28 modifies step one of the
goodwill impairment test for reporting units with zero or negative carrying amounts, requiring that an entity perform
step two of the goodwill impairment test if it is more likely than not that a goodwill impairment exists for those
reporting units. ASU No. 2010-28 became effective and was adopted by the Company on January 1, 2011. The
adoption of ASU No. 2010-28 did not have an impact on the goodwill impairment test performed by the Company.

In May 2011, the FASB issued ASU 2011-04, "Amendments to Achieve Common Fair Value Measurements
and Disclosure Requirements in U.S. GAAP and IFRSs." ASU 2011-04 amended Accounting Standards Codification
("ASC") 820 to converge the fair value measurement guidance in GAAP and International Financial Reporting
Standards. Certain of the amendments clarify the application of existing fair value measurement requirements, while
other amendments change a particular principle in ASC 820. In addition, ASU 2011-04 requires additional fair value
disclosures. The amendments will be applied prospectively and are effective for annual periods beginning after
December 15, 2011. The Company does not believe the adoption of this guidance will have a material impact on its
future financial position, results of operation or liquidity.

In September 2011, the FASB issued ASU No. 2011-08, "Testing Goodwill for Impairment." ASU 2011-08
amends ASC 350 to permit an entity to first assess qualitative factors to determine whether it is more likely than not
that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary
to perform the two-step goodwill impairment test. The more-likely-than-not threshold is defined as having a
likelihood of more than 50 percent. ASU 2011-08 is effective for annual and interim goodwill impairment tests
performed for fiscal years beginning after December 15, 2011. The adoption of ASU 2011-08 will not have a material
impact on the future carrying value of the Company's goodwill. See "Goodwill" above for more information about the
Company's policy for assessing goodwill for impairment.

During December 2011, the FASB issued ASU 2011-11, "Disclosures about offsetting Assets and Liabilities"
requiring additional disclosure about offsetting and related arrangements. ASU 2011-11 is effective retrospectively
for annual reporting periods beginning on or after January 1, 2013. The adoption of ASU 2011-11 will not impact the
Company's future financial position, results of operation or liquidity.

NOTE C. Exploratory Well Costs

The Company's capitalized exploratory well and project costs are presented in proved properties in the
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, 2011, 2010 and 2009:

Beginning capitalized exploratory well costs ................................................................ $
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 expense (a) ........................................
Ending capitalized exploratory well costs ..................................................................... $
_____________
(a)

Includes an exploratory well credit included in discontinued operations of $117 thousand in 2010, and
exploratory well costs included in discontinued operations of $9.9 million in 2009.

Year Ended December 31,
2010

2009

2011

(in thousands)

96,193 $
524,313
(480,716)
(28,938)
(3,256)
107,596 $

127,574 $
238,905
(160,879)
(17,601)
(91,806)
96,193 $

124,014
80,222
(58,792)
-
(17,870)
127,574

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

During the fourth quarter of 2010, the Company determined that further appraisal drilling in its Cosmopolitan
Unit in the Cook Inlet of Alaska would not be funded based on the project's limited impact to the Company's future
Alaskan and overall growth profile. As a result, an exploration and abandonment charge of $97.7 million was
recorded in the fourth quarter of 2010 to write off the Cosmopolitan project's carrying value. Included in the write off
was suspended well costs of $76.0 million, $14.3 million of acreage costs, $6.4 million of estimated property
abandonment costs and $1.0 million of inventory impairment charges to reduce the carrying value of its pipe
inventory to its resale value.

The following table provides an aging, as of December 31, 2011, 2010 and 2009 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:

Year Ended December 31,
2010

2009

2011

(in thousands, except well counts)

Capitalized exploratory well costs that have been suspended:
One year or less ................................................................................................... $
More than one year ...............................................................................................

107,596 $
-

70,635 $
25,558

21,634
105,940

107,596 $

96,193 $

127,574

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

NOTE D. Disclosures About Fair Value Measurements

In accordance with GAAP, fair value measurements are based upon inputs that market participants use in
pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs.
Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a
company's own market assumptions, which are used if observable inputs are not reasonably available without undue
cost and effort. These two types of inputs are further prioritized into the following fair value input hierarchy:

Level 1 – quoted prices for identical assets or liabilities in active markets.
Level 2 – quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar
assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset
or liability (e.g. interest rates) and inputs derived principally from or corroborated by observable market data by
correlation or other means.

Level 3 – unobservable inputs for the asset or liability.

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.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

The following tables present the Company's assets and liabilities that are measured at fair value on a recurring

basis as of December 31, 2011 and 2010 for each of the fair value hierarchy levels:

Fair Value Measurements at Reporting Date Using
Significant
Significant Other
Unobservable
Observable
Inputs
Inputs
(Level 3)
(Level 2)

Quoted Prices in
Active Markets for
Identical Assets
(Level 1)

Fair Value at
December 31,
2011

Assets:
Trading securities ............................................ $
Commodity derivatives ...................................
Deferred compensation plan assets .................
Total assets.................................................. $

Liabilities:
Commodity derivatives ................................... $
Interest rate derivatives ...................................
Liability Awards .............................................
Total liabilities ............................................ $

257 $
-
39,904
40,161 $

- $
-
9,207
9,207 $

(in thousands)

168 $

482,075
-

482,243 $

92,322 $
15,654
-

107,976 $

- $
-
-
- $

425
482,075
39,904
522,404

92,322
15,654
9,207
117,183

Fair Value Measurements at Reporting Date Using
Significant
Significant Other
Unobservable
Observable
Inputs
Inputs
(Level 3)
(Level 2)

Quoted Prices in
Active Markets for
Identical Assets
(Level 1)

Fair Value at
December 31,
2010

Assets:
Trading securities ............................................ $
Commodity derivatives ...................................
Interest rate derivatives ...................................
Deferred compensation plan assets .................
Total assets................................................. $

316 $
-
-
36,162
36,478 $

- $
-
4,900
4,900 $

(in thousands)

151 $

304,434
18,256
-

322,841 $

127,311 $
704
-

128,015 $

- $
-
-
-
- $

9,556 $
-
-
9,556 $

467
304,434
18,256
36,162
359,319

136,867
704
4,900
142,471

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

The following table presents the changes in the fair values of the Company's net commodity derivative

liabilities classified as Level 3 in the fair value hierarchy for the year ended December 31, 2011:

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)

Year Ended
December 31,
2011
(in thousands)

Beginning liability balance ........................................................................................................................ $
Fair value changes (a):
Net unrealized gains included in earnings..............................................................................................
Net realized losses included in earnings ................................................................................................
Settlement payments ..................................................................................................................................
Transfers out of Level 3 (b) .......................................................................................................................
Ending liability balance ............................................................................................................................. $
_____________
(a) Changes in fair value are included in derivative gains (losses), net in the accompanying consolidated statements of

188
(11,803)
11,803
9,368
-

(9,556)

(b)

operations.
The values related to NGL swap and collar contracts were transferred from Level 3 to Level 2 as a result of the Company's
ability to obtain independent market-quoted NGL data. The Company recognized the transfer between Level 3 and Level 2
at the end of the reporting period of transfer.

The following table presents the carrying amounts and fair values of the Company's financial instruments as of

December 31, 2011 and 2010:

Carrying

December 31, 2011
Fair
Value

Value

Carrying

December 31, 2010
Fair
Value

Value

Assets:
Commodity price derivatives .......................................... $
Interest rate derivatives ................................................... $
Trading securities .......................................................... $
Deferred compensation plan assets ................................. $
Liabilities:
Commodity price derivatives .......................................... $
Interest rate derivatives ................................................... $
Liability Awards ............................................................. $
Pioneer credit facility ..................................................... $
Pioneer Southwest credit facility .................................... $
5.875 % senior notes due 2016 ...................................... $
6.65 % senior notes due 2017 ......................................... $
6.875 % senior notes due 2018 ...................................... $
7.50 % senior notes due 2020 ........................................ $
7.20 % senior notes due 2028 ........................................ $
2.875% convertible senior notes due 2038 (a) ................ $

(in thousands)

482,075 $
- $
425 $
39,904 $

304,434 $
18,256 $
467 $
36,162 $

92,322 $
15,654 $
9,207 $
- $
32,000 $
405,388 $
484,185 $
449,225 $
446,716 $
249,928 $
461,463 $

92,322 $
15,654 $
9,207 $
- $
32,393 $
488,445 $
546,931 $
505,688 $
523,373 $
269,125 $
739,630 $

136,867 $
704 $
4,900 $
49,000 $
81,200 $
396,880 $
484,045 $
449,192 $
446,433 $
249,925 $
444,994 $

304,434
18,256
467
36,162

136,867
704
4,900
58,382
77,241
475,194
516,632
480,969
494,145
259,350
728,400

__________
(a) The fair value of the 2.875% convertible senior notes includes the fair value of the conversion privilege.

Trading securities and deferred compensation plan assets. The Company's trading securities are comprised of
securities that are 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. As
of December 31, 2011, all significant inputs to these exchange-traded asset values represented Level 1 independent
active exchange market price inputs except inputs for certain trading securities that are not actively traded on major
exchanges, which were provided by broker quotes representing Level 2 inputs.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

Interest rate derivatives. The Company's interest rate derivative assets and liabilities as of December 31, 2011
represent interest rate swap contracts that, at their inception, locked in a fixed forward 10-year annual rate of 3.06
percent on $200 million notional amount of debt for a period of one year. The Company's interest rate derivative
assets and liabilities as of December 31, 2010 represent (i) swap contracts for $189 million notional amount of debt
whereby the Company pays a fixed rate of interest and the counterparty pays a variable LIBOR-based rate and
(ii) swap contracts for $470 million notional amount of debt, respectively, whereby the Company pays a variable
LIBOR-based rate and the counterparty pays a fixed rate of interest. During July 2011, the Company terminated $470
million notional amount of fixed-for-variable interest rate derivative contracts and received $26.1 million of cash
proceeds.

The net derivative asset and liability values attributable to the Company's interest rate derivative contracts as of
December 31, 2011 and 2010 were determined based on (i) the contracted notional amounts, (ii) LIBOR rate yield
curves provided by counterparties and corroborated with forward active market-quoted LIBOR rate yield curves and
(iii) the applicable credit-adjusted risk-free rate yield curve. The Company's interest rate derivative asset and liability
measurements represent Level 2 inputs in the hierarchy priority.

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

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

As of December 31, 2011, the Company is also party to ''roll adjustment'' swap derivatives to mitigate the
timing risk associated with the sales price of oil in the Permian Basin. The asset value attributable to the Company's
roll adjustment swaps as of December 31, 2011, of $181 thousand, was determined based on (i) the contracted
notional volumes, (ii) independent active NYMEX futures price quotes for WTI oil and (iii) the applicable estimated
credit-adjusted risk-free rate yield curve.

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

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

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

Diesel derivatives. The Company's diesel derivatives are swap contracts for notional Bbls posted as Gulf Coast
Ultra Low Sulfur (Pipeline) diesel by a posting service. The asset and liability values attributable to the Company's
diesel derivatives were determined based on (i) the contracted notional volumes, (ii) independent active market-quoted
diesel prices and (iii) the applicable credit-adjusted risk-free rate yield curve.

Liability Awards. The fair values of the Company's Liability Awards are updated each balance sheet date based

on the closing stock price on the balance sheet date.

Credit facility. The fair values of the Company's credit facility and Pioneer Southwest's credit facility are based
on (i) forecasted contractual interest and fee payments, (ii) forward active market-quoted LIBOR rate yield curves and
(iii) the applicable credit-adjusted risk-free rate yield curve.

Senior notes. The Company's senior notes represent debt securities that are 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.

Concentrations of credit risk. As of December 31, 2011, 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 B for information regarding the Company's accounts receivable – trade and Note J 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 I for additional
information regarding the Company's derivative activities and Note J for information regarding derivative assets and
liabilities by counterparty.

NOTE E. Long-term Debt

Long-term debt, including the effects of net deferred fair value hedge losses and issuance discounts and

premiums, consisted of the following components at December 31, 2011 and 2010:

December 31,

2011

2010

(in thousands)

Outstanding debt principal balances:
Pioneer credit facility ....................................................................................................................... $
Pioneer Southwest credit facility .....................................................................................................
5.875% senior notes due 2016 ........................................................................................................
6.65% senior notes due 2017 ...........................................................................................................
6.875 % senior notes due 2018 .......................................................................................................
7.500 % senior notes due 2020 ........................................................................................................
7.20% senior notes due 2028 ..........................................................................................................
2.875% convertible senior notes due 2038.......................................................................................

49,000
81,200
455,385
485,100
449,500
450,000
250,000
480,000
2,700,185
(96,515)
Issuance discounts and premiums, net ................................................................................................
Net deferred fair value hedge losses ....................................................................................................
(2,000)
Total long-term debt ........................................................................................................................... $ 2,528,905 $ 2,601,670

32,000
455,385
485,100
449,500
450,000
250,000
479,930
2,601,915
(71,301)
(1,709)

- $

Credit Facility. During March 2011, the Company entered into a Second Amended and Restated 5-Year
Revolving Credit Agreement (the "Credit Facility") with a syndicate of financial institutions that matures in March
2016, unless extended in accordance with the terms of the Credit Facility. The Credit Facility replaces the Company's
Amended and Restated 5-Year Revolving Credit Agreement entered into in April 2007 (the "Expired Credit Facility")
and provides for aggregate loan commitments of $1.25 billion. As of December 31, 2011, the Company had no
outstanding borrowings under the Credit Facility and $65.1 million of undrawn letters of credit, all of which were

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

commitments under the Credit Facility, leaving the Company with $1.2 billion of unused borrowing capacity under
the Credit Facility.

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 0.75 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
1.75 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 0.325 percent).

The Credit Facility contains certain financial covenants, which include the maintenance of a ratio of total debt
to book capitalization less intangible assets, accumulated other comprehensive income and certain noncash asset
impairments not to exceed .60 to 1.0. In November 2011, the Company achieved an investment grade rating with one
of the credit rating agencies. As such, in accordance with the financial covenants of the Credit Facility, the
requirement of the Company to maintain a ratio of the net present value of the Company's oil and gas properties to
total debt of at least 1.75 to 1.0 has been permanently deleted. As of December 31, 2011, the Company was in
compliance with all of its debt covenants.

In accordance with GAAP, the Company accounted for the entry into the Credit Facility as an extinguishment
of the Expired Credit Facility. Associated therewith, the Company recorded a $2.4 million loss on extinguishment of
debt to write off the unamortized issuance costs of the Expired Credit Facility, which is included in other expense in
the accompanying consolidated statement of operations for the year ended December 31, 2011 (see Note N).

In May 2008, Pioneer Southwest entered into a $300 million unsecured revolving credit facility with a syndicate
of financial institutions, which matures in May 2013 (the "Pioneer Southwest Credit Facility"). As of December 31,
2011, there were $32.0 million of outstanding borrowings under the Pioneer Southwest Credit Facility. The Pioneer
Southwest Credit Facility is available for general partnership purposes, including working capital, capital expenditures
and distributions. Borrowings under the Pioneer Southwest Credit Facility may be in the form of Eurodollar rate loans,
base rate committed loans or swing line loans. Eurodollar rate loans bear interest annually at LIBOR, plus a margin
(the "Applicable Rate") (currently 0.875 percent) that is determined by a reference grid based on Pioneer Southwest's
consolidated leverage ratio. Base rate committed loans bear interest annually at a base rate equal to the higher of
(i) the Federal Funds Rate plus 0.5 percent or (ii) the Bank of America prime rate (the "Base Rate") plus a margin
(currently zero percent). Swing line loans bear interest annually at the Base Rate plus the Applicable Rate.

The Pioneer Southwest Credit Facility contains certain financial covenants, including (i) the maintenance of a
quarter end maximum leverage ratio of not more than 3.5 to 1.00, (ii) an interest coverage ratio (representing a ratio of
earnings before depreciation, depletion and amortization; impairment of long-lived assets; exploration expense;
accretion of discount on asset retirement obligations; interest expense; income taxes; gain or loss on the disposition of
assets; noncash commodity hedge and derivative related activity; and noncash equity-based compensation to interest
expense) of not less than 2.5 to 1.0 and (iii) the maintenance of a ratio of the net present value of Pioneer Southwest's
projected future cash flows from its oil and gas properties to total debt of at least 1.75 to 1.0. As of December 31,
2011, Pioneer Southwest was in compliance with all of its debt covenants.

As of December 31, 2011, the borrowing capacity under the Pioneer Southwest Credit Facility was $268.0
million. However, because of the net present value covenant, Pioneer Southwest's borrowing capacity under the
Pioneer Southwest Credit Facility may be limited in the future. The variables on which the calculation of net present
value is based (including assumed commodity prices and discount rates) are subject to adjustment by the lenders. As a
result, if commodity prices decline in the future, it 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

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

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 other things, nonpayment of principal or interest, violations of covenants, bankruptcy and material judgments
and liabilities.

Pioneer Southwest pays a commitment fee on the undrawn amounts under the Pioneer Southwest Credit
Facility. The commitment fee is variable based on the Partnership's consolidated leverage ratio. For 2011, the
commitment fee was 0.175 percent.

Convertible senior notes. During January 2008, the Company issued $500 million of 2.875% Convertible
Senior Notes due 2038 (the "2.875% Convertible Notes"), of which $479.9 million remains outstanding at December
31, 2011.

The 2.875% Convertible Senior Notes are convertible under certain circumstances, using a net share settlement
process, into a combination of cash and the Company's common stock pursuant to a formula. The initial base
conversion price is approximately $72.60 per share (subject to adjustment in certain circumstances), which is
equivalent to an initial base conversion rate of 13.7741 common shares per $1,000 principal amount of convertible
notes. In general, upon conversion of a note, the holder of such note will receive cash equal to the principal amount of
the note and the Company's common stock for the 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 2.875% Convertible Senior Notes mature on January 15, 2038. The Company may redeem the 2.875%
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 2.875% Convertible Senior Notes may require the Company to
purchase their 2.875% 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. 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);

During five-day periods following defined circumstances when the trading price of the 2.875% 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 price during March 2011 caused the 2.875% Convertible Senior Notes to become
convertible at the option of the holders during the three months ended June 30, 2011. Associated therewith, certain
holders of the 2.875% Convertible Senior Notes tendered $70 thousand principal amount of the notes for conversion
during the three months ended June 30, 2011. During 2011, the Company paid the tendering holders a total of $71
thousand of cash and issued to the tendering holders 340 shares of the Company's common stock in accordance with
the terms of the 2.875% Convertible Senior Notes indenture supplement.

As of December 31, 2011, the Company's stock price performance did not qualify the 2.875% Convertible
Senior Notes for conversion at the option of the holders. However, if all of the 2.875% Convertible Senior Notes had
been convertible on December 31, 2011, the note holders would have received $479.9 million of cash and
approximately 1.9 million shares of the Company's common stock, which had a market value of $173.3 million as of
December 31, 2011.

Interest on the principal amount of the 2.875% 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 day price of a 2.875% Convertible Senior
Note for the five consecutive trading days immediately preceding the first day of the applicable six-month interest

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

period equals or exceeds $1,200, interest on the principal amount of the 2.875% Convertible Senior Notes will be
2.375% solely for the relevant interest period.

As of December 31, 2011 and 2010, the 2.875% Convertible Senior Notes had an unamortized discount of
$18.5 million and $35.0 million, respectively, and a net carrying value of $461.5 million and $445.0 million,
respectively. The unamortized discount is being amortized ratably through January 2013. For the years ended
December 31, 2011, 2010 and 2009, the Company recorded $32.3 million, $31.1 million and $29.9 million,
respectively, of interest expense relating to the 2.875% Convertible Senior Notes, which had an effective interest rate
of 6.75 percent. As of December 31, 2011 and 2010, $49.5 million is recorded in Additional Paid-in Capital as the
equity component of the 2.875% 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 senior convertible notes are structurally
subordinated to all obligations of its subsidiaries. Interest on the Company's senior notes and senior convertible notes
is payable semiannually.

Principal maturities. Principal maturities of long-term debt at December 31, 2011, are as follows (in

thousands):

2012 ............................................................................................................................................................................... $
-
511,930
2013 ............................................................................................................................................................................... $
-
2014 ............................................................................................................................................................................... $
-
2015 ............................................................................................................................................................................... $
2016 ............................................................................................................................................................................... $
455,385
Thereafter....................................................................................................................................................................... $ 1,634,600

The principal maturities during 2013 in the preceding table represent the 2.875% Convertible Senior Notes,

which are subject to repurchase at the option of the holders in 2013, and the Pioneer Southwest Credit Facility.

Interest expense. The following amounts have been incurred and charged to interest expense for the years

ended December 31, 2011, 2010 and 2009:

Year Ended December 31,
2010

2009

2011

(in thousands)

Cash payments for interest ........................................................................................ $
Accretion/amortization of discounts or premiums on loans ......................................
Accretion of discount on derivative obligations ........................................................
Accretion of discount on postretirement benefit obligations ......................................
Amortization of net deferred hedge losses (see Note I) ............................................
Amortization of capitalized loan fees .......................................................................
Net changes in accruals .............................................................................................
Interest incurred ........................................................................................................
Less capitalized interest ............................................................................................
Total interest expense ............................................................................................... $

165,307 $
25,210
-
315
573
5,385
(1,768)
195,022
(13,362)
181,660 $

155,854 $
23,304
521
433
517
5,698
11,999
198,326
(15,242)
183,084 $

151,246
21,388
874
657
465
4,612
3,762
183,004
(9,651)
173,353

NOTE F. 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.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

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, 2011, 2010 and 2009:

2011

Year Ended December 31,
2010
(in thousands)

2009

Receipt of lease operating and supervision charges in
accordance with standard industry operating agreements ..................................... $
Reimbursement of general and administrative expenses ............................................ $

2,104 $
313 $

2,184 $
344 $

2,224
265

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 2011 and 2010, the Company received $2.2 million and $1.1 million of fixed payments and $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
$21.3 million and $404 thousand of gathering and treating fees. Such amounts were expensed as oil and gas
production costs in the accompanying consolidated statements of operations during 2011 and 2010, respectively. See
Note H for additional information about commitments under the HGH Agreement.

NOTE G.

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 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 $2.2 million, $1.9 million and $1.7 million for the years ended December 31, 2011, 2010
and 2009, 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.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

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, 2011, 2010 and 2009, the Company recognized compensation expense of $18.3
million, $13.4 million and $11.8 million, respectively, as a result of Matching Contributions.

Compensation costs. In accordance with GAAP, the Company records 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 compensation expense recorded for each type of incentive award and the

associated income tax benefit for the years ended December 31, 2011, 2010 and 2009:

2011

Year Ended December 31,
2010
(in thousands)

2009

Restricted stock-equity awards (a) ......................................................................... $
Restricted stock-liability awards ............................................................................
Stock options (b) ....................................................................................................
Performance unit awards........................................................................................
Pioneer Southwest LTIP ........................................................................................
Sendero Series B units ...........................................................................................
ESPP ......................................................................................................................
Total ........................................................................................................................... $

32,861 $
10,882
2,936
4,500
761
1,020
125
53,085 $

31,712 $
4,900
1,522
4,635
475
1,020
1,034
45,298 $

31,929
-
629
4,868
217
-
907
38,550

Income tax benefit ..................................................................................................... $
_____________
(a) For the year ended December 31, 2010, 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 statement of operations for the year
ended December 31, 2010.

22,084 $

14,019 $

11,675

(b) Cash proceeds received from stock option exercises during 2011, 2010 and 2009 amounted to $619 thousand, $4.8

million and $6.6 million, respectively.

As of December 31, 2011, there was $69.5 million of unrecognized share-based compensation expense related
to unvested share and unit based compensation plans, including $19.7 million attributable to Liability Awards. The
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 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.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

The following table shows the number of shares available for issuance pursuant to awards under the Company's

LTIP at December 31, 2011:

Approved and authorized awards .................................................................................................................................
Awards issued after May 3, 2006..................................................................................................................................
Awards available for future grant ................................................................................................................................

9,100,000
(5,705,600)
3,394,400

Restricted stock awards. During 2011, the Company awarded 645,471 restricted shares or units of the
Company's common stock as compensation to directors, officers and employees of the Company (including 202,411
shares or units representing Liability Awards). The Company's issued shares, as reflected in the consolidated balance
sheets as of December 31, 2011 do not include 533,125 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, 2011:

Equity Awards

Liability Awards

Weighted
Average Grant-
Date Fair
Value

Number of
Shares

Number of Shares

Outstanding at beginning of year .............................................................
Shares granted .........................................................................................
Shares forfeited ......................................................................................
Shares vested ..........................................................................................

2,559,779 $
443,060 $
(63,105) $
(1,082,122) $

Outstanding at end of year .......................................................................

1,857,612 $

28.85
97.52
54.51
36.41

39.95

215,134
202,411
(23,953)
(70,667)

322,925

The weighted average grant-date fair value of restricted stock Equity Awards awarded during 2011, 2010 and
2009 was $97.52, $48.32 and $15.47, respectively. The fair value of shares for which restrictions lapsed during 2011,
2010 and 2009 was $98.6 million, $42.9 million and $11.7 million, respectively, based on the market price on the
vesting date.

As of December 31, 2011 and 2010, accounts payable – due to affiliates in the accompanying consolidated
balance sheet includes $9.2 million and $4.9 million of liabilities attributable to the Liability Awards, representing the
fair value of employee services rendered in consideration for the awards as of that date. There were no Liability
Awards issued or outstanding as of December 31, 2009. The fair value of shares for which restrictions lapsed during
2011 was $6.7 million, based on the market price on the vesting date.

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-Sholes option-pricing model. Option
awards have a 10 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 U.S. 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. The Company used the following weighted-average assumptions to estimate the fair value of stock options
granted during 2011, 2010 and 2009:

Expected option life – years ...........................................................................................
Volatility ........................................................................................................................
Risk-free interest rate .....................................................................................................
Dividend yield ...............................................................................................................

2011
7
47.6%
2.9%
0.4%

2010
7
46.8%
3.4%
0.4%

2009
7
43.0%
3.3%
1.9%

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

A summary of the Company's stock option awards activity for the year ended December 31, 2011 is presented

below:

Number of
Shares

Weighted
Average
Exercise Price

Weighted
Average
Remaining
Contractual
Life
(in years)

Aggregate
Intrinsic Value
(in thousands)

Nonstatutory stock options:
Outstanding at beginning of year ..............................
Options awarded .....................................................
Options expired and forfeited ..................................
Options exercised .....................................................
Outstanding and expected to vest at end of year .......

507,539 $
86,903 $
- $
(30,398) $
564,044 $

Exercisable at end of year ..........................................

26,905 $

23.11
98.69
-
20.36
34.90

22.64

8.10 $

7.63 $

30,786

1,798

The weighted average grant-date fair value of options awarded during 2011, 2010 and 2009 was $49.61, $23.79
and $6.27, respectively, using the Black-Sholes option-pricing model. The intrinsic value of options exercised during
2011, 2010 and 2009 was $1.5 million, $6.9 million and $3.1 million, respectively, based on the difference between
the market price at the exercise date and the option exercise price.

Performance unit awards. During 2011, 2010 and 2009, 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 2011, 2010 and 2009 performance unit awards are $134.68, $63.52 and $15.29,
respectively, which amounts were determined using the Monte Carlo simulation method and are being recognized as
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 U.S. 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 2011, 2010 and 2009:

2011

2010

2009

Risk-free interest rate ...........................................................
Range of volatilities .............................................................

1.32%
50.2% - 84.1%

1.36%
50.4% - 83.0%

1.33%
47.1% - 73.0%

The following table summarizes the performance unit activity for the year ended December 31, 2011:

Number of
Units (a)

Weighted Average
Grant-Date
Fair Value

263,729 $
43,495 $
(193,096) $
114,128 $

28.91
134.68
16.25
90.64

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, 2011, the service period lapsed on 178,289 of these performance unit awards. The lapsed units earned 2.5
shares for each vested award representing 445,724 aggregate shares of common stock issued in 2012. On May 31, 2011,
14,807 units lapsed as part of the Tunisian divesture and earned 2.5 shares for each vested award, representing 37,018 of
aggregate shares of common stock.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

The fair value of shares for which restrictions lapsed during 2011, 2010 and 2009 was $44.7 million, $27.4

million and $4.8 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 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 awards granted under the plan to
3.0 million common units.

The following table shows the number of awards available under the Pioneer Southwest LTIP at December 31,

2011:

Approved and authorized awards .....................................................................................................................................
Awards issued after May 6, 2008.....................................................................................................................................
Awards available for future grant ....................................................................................................................................

3,000,000
(106,252)
2,893,748

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 vest 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. During 2009, the General Partner awarded 12,909 restricted common units to directors of the
General Partner under the Pioneer Southwest LTIP, of which 2,038 units vest ratably over three years and 10,871 units
vested in May 2010.

Restricted Unit Awards
Weighted
Average
Grant-Date
Fair Value

Number of
Units

Phantom Unit Awards
Weighted
Average
Grant-Date
Fair Value

Number of
Units

Outstanding at beginning of year ..............................................
Units granted ............................................................................
Lapse of restrictions ................................................................
Outstanding at end of year .........................................................

12,212 $
6,812 $
(11,532) $
7,492 $

21.84
29.35
21.97
28.47

35,118 $
30,039 $
- $
65,157 $

22.74
32.16
-
27.08

The weighted average grant-date fair value of restricted common units awarded during 2011, 2010 and 2009
was $29.35, $22.87 and $18.26, respectively. The fair value of common units for which restrictions lapsed on the
restricted common units during 2011, 2010 and 2009 was $342 thousand, $324 thousand and $145 thousand,
respectively, based on the market price at the vesting date.

During 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 2011 and 2010 was $32.16 and 22.74, respectively. No phantom common units were awarded in
2009. 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.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

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.

The following table shows the number of shares available for issuance under the ESPP at December 31, 2011:

Approved and authorized shares ...................................................................................................................................
Shares issued ..................................................................................................................................................................

750,000
(625,003)

Shares available for future issuance ...............................................................................................................................

124,997

Postretirement Benefit Obligations

At December 31, 2011 and 2010, the Company had $7.5 million and $7.4 million, respectively, of unfunded
accumulated postretirement benefit obligations, the current and noncurrent portions of which are included in other
current liabilities and other liabilities, respectively, in the accompanying consolidated balance sheets. These
obligations are comprised of five plans of which four relate to predecessor entities that the Company acquired in prior
years. These plans had no assets as of December 31, 2011 or 2010. Other than the Company's retirement plan, the
participants of these plans are not current employees of the Company.

At December 31, 2011, the accumulated postretirement benefit obligations related to these plans were
determined by independent actuaries for four plans representing $4.6 million of unfunded accumulated postretirement
benefit obligations and by the Company for one plan representing $2.9 million of unfunded accumulated
postretirement benefit obligations. For the years ended December 31, 2011, 2010 and 2009, the undiscounted
accumulated post retirement benefit obligations were discounted at four percent, four percent and five percent to value
the benefit obligations. Certain of the aforementioned plans provide for medical cost subsidies for plan participants.
Annual medical cost escalation trends were employed to estimate the accumulated postretirement benefit obligations
associated with the medical cost subsidies. The Company forecasted a cost escalation trend of eight percent for 2012,
declining annually to seven percent in 2016 and five percent in 2025 and thereafter.

The following table reconciles changes in the Company's unfunded accumulated postretirement benefit

obligations during the years ended December 31, 2011, 2010 and 2009:

Year Ended December 31,
2010

2009

2011

(in thousands)

Beginning accumulated postretirement benefit obligations ........................................ $
Net benefit payments ..............................................................................................
Service costs ...........................................................................................................
Net actuarial losses (gains) ......................................................................................
Accretion of interest .................................................................................................
Ending accumulated postretirement benefit obligations ............................................. $

7,408 $
(1,323)
243
813
315
7,456 $

9,075 $
(1,491)
321
(930)
433
7,408 $

9,612
(1,430)
228
8
657
9,075

Estimated benefit payments and service/interest costs associated with the plans for the year ending December

31, 2012 are $854 thousand and $596 thousand, respectively.

100

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

Future postretirement benefits the Company expects to pay at December 31, 2011 are as follows (in thousands):

2012 .............................................................................................................................................................................. $
2013 .............................................................................................................................................................................. $
2014 .............................................................................................................................................................................. $
2015 .............................................................................................................................................................................. $
2016 .............................................................................................................................................................................. $
Thereafter....................................................................................................................................................................... $

854
902
953
1,006
995
2,746

NOTE H. 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 $42.6 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. In addition to the legal action described below, the Company is party to other proceedings and
claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that
the amount of the liability, if any, ultimately incurred with respect to such other proceedings and claims will not have
a material adverse effect on the Company's consolidated financial position as a whole or on its liquidity, capital
resources or future annual results of operations. The Company will continue to evaluate its litigation on a quarter-by-
quarter basis and will establish and adjust any litigation reserves as appropriate to reflect its assessment of the then
current status of litigation.

Investigation by the Alaska Oil and Gas Conservation Commission (the "AOGCC"). During the second quarter
of 2010, the AOGCC commenced an investigation into allegations by a former Pioneer employee regarding the
Company's Oooguruk facility on the North Slope of Alaska. Among the allegations are claims that the Company did
not have authorization to inject certain non-hazardous substances into its enhanced oil recovery well, that the
Company mishandled disposal of waste products and that the Company's operating practices are harmful to the
project's oil reservoirs. Upon initially becoming aware of the allegations, the Company informed the AOGCC and
other relevant federal, state and local agencies and commenced its own investigation, which confirmed injections of
non-hazardous fluids into the Oooguruk enhanced oil recovery well without prior authorizations to do so. The results
of the Company's investigation were reported to the agencies. In December 2010, the AOGCC investigator submitted
a report outlining its findings, which (i) found that the Company's operating practices have not harmed the project's oil
reservoirs and (ii) raised certain regulatory compliance issues, all of which the Company previously reported or has
since taken actions to remedy. Although the Company does not know at this time what action the AOGCC will take in
response to the report, based on the facts as known to date, the Company believes that compliance with any order or
other action of the AOGCC will not materially and negatively affect the Company's liquidity, financial position or
future results of operations.

Obligations following divestitures. In April 2006, the Company provided the purchaser of its Argentine assets
certain indemnifications. The Company remains responsible for certain contingent liabilities related to such
indemnifications, subject to defined limitations, 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 in 2007 of its Canadian assets and the February 2011
sale of Pioneer Tunisia. 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.

101

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

Lease agreements. The Company leases equipment and office facilities under noncancellable operating leases.
Lease payments associated with these operating leases for the years ended December 31, 2011, 2010 and 2009 were
$26.9 million, $29.5 million and $30.5 million, respectively. These payments include $513 thousand, $7.2 million and
$10.7 million for the years ended December 31, 2011, 2010 and 2009 respectively, of lease payments associated with
discontinued operations and included in income from discontinued operations, net of tax, in the accompanying
consolidates statement of operations. Future minimum lease commitments under noncancellable operating leases at
December 31, 2011 are as follows (in thousands):

2012 ............................................................................................................................................................................ $
2013 ............................................................................................................................................................................ $
2014 ............................................................................................................................................................................ $
2015 ............................................................................................................................................................................ $
2016 ............................................................................................................................................................................ $
Thereafter..................................................................................................................................................................... $

26,843
24,997
14,732
13,156
11,775
41,459

Gathering, processing and transportation agreements. The Company is party to contractual commitments
with midstream service companies and pipeline carriers for the future gathering, processing, transportation and
purchase of oil, NGL and gas production from certain of the Company's asset areas described below:

Permian Basin. The Company has entered into an agreement to sell NGL production that includes a
commitment to deliver minimum NGL volumes for transportation and fractionation. Under the terms of the
agreement, committed NGL volumes equal 13,900 Bbls per day in 2012, increasing to 16,000 Bbls in 2015 and
continuing at this rate until 2021.

The Company has entered into an NGL purchase and sale agreement pursuant to which the Company has
committed to sell NGL production at or near the field processing plant in the Spraberry field and repurchase it at the
inlet of the fractionation facilities of the counterparty in Mt. Belvieu, Texas. The Company's commitment commences
in 2012 for 2,000 Bbls of NGL per day, increasing annually to 15,000 Bbls per day by 2019 and continuing at this rate
until 2027. The Company's commitment prior to December 31, 2013, is subject to the completion of certain
construction activities by the counterparty to the agreement. The Company also has NGL fractionation commitments
with the same counterparty that average 2,000 Bbls of NGL per day commencing in 2014, increasing to 10,000 Bbls
per day by 2018 and continuing at this rate until 2023.

Raton. The Company has firm transportation commitments for 214,000 Mcf per day of gas through 2020, then
declining to 133,000 Mcf per day in 2026, from the Raton field eastward to Mid-Continent sales points and north to
Cheyenne, Wyoming. Of these committed volumes, 75,000 Mcf per day is committed onward to Opal, Wyoming.

Eagle Ford Shale. During 2010, the Company entered into agreements with third parties to gather, transport,
process and fractionate certain portions of the Company's future Eagle Ford Shale oil, gas and NGL production.
During 2010, the Company entered into a ten-year oil gathering agreement, under which the counterparty is obligated
to build a 111-mile oil pipeline that will transport approximately 7,100 Bbls of oil per day in 2012, increasing to
approximately 17,400 Bbls per day in 2017, and declining thereafter until the contract term ends in 2022. The
Company has firm transportation commitments under this contract upon completion of the pipeline, which is expected
during the third quarter of 2012.

During 2010, the Company entered into two five-year gas transportation agreements. Transportation
commitments under these agreements in 2012 are approximately 37,000 Mcf per day, increasing to approximately
83,500 Mcf per day in 2015 declining thereafter to 9,700 Mcf per day until terminating in mid-2016.

During 2010, the Company also entered into a ten-year contractual agreement with a third party for the
transportation and processing of gas production and the fractionation of recovered NGLs. The firm transportation and
processing commitments under this agreement are for approximately 41,800 Mcf per day in 2012 and increasing to
approximately 139,100 Mcf per day in 2020. Fractionation commitments under the agreement are for approximately
4,500 Bbls per day of NGLs in 2012 and increasing to approximately 14,900 Bbls per day in 2020.

During 2010, the Company entered into an agreement with its unconsolidated subsidiary EFS Midstream to
gather, treat and transport certain Eagle Ford Shale oil and gas production. The agreement has sequential start dates

102

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

linked to commencement of Eagle Ford Shale production, with a primary term of 20 years and continuing year-to-year
thereafter. EFS Midstream is obligated to construct various gathering and field facilities to handle the Eagle Ford
Shale area production, and the Company has dedicated the areas' reserves to the contract. The Company has
minimum annual revenue commitments payable to EFS Midstream of $46.2 million in 2012 and increasing to $128.0
million in 2016 under the aforementioned agreement. See Notes B and F for additional information about EFS
Midstream.

Barnett Shale Combo. During 2011, the Company entered into a gas gathering and processing agreement with
a third party commencing in 2013 for 50,000 Mcf of gas per day, increasing to 95,000 Mcf per day in 2016 then
decreasing to 70,000 Mcf per day in 2019. The agreement terms provide for annual adjustments based on the prior
year's deliveries under the contract. The contract commitment is also subject to commencement of construction of a
related plant upon notice given by the Company of its intent to deliver volumes to the plant.

Other. The Company also has a 10-year firm transportation commitment for 75,000 Mcf per day from Opal,
Wyoming to Malin, Oregon, which became effective when construction of a 675-mile new pipeline was completed
and placed in service during August 2011. The Company does not ship any of its production under this transportation
commitment. From time to time, the Company is able to mitigate its exposure to the firm transportation commitments
under this agreement by purchasing gas in Cheyenne or Opal, Wyoming and transporting and selling the gas in Malin,
Oregon when the spread between the index prices at these two locations is wider than the Company's variable cost to
transport the gas. The firm transportation charges, net of any income from the Company's mitigation efforts, are
recorded in other expense in the accompanying statements of operations. See Note N for additional information on
unused transportation commitments.

Future minimum gathering, processing, transportation and fractionation fees under the Company's oil, NGL and

gas gathering, processing and transportation commitments at December 31, 2011 are as follows (in thousands):

2012 ............................................................................................................................................................................ $
2013 ............................................................................................................................................................................ $
2014 ............................................................................................................................................................................ $
2015 ............................................................................................................................................................................ $
2016 ............................................................................................................................................................................ $
Thereafter..................................................................................................................................................................... $

151,640
217,617
262,888
311,529
329,379
1,069,159

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 I. 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, (ii) support the
Company's annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with
certain capital projects. The Company also, from time to time, utilizes interest rate contracts to reduce the effect of
interest rate volatility on the Company's indebtedness and forward currency exchange rate agreements to reduce the
effect of exchange rate volatility.

Oil production derivative activities. All material physical sales contracts governing the Company's oil

production are tied directly or indirectly to NYMEX WTI oil prices.

103

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

The following table sets forth the volumes in Bbls outstanding as of December 31, 2011 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
79.32 $

3,000
81.02 $

-
-

2012

2013

2014

2,000

127.00 $
90.00 $

Collar contracts:
Volume (Bbl) ........................................................................................................
Average price per Bbl:
Ceiling ................................................................................................................. $
Floor .................................................................................................................... $
Collar contracts with short puts: (a)
Volume (Bbl) ........................................................................................................
Average price per Bbl:
Ceiling ................................................................................................................. $
Floor .................................................................................................................... $
Short put .............................................................................................................. $
_____________
(a) During the period from January 1, 2012 to February 24, 2012, the Company entered into additional collar contracts with
short puts for (i) 8,500 Bbls per day of the Company's July through September 2012 production with a ceiling price of
$120.47 per Bbl, a floor price of $95.00 per Bbl and a short put price of $80.00 per Bbl, (ii) 11,500 Bbls per day of the
Company's October through December 2012 production with a ceiling price of $121.10 per Bbl, a floor price of $95.00
per Bbl and a short put price of $80.00 per Bbl, (iii) 32,250 Bbls per day of the Company's 2013 production with a ceiling
price of $121.62 per Bbl, a floor price of $93.45 per Bbl and a short put price of $76.90 per Bbl and (iv) 13,000 Bbls per
day of the Company's 2014 production with a ceiling price of $118.78 per Bbl, a floor price of $90.00 per Bbl and a short
put price of $70.00 per Bbl.

118.24 $
82.36 $
66.52 $

119.38 $
84.35 $
66.56 $

127.46
87.50
72.50

- $
- $

41,610

10,000

34,000

-
-

Permian Basin roll adjustment swap derivatives. The Company uses ''roll adjustment'' swap derivatives to
mitigate the timing risk associated with the sales price of oil in the Permian Basin. In the Permian Basin, the
Company generally sells its oil at a sales price based on the calendar month average NYMEX price of oil during that
month, plus an adjustment calculated as the weighted average spread between the NYMEX price for that delivery
month and (i) the next month and (ii) the following month during the period when the delivery month is prompt. The
Company has roll adjustment swap derivatives for 3,000 Bbls per day of March 2012 through May 2012 oil sales and
3,000 Bbls per day of oil sales for the year 2013. Under the terms of the roll adjustment swap derivatives, the
Company pays the periodic variable roll adjustments and receives a fixed price of $0.28 per Bbl for March 2012
through May 2012 and $0.43 per Bbl for the year 2013. The Permian Basin roll adjustment swap derivatives are not
included in the table presented above. During the period from January 1, 2012 to February 24, 2012, the Company
entered into additional roll adjustment swap derivatives for 3,000 Bbls per day of 2013 oil sales, under which the
Company pays the periodic variable roll adjustments and receives a fixed price of $0.43 per Bbl.

Natural gas liquids production derivative activities. All material physical sales contracts governing the
Company's NGL production are tied directly or indirectly to either Mont Belvieu or Conway fractionation facilities'
NGL product component prices. As of December 31, 2011 the Company had NGL swap derivatives for 750 Bbls per
day of 2012 NGL sales at an average price of $35.03 per Bbl and NGL collar contracts with short put derivatives for
3,000 Bbls per day of 2012 sales with a ceiling price of $79.99 per Bbl, a floor price of $67.70 per Bbl and short put
price of $55.76 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.

104

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

The following table sets forth the volumes in MMBtus outstanding as of December 31, 2011 under the

Company's gas derivative contracts and the weighted average gas prices per MMBtu for those contracts:

Swap contracts: (a)
Volume (MMBtu) ............................................................................
Price per MMBtu .............................................................................. $
Collar contracts:
Volume (MMBtu) ............................................................................
Price per MMBtu:
Ceiling ............................................................................................ $
Floor ............................................................................................... $
Collar contracts with short puts: (a)
Volume (MMBtu) ............................................................................
Price per MMBtu:
Ceiling ............................................................................................ $
Floor ............................................................................................... $
Short put ......................................................................................... $
Basis swap contracts:
Volume (MMBtu) ............................................................................
Price per MMBtu .............................................................................. $

2012

2013

2014

2015

105,000

67,500

50,000

5.82 $

6.11 $

6.05 $

-
-

65,000

150,000

140,000

50,000

6.60 $
5.00 $

6.25 $
5.00 $

6.44 $
5.00 $

7.92
5.00

170,000

45,000

60,000

30,000

7.92 $
6.07 $
4.50 $

7.49 $
6.00 $
4.50 $

7.80 $
5.83 $
4.42 $

136,000

142,500

115,000

(0.34) $

(0.22) $

(0.23) $

7.11
5.00
4.00

-
-

______
(a) During the period from January 1, 2012 to February 24, 2012, the Company (i) entered into offsetting swap contracts for
20,000 MMBtus per day of the Company's March 2012 production with a fixed price of $2.41, (ii) converted 95,000
MMBtus per day of the Company's February through December 2012 collar contracts with short puts to swap contracts with
a fixed price of $4.47 per MMBtu , (iii) converted 75,000 MMBtus per day of the Company's March through December
2012 collar contracts with short puts to swap contracts with a fixed price of $4.41 per MMBtu and (iii) converted 45,000
MMBtus per day of the Company's 2013 collar contracts with short puts to swap contracts with a fixed price of $4.88 per
MMbtu.

Diesel prices. As of December 31, 2011, the Company had diesel derivative swap contracts for 500 Bbls per
day for 2012 at an average per Bbl fixed price of $119.49. The diesel derivative swap contracts are priced at an index
that is highly correlated to the prices that the Company incurs to fuel its drilling rigs, fracture stimulation fleet
equipment and well servicing equipment. The Company purchases diesel derivative swap contracts to mitigate fuel
price risk.

Subsequent to December 31, 2011, the Company terminated all diesel derivative swap contracts and received

cash proceeds of $1.8 million associated with the termination.

Interest rates. As of December 31, 2011, the Company is a party to interest rate derivative contracts that lock
in, through July 2012, a fixed forward 10-year annual interest rate of 3.06 percent on $200 million notional amount of
debt.

105

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

Tabular disclosure of derivative fair value. All of the Company's derivatives are accounted for as non-hedge
derivatives as of December 31, 2011 and 2010. The following tables provide disclosure of the Company's derivative
instruments:

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
Interest rate derivatives ......................... Derivatives - current
Commodity price derivatives ................ Derivatives - noncurrent
Interest rate derivatives ......................... Derivatives - noncurrent

248,809 Derivatives - current
- Derivatives - current
257,368 Derivatives - noncurrent
- Derivatives - noncurrent

506,177

68,735
15,654
47,689
-
132,078

Fair Value of Derivative Instruments as of December 31, 2010
Asset Derivatives (a)

Liability Derivatives (a)

Type

Balance Sheet
Location

Fair
Value
(in thousands)

Balance Sheet
Location

Fair
Value
(in thousands)

167,406 Derivatives - current
11,903 Derivatives - current
152,731 Derivatives - noncurrent
15,762 Derivatives - noncurrent
$
347,802

87,741
886
64,829
9,227
162,683

_____________
(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.

Amount of Gain/(Loss) Recognized in
AOCI on Effective Portion

Derivatives in Cash Flow Hedging Relationships

Year Ended December 31,
2010

2009

2011

Interest rate derivatives .............................................................................................. $
Commodity price derivatives .....................................................................................

Total ........................................................................................................................... $

(in thousands)

- $
-

- $

- $
-

- $

(433)
13,407

12,974

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,
2010
(in thousands)

2011

2009

$
Interest rate derivatives .............................................. Interest expense
Interest rate derivatives .............................................. Derivative gains (losses), net
Commodity price derivatives ..................................... Oil and gas revenue
Total ...........................................................................

(282) $
-
32,918
32,636 $

(1,698) $
(2,465)
89,040
84,877 $

(6,835)
-
121,066
114,231

106

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

Derivatives Not Designated as Hedging
Instruments

Location of Gain (Loss)
Recognized in Earnings on
Derivatives

Amount of Gain (Loss) Recognized in
Earnings on Derivatives
Year Ended December 31,
2010

2011

2009

Interest rate derivatives ............................................. Derivative gains (losses), net $
Commodity price derivatives .................................... Derivative gains (losses), net

3,098 $
389,654

36,597 $
414,302

(15,423)
(180,134)

Total ..........................................................................

392,752 $

450,899 $

(195,557)

(in thousands)

AOCI - Hedging. The effective portions of deferred cash flow hedge gains and losses, net of associated taxes
are reflected in AOCI-Hedging as of December 31, 2011 and 2010, and are being transferred to oil revenue (for
deferred commodity hedge losses) and to interest expense (for deferred interest rate hedge gains and losses) in the
same periods in which the hedged transactions are recorded in earnings. In accordance with the change to the mark-to-
market method of accounting on February 1, 2009, the Company recognizes changes in the fair values of its derivative
contracts as gains or losses in the earnings of the periods in which the changes occur.

As of December 31, 2011, AOCI - Hedging represented net deferred losses of $3.1 million compared to net
deferred gains of $7.4 million as of December 31, 2010. The AOCI - Hedging balance as of December 31, 2011 was
comprised of $3.1 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 the 12 months ending December 31, 2012, the Company expects to reclassify $3.1 million of AOCI –
Hedging net deferred losses to oil revenues and $317 thousand of AOCI – Hedging net deferred losses to interest
expense. The Company also expects to reclassify $1.3 million of net deferred income tax benefits associated with
hedge derivatives during the 12 months ending December 31, 2012 from AOCI – Hedging to income tax benefit.

NOTE J. Major Customers and Derivative Counterparties

Sales to 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 Company is of the opinion that the loss of any one purchaser would not have an adverse effect on the ability of
the Company to sell its oil and gas production.

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 years in the three
years ended December 31, 2011. The table provides the percentages of the Company's consolidated oil, NGL and gas
revenues represented by the purchasers during the periods presented:

Year Ended December 31,
2010

2011

2009

Plains Marketing LP ...........................................................................................................
Occidental Energy Marketing Inc ........................................................................................
Enterprise Products Partners L.P. ........................................................................................

16%
14%
12%

12%
8%
10%

10%
7%
6%

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.

107

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

The following table provides the Company's derivative assets and liabilities by counterparty as of December

31, 2011:

Assets

Liabilities

(in thousands)

Citibank, N.A. .................................................................................................................................... $
JP Morgan Chase ...............................................................................................................................
BNP Paribas .......................................................................................................................................
Barclays Capital .................................................................................................................................
Societe Generale ................................................................................................................................
Credit Agricole ..................................................................................................................................
Toronto Dominion .............................................................................................................................
Credit Suisse ......................................................................................................................................
J. Aron & Company ...........................................................................................................................
BMO Financial Group .......................................................................................................................
Wells Fargo Bank, N.A. .....................................................................................................................
Morgan Stanley ..................................................................................................................................
Den Norske Bank ...............................................................................................................................
Merrill Lynch .....................................................................................................................................
Total ................................................................................................................................................... $

138,267 $
117,335
41,879
35,413
32,376
28,545
20,856
16,076
15,985
13,146
12,539
4,923
4,582
153
482,075 $

6,850
13,070
6,391
4,278
2,241
5,487
1,369
4,779
3,139
12,365
46,216
774
-
1,017
107,976

NOTE K. 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, 2011, 2010 and 2009:

2011

Year Ended December 31,
2010
(in thousands)

2009

Beginning asset retirement obligations ..................................................................... $
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 on discontinued operations ................................................
Ending asset retirement obligations ........................................................................... $
____________
(a) The change in the 2011 and 2010 estimates are primarily due to increases in abandonment cost estimates based in part on
recent actual costs incurred and a decline in credit-adjusted risk-free discount rates used to value increases in asset
retirement obligations. These increases were partially offset by higher oil and NGL prices used to calculate proved reserves
at December 31, 2011 and 2010, 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. The change in the 2009 estimate is primarily due to (i) lower gas prices used to
calculate proved reserves at December 31, 2009, which had the effect of shortening the economic life of wells and
increasing the present value of future retirement obligations primarily in the Raton, Hugoton and West Panhandle gas fields
and (ii) a $19.9 million increase in East Cameron facilities reclamation and abandonment estimates.

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 $

172,433
-
625
40,153
-
(13,334)
(45,010)
8,050
3,517
166,434

The Company records the current and noncurrent portions of asset retirement obligations in other current
liabilities and other liabilities, respectively, in the accompanying consolidated balance sheets. As of December 31,

108

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

2011 and 2010, the current portions of the Company's asset retirement obligations were $14.2 million and $19.9
million, respectively.

NOTE L.

Interest and Other Income

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

ended December 31, 2011, 2010 and 2009:

Year Ended December 31,

2011

2010
(in thousands)

2009

Third-party income from vertical integration services (a).......................................... $
Alaskan Petroleum Production Tax credits and refunds (b) .......................................
Equity interest in income (loss) of EFS Midstream ...................................................
Eagle Ford Shale land fees .........................................................................................
Other income ............................................................................................................
Deferred compensation plan income .........................................................................
Interest income ..........................................................................................................
Total interest and other income ................................................................................. $
_____________
(a) Third-party income from vertical integration services represents the third-party working interests' share of earnings

45,115 $
38,939
7,868
3,747
3,937
1,657
697
101,960 $

47,652
(819)
-
4,565
1,228
4,177
56,972 $

-
94,989
-
-
3,631
1,034
1,935
101,589

169 $

(b)

associated with Company-provided fracture stimulation, drilling and related services.
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.

NOTE M. Asset Divestitures

During the years ended December 31, 2011, 2010 and 2009, the Company completed asset divestitures for net
proceeds of $819.0 million, $313.8 million and $51.6 million, respectively. The Company recorded net losses on
disposition of assets in continuing operations of $3.6 million and $774 thousand during the years ended December 31,
2011 and 2009, respectively, and a net gain on disposition of assets in continuing operations of $19.1 million during
the year ended December 31, 2010. The Company recorded gains from the disposition of discontinued operations of
$645.2 million and $17.5 million during the years ended December 31, 2011 and 2009. The following describes the
significant divestitures of continuing operations:

Eagle Ford Shale. 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, including normal closing adjustments, resulting in a
pretax gain of $6.0 million in 2010 and a $46.2 million deferred gain that is being amortized as a reduction to
production costs over a 20-year period. Under the terms of the transaction, the purchaser is also paying 75
percent (up to $886.8 million) of the Company's defined exploration, drilling and completion costs attributable to
the Eagle Ford Shale assets;

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 2011 and 2010, the Company sold unproved leaseholds, inventory and other property and

equipment and recorded a pretax net loss of $5.1 million and $4.2 million, respectively.

The following describes the significant divestitures of discontinued operations:

Pioneer Tunisia. During December 2010, the Company committed to a plan to sell its Tunisia subsidiaries and in
February 2011 completed the sale of Pioneer Tunisia to an unaffiliated third party for cash proceeds of $853.6
million, including normal closing adjustments. Pioneer Tunisia represents all of the Company's Tunisian oil and

109

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

gas operations. Accordingly, assets, liabilities and historic results of operations of Pioneer Tunisia, including a
$645.2 million pretax gain on disposition of assets, have been classified as discontinued operations herein. (Refer
to Note U for further information regarding discontinued operations);

Mississippi and Gulf of Mexico Shelf. During 2009, the Company sold its oil and gas asset properties in
Mississippi and substantially all of its shelf properties in the Gulf of Mexico. In accordance with GAAP, the
Company classified the results of operations attributable to these divestitures as discontinued operations, rather
than as a component of continuing operations.

NOTE N. Other Expense

The following table provides the components of the Company's other expense during the years ended

December 31, 2011, 2010 and 2009:

2011

Year Ended December 31,
2010
(in thousands)

2009

23,248 $
20,132
5,503
4,057
3,126
3,009
2,725
2,366
693
-
(1,693)
63,166 $

1,589 $
37,516
4,758
5,581
10,729
1,591
501
-
3,516
13,065
(442)
78,404 $

6,839
54,223
4,151
7,796
2,275
2,047
315
-
263
12,437
4,356
94,702

Transportation commitment charge (a) ...................................................................... $
Above market drilling and rig termination costs (b) ..................................................
Other ..........................................................................................................................
Contingency and environmental accrual adjustments ................................................
Inventory impairment (c) ...........................................................................................
Cancelled wells ..........................................................................................................
Legal settlements .......................................................................................................
Loss on extinguishment of debt .................................................................................
Tax penalties and adjustments ...................................................................................
Well servicing operations (d) .....................................................................................
Bad debt expense (recovery) ......................................................................................
Total other expense ................................................................................................... $
__________
(a)
(b)

Primarily represents contract deficiency payments on excess pipeline capacity.
Primarily represents rig termination fees and charges for the portion of Pioneer's contracted drilling rig rates that are above
market rates and are not charged to joint operations.

(c) Represents impairment charges on excess materials and supplies inventories.
(d) Represents idle well servicing costs.

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 $22.3 million and $36.6 million (net of tax
refunds) during 2011 and 2010, respectively, and received tax refunds (net of tax payments) during 2009 of $42.6
million. These payments and net refunds include tax payments related to Pioneer Tunisia's and Pioneer South Africa's
operations of $12.2 million, $17.8 million and $10.6 million during 2011, 2010 and 2009, respectively. During 2009,
the Company received $61.6 million of refunds as a result of carrying back 2007 and 2008 net operating losses. In
November 2009, President Obama signed into law the Worker, Homeownership, and Business Assistance Act of 2009,
which expanded the carryback period from two years to five years and suspended certain loss utilization limitations.
Pursuant to this new legislation, the Company filed an amended carryback claim and received an additional $19.9
million refund during 2010.

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

110

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

carryforwards ("NOLs") and other deferred tax attributes in the United States, state, local and foreign tax jurisdictions
will be utilized prior to their expiration.

Accounting for uncertainty in income taxes prescribes a recognition threshold and measurement methodology
for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return.
As of December 31, 2011, the Company had no unrecognized tax benefits. The Company's policy is to account for
interest charges with respect to income taxes as interest expense and any penalties, with respect to income taxes, as
other expense in the consolidated statements of operations. The Company files income tax returns in the U.S. federal
jurisdiction, and various state and foreign jurisdictions. With few exceptions, the Company believes that it is no longer
subject to examinations by tax authorities for years before 2006. The Internal Revenue Service recently closed the
examination of the 2007, 2008 and 2009 tax years, and is concluding an examination of the 2010 tax year. As of
December 31, 2011, 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 ....................................................................................................................................

2010
2007
2006
2006

The Company's income tax (provision) benefit and amounts separately allocated were attributable to the

following items for the years ended December 31, 2011, 2010 and 2009:

Year Ended December 31,

2011

2010

2009

(in thousands)

Income from continuing operations .......................................................................... $
Income from discontinued operations .......................................................................
Changes in goodwill – tax benefits related to stock-based compensation .................
Changes in stockholders' equity:
Net deferred hedge gains .......................................................................................
Tax benefits related to stock-based compensation ................................................

Tax on Pioneer Southwest common units sold by the Company on
December 12, 2011 ................................................................................................

(197,644) $
(257,950)
40

(269,627) $

270
453

83,195
(85,527)
124

8,407
31,087

23,648
(153)

50,059
1

(15,381)

The Company's income tax (provision) benefit attributable to income from continuing operations consisted of

the following for the years ended December 31, 2011, 2010 and 2009:

Current:
U.S. federal ........................................................................................................... $
U.S. state ................................................................................................................
Foreign ...................................................................................................................

Deferred:
U.S. federal ...........................................................................................................
U.S. state ................................................................................................................

Year Ended December 31,

2011

2010

2009

(in thousands)

- $

21,714

(9,065)
-

(9,864)
-

(10,010)
(551)

(9,065)

(9,864)

11,153

(207,146)

(263,063)

63,970

18,567

3,300

8,072

(188,579)

(259,763)

72,042

Income tax (provision) benefit ................................................................................... $

(197,644) $

(269,627) $

83,195

111

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

Income (loss) from continuing operations before income taxes less net income attributable to the noncontrolling

interests consists of the following for the years ended December 31, 2011, 2010 and 2009:

2011

Year Ended December 31,
2010
(in thousands)

2009

U.S. federal ................................................................................................................ $
Foreign .......................................................................................................................

608,981 $

740,785 $

(234,860)
(157)

608,981 $

740,785 $

(235,017)

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, 2011, 2010 and 2009:

2011

Year Ended December 31,
2010
(in percentages)

2009

U.S. federal statutory tax rate .............................................................................................
State income taxes (net of federal benefit) ..........................................................................
Other ...................................................................................................................................
Consolidated effective tax rate ............................................................................................

35.0
(0.9)
(1.6)
32.5

35.0
0.5
0.9
36.4

35.0
(0.4)
0.8
35.4

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, 2011 and 2010:

Deferred tax assets:
Foreign tax credit carryforward ..................................................................................................... $
Asset retirement obligations .........................................................................................................
Other .............................................................................................................................................
Total deferred tax assets ..............................................................................................................
Valuation allowances ....................................................................................................................
Net deferred tax assets ................................................................................................................
Deferred tax liabilities:
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 ........................................................................................................

December 31,

2011

2010

(in thousands)

- $

47,860
82,828
130,688
-
130,688

174,054
50,886
78,014
302,954
(6,632)
296,322

(1,692,317)

(102,351)
(191,621)
(144,558)
(2,130,847)

(1,663,343)

(58,866)
(117,685)
(52,232)
(1,892,126)

Net deferred tax liability ................................................................................................................. $ (2,000,159) $ (1,595,804)

Reflected in accompanying consolidated balance sheets as:
Current deferred income tax asset .................................................................................................. $
Current deferred income tax liability .............................................................................................
Non-current deferred income tax liability ......................................................................................

77,005 $

-
(2,077,164)

156,650
(1,144)
(1,751,310)

Total ............................................................................................................................................. $ (2,000,159) $ (1,595,804)

During 2010, the Company utilized all available NOLs in the United States and South Africa. At December 31,
2010, the Company had $174.1 million of foreign tax credit carryforwards, which were available to offset future U.S.

112

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

regular taxable income, if any. As a result of the sale of Pioneer Tunisia during February 2011, the Company realized
all of these carryforwards in 2011. Pursuant to GAAP, the Company's $174.1 million deferred tax asset related to the
foreign tax credit carryforwards at December 31, 2010 is net of $12.2 million of unrealized excess tax benefits from
stock based compensation.

The Company's income tax (provision) benefit attributable to income from discontinued operations consisted of

the following for the years ended December 31, 2011, 2010 and 2009:

Current:
U.S. state .................................................................................................................. $
Foreign .....................................................................................................................

Deferred:
U.S. federal .............................................................................................................
U.S. state ..................................................................................................................
Foreign .....................................................................................................................

Year Ended December 31,

2011

2010
(in thousands)

2009

(4,354) $
(39,543)
(43,897)

(538) $
(24,948)
(25,486)

(1,300)
(18,757)
(20,057)

(227,385)
(1,836)
15,168
(214,053)

42,155
3
(16,402)
25,756

(48,879)
-
(16,591)
(65,470)

Income tax (provision) benefit ..................................................................................... $

(257,950) $

270 $

(85,527)

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

In the calculation of basic net income (loss) 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 not participate in undistributed net losses because they are not contractually
obligated to do so. The computation of diluted net income (loss) 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 (loss) 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, 2011, the two-class method of
calculating the Company's diluted net income (loss) per share was more dilutive than the treasury stock method.

The Company's basic net income (loss) per share attributable to common stockholders is computed as (i) net
income (loss) attributable to common stockholders, (ii) less participating share- and unit-based basic earnings (iii)
divided by weighted average basic shares outstanding. The Company's diluted net income (loss) per share attributable
to common stockholders is computed as (i) basic net income (loss) attributable to common stockholders, (ii) plus
diluted adjustments to participating undistributed earnings (iii) divided by weighted average diluted shares
outstanding.

113

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

The following table is a reconciliation of the Company's net income (loss) attributable to common stockholders
to basic net income (loss) attributable to common stockholders and to diluted net income (loss) attributable to
common stockholders for the years ended December 31, 2011, 2010 and 2009:

Continuing
Operations

Year Ended December 31, 2011
Discontinued
Operations
(in thousands)

Total

Net income (loss) attributable to common stockholders .................................. $
Participating basic earnings (a) .......................................................................
Basic income attributable to common stockholders .....................................
Reallocation of participating earnings (a) ......................................................

411,337 $
(7,482)
403,855
190

423,152 $
(7,696)
415,456
195

834,489
(15,178)
819,311
385

Diluted income attributable to common stockholders .................................. $

404,045 $

415,651 $

819,696

Continuing
Operations

Year Ended December 31, 2010
Discontinued
Operations
(in thousands)

Total

471,158 $
(10,818)
460,340
140

134,050 $
(3,078)
130,972
40

605,208
(13,896)
591,312
180

Diluted income attributable to common stockholders .................................. $

460,480 $

131,012 $

591,492

Continuing
Operations

Year Ended December 31, 2009
Discontinued
Operations
(in thousands)

Total

Net income (loss) attributable to common stockholders .................................. $
Participating basic earnings (a) .......................................................................
Basic net income (loss) attributable to common stockholders .....................
Reallocation of participating earnings (a) ......................................................

(151,822) $
(571)
(152,393)
-

99,716 $
375
100,091
-

(52,106)
(196)
(52,302)
-

Diluted income (loss) attributable to common stockholders ........................ $
__________
(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
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.

(152,393) $

100,091 $

(52,302)

114

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

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, 2011, 2010 and 2009:

2011

Year Ended December 31,
2010
(in thousands)

2009

Weighted average common shares outstanding:
Basic .........................................................................................................................
Dilutive common stock options (a) ............................................................................
Contingently issuable - performance shares (a) .........................................................
Convertible notes dilution (b) ....................................................................................

116,904
190
424
1,697

115,062
212
646
410

114,176
-
-
-

Diluted .......................................................................................................................
_____________
(a) Diluted earnings per share were calculated using the two-class method for the years ended December 31, 2011, 2010 and
2009. The following common stock equivalents were excluded from the diluted loss per share calculations for the year
ended 2009 because they would have been anti-dilutive to the calculations: 173,915 outstanding options to purchase the
Company's common stock and 223,969 performance shares.

119,215

116,330

114,176

(b) During January 2008, the Company issued $500 million of 2.875% Convertible Senior Notes. Weighted average common
shares outstanding have been increased to reflect the dilutive effect that would have resulted if the 2.875% Convertible
Senior Notes had qualified for and been converted during the years ended December 31, 2011 and 2010, respectively. The
2.875% Convertible Senior Notes were not dilutive to the per share calculations of 2009.

NOTE Q. Geographic Operating Segment Information

The Company has determined that its business is comprised of only one geographic and business segment as

the Company's vertical integration services are ancillary to production operations and are not separately managed.

NOTE R.

Impairment

The Company reviews its long-lived assets for impairment, including oil and gas proved properties, whenever
events or circumstances indicate that their carrying values may not be fully recoverable. During the years ended 2011
and 2009, the Company recognized $354.4 million and $21.1 million, respectively, of charges from impairment of oil
and gas proved properties.

2011 impairment. During the third and fourth quarters of 2011, events and circumstances provided indications
of possible impairment of certain of the Company's dry gas assets, including oil and gas proved properties in the
Company's Edwards, Austin Chalk, Raton and Barnett Shale fields. The events and circumstances indicating possible
impairment of these fields were primarily related to a reduction in Management's Price Outlook for gas that led to a
decrease in estimated future undiscounted net cash flows attributable to each fields' proved reserves. During the
fourth quarter of 2011, the estimate of undiscounted future net cash flows attributable to the Company's Edwards and
Austin Chalk fields in South Texas indicated that their carrying amounts were partially unrecoverable. Consequently,
the Company recorded $354.4 million of noncash impairment charges to reduce the carrying values of these fields to
their estimated fair values, represented by the estimated discounted future cash flows attributable to the assets, which
were derived from Level 3 fair value inputs, including Management's Price Outlook and the primary factors described
in Note B and below.

2009 impairment. During the first quarter of 2009, declines in commodity prices provided indications that the
carrying values of the Company's oil and gas properties in the Uinta/Piceance area may have been impaired. The
Company's estimates of the undiscounted future cash flows attributed to the assets indicated that their carrying
amounts were not expected to be recovered. Consequently, the Company recorded noncash charges during the first
quarter of 2009 of $21.1 million to reduce the carrying value of the Uinta/Piceance area oil and gas properties. During
2010, the Company sold substantially all of its oil and gas properties in the Uinta/Piceance area. See Note M for more
information on asset divestitures. The impairment charges reduced the oil and gas properties' carrying values to their
estimated fair values on those dates, represented by the estimated discounted future cash flows attributable to the
assets, which were derived from Level 3 fair value inputs.

115

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

Impairment risks. The Company's estimates of undiscounted future net cash flows attributable to the Raton
and Barnett Shale fields' oil and gas properties indicated on December 31, 2011 that their carrying amounts were
expected to be recovered. However, the carrying values of these fields continue to be at risk for impairment if future
estimates of undiscounted cash flows decline. As of December 31, 2011, the Company's Raton and Barnett Shale
fields have carrying values of $2.3 billion and $456.8 million, respectively.

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 the
fields.

NOTE S. Deferred Revenue

The Company's remaining volumetric production payment ("VPP") represents a limited-term overriding royalty
interest in oil reserves that: (i) entitles the purchaser to receive production volumes over a period of time from specific
lease interests, (ii) is free and clear of all associated future production costs and capital expenditures associated with
the reserves, (iii) is nonrecourse to the Company (i.e., the purchaser's only recourse is to the reserves acquired),
(iv) transferred title of the reserves to the purchaser and (v) allows the Company to retain the remaining reserves after
the VPPs volumetric quantities have been delivered.

At the inception of the VPP agreements, the Company (i) removed the proved reserves associated with the
VPP, (ii) recognized VPP proceeds as deferred revenue which are being amortized on a unit-of-production basis to oil
revenues over the term of the VPP, (iii) retained responsibility for 100 percent of the production costs and capital
costs related to VPP interests and (iv) no longer recognizes production associated with the VPP volumes.

The following table provides information about the deferred revenue carrying values of the Company's VPP (in

thousands):

Deferred revenue at December 31, 2010 ........................................................................................................................ $
Less: 2011 amortization .............................................................................................................................................
Deferred revenue at December 31, 2011 ........................................................................................................................ $

87,020
(44,951)
42,069

The remaining $42.1 million of deferred revenue will be recognized in oil revenues in the consolidated

statements of operations in 2012, assuming the related VPP production volumes are delivered as scheduled.

NOTE T.

Insurance Claims

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 million during November 2010. East Cameron 322 facility insurance recoveries and reclamation and
abandonment costs are included in hurricane activity, net in the accompanying consolidated statements of operations.

NOTE U. Discontinued Operations

The following lists the divestitures that have been reflected as discontinued operations in the accompanying

consolidated balance sheets and statements of operations:

During December 2011, the Company committed to a plan to divest Pioneer South Africa. The plan is expected to

result in the sale of Pioneer South Africa during 2012;

116

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

During December 2010, the Company committed to a plan to sell Pioneer Tunisia and in February 2011
completed a sale to an unaffiliated third party for cash proceeds of $853.6 million, including normal closing
adjustments. Associated therewith, the Company recognized a pretax gain of $645.2 million;

During the fourth quarter of 2009, the Company recorded a $119.3 million receivable from the Bureau of Ocean
Energy Management, Regulation, and Enforcement ("BOEMRE") for the recovery of excess royalties paid by the
Company on qualifying leases in the Gulf of Mexico. During 2010, the BOEMRE paid the Company the $119.3
million receivable plus an additional $35.3 million of associated interest on the excess royalty payments. The
properties that were the source of these royalty and interest recoveries were sold by the Company and classified
as discontinued operations during 2006;

The Company sold substantially all of its Mississippi assets and shelf properties in the Gulf of Mexico during

2009.

See Note B for additional information about the presentation of the Company's discontinued operations in the

accompanying consolidated balance sheets and statements of operations.

The following table summarizes the components of the Company's discontinued operations (principally related
to the divestitures of Pioneer South Africa and Pioneer Tunisia) for the years ended December 31, 2011, 2010 and
2009:

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 ...........................................................................................
Production and ad valorem taxes ...........................................................................
Depletion, depreciation and amortization (b) .........................................................
Exploration and abandonments (b) ........................................................................
General and administrative ....................................................................................
Accretion of discount on asset retirement obligations (b) ......................................
Interest ...................................................................................................................
Other ......................................................................................................................

Income from discontinued operations before income taxes .......................................
Income tax benefit (provision):
Current ...................................................................................................................
Deferred (b) ...........................................................................................................

Year Ended December 31,
2010

2009

2011

(in thousands)

100,275 $
6,193
645,241
751,709

236,343 $
49,076
36
285,455

221,279
120,062
17,491
358,832

5,519
-
41,916
4,268
10,286
2,686
773
5,159
70,607
681,102

14,754
-
98,495
15,908
5,697
2,923
-
13,898
151,675
133,780

39,621
(27)
91,273
19,240
9,647
3,517
8
10,310
173,589
185,243

(43,897)
(214,053)

(25,486)
25,756

(20,057)
(65,470)

423,152 $

134,050 $

99,716

Income from discontinued operations ........................................................................ $
____________
(a)

Primarily comprised of (i) $119.3 million receivable from the BOEMRE recorded in the fourth quarter of 2009 for the
recovery of excess royalties paid by the Company on qualifying deepwater leases in the Gulf of Mexico, (ii) $35.3 million
of associated interest on the aforementioned excess royalty payments received from BOEMRE during the second quarter of
2010, (iii) $2.8 million of legal settlements paid to the Company during the third quarter of 2010 on Gulf of Mexico
discontinued operations sold during 2006, (iv) $2.1 million of Canadian sales tax refunds paid to the Company during the
second quarter of 2010 attributable Canadian discontinued operations sold during 2007, (v) $3.8 million of Argentine value
added tax contingency charge reversals recorded during 2010 on Argentine discontinued operations sold during 2006, (vi)
$2.0 million of interest received during the first quarter of 2011 associated with the 2010 recovery of excess royalties paid
by the Company on qualifying deepwater leases in the Gulf of Mexico and (vii) $2.8 million of interest income associated
with Pioneer Tunisia operations recorded during the first quarter of 2011.
(b) Represents the significant noncash components of discontinued operations.

117

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009

As of December 31, 2011 and 2010, the carrying values of Pioneer South Africa and Pioneer Tunisia assets and
liabilities, respectively, were included in discontinued operations held for sale in the accompanying consolidated
balance sheet and are comprised of the following (in thousands):

December 31,

2011

2010

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................................................................................................................................... $

10,465 $
53,025
9,816
43
73,349 $

43,500
184,357
14,731
39,153
281,741

Composition of liabilities included in discontinued operations held for sale:
Current liabilities ............................................................................................................................. $
Deferred tax liabilities .....................................................................................................................
Deferred revenue .............................................................................................................................
Other liabilities ................................................................................................................................
Total liabilities ............................................................................................................................. $

11,689 $

-
34,320
29,892
75,901 $

30,148
72,663
-
5,781
108,592

NOTE V. Subsequent Events

During January 2012, the Company sold a portion of its interest in an unproved oil and gas property in the
Eagle Ford Shale to unaffiliated third parties for proceeds of $54.8 million. Associated therewith, the Company
expects to record a pretax gain of $40 million to $43 million during the three months ended March 31, 2012.

The Company has evaluated subsequent events through the date of issuance of the consolidated financial

statements. Except as described above, the Company is not aware of any reportable subsequent events.

118

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2011, 2010 and 2009

Capitalized Costs

December 31,

2011 (a)

2010 (b)

(in thousands)

Oil and gas properties:
Proved .......................................................................................................................................... $ 12,373,848 $ 11,003,805
191,112
Unproved .....................................................................................................................................
11,194,917
Capitalized costs for oil and gas properties ..................................................................................
(3,447,740)
Less accumulated depletion, depreciation and amortization ........................................................
7,747,177
Net capitalized costs for oil and gas properties ............................................................................ $

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.
Includes $264.7 million of proved property and $81.3 million of accumulated depletion, depreciation and
amortization related to Pioneer Tunisia, which was classified as held for sale at December 31, 2010.

(b)

Costs Incurred for Oil and Gas Producing Activities (a)

Property Acquisition
Costs

Proved

Unproved Costs

Exploration Development Total Costs
Costs

Incurred

(in thousands)

Year Ended December 31, 2011:
United States .............................................................. $
South Africa ................................................................
Tunisia ........................................................................
Total .......................................................................... $

Year Ended December 31, 2010:
United States .............................................................. $
South Africa ................................................................
Tunisia ........................................................................
Other ...........................................................................
Total .......................................................................... $

7,571 $
-
-
7,571 $

124,326 $
-
-
124,326 $

560,036 $ 1,470,362 $ 2,162,295
(3,261)
14,452
567,196 $ 1,474,393 $ 2,173,486

(3,602)
7,633

341
6,819

6,566 $
-
-
-
6,566 $

175,007 $
-
-
-
175,007 $

246,186 $
512
30,629
329
277,656 $

685,670 $ 1,113,429
2,294
70,503
329
727,326 $ 1,186,555

1,782
39,874
-

Year Ended December 31, 2009:
United States .............................................................. $
South Africa ................................................................
Tunisia ........................................................................
Other ...........................................................................
Total .......................................................................... $
__________
(a) The costs incurred for oil and gas producing activities includes the following amounts of asset retirement

255,538 $
(1,448)
17,470
-
271,560 $

90,737 $
623
19,931
724
112,015 $

80,088 $
-
-
-
80,088 $

8,770 $
65
-
-
8,835 $

435,133
(760)
37,401
724
472,498

obligations:

2011

Year Ended December 31,
2010
(in thousands)

2009

Proved property acquisition costs ................................................................................... $
Exploration costs ............................................................................................................
Development costs ..........................................................................................................
Total ................................................................................................................................ $

6 $
1,222
18,274
19,502 $

6 $
6,820
14,369
21,195 $

-
1,068
19,859
20,927

119

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2011, 2010 and 2009

The Company has continuing operations in only one business and geographic segment, that being United States
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.

Reserve Quantity Information

The estimates of the Company's proved reserves as of December 31, 2011, 2010, and 2009, which were located
in the United States, South Africa and Tunisia, 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 with no provision for
price and cost escalations except by contractual arrangements.

During the fourth quarter of 2009, the Company adopted the SEC's final rule on "Modernization of Oil and Gas
Reporting" (the "Reserve Ruling") and the FASB issued an ASU to ASC Topic 932 that aligns Topic 932 estimation
and disclosure requirements with the Reserve Ruling. The Reserve Ruling and Topic 932 ASU became effective for
annual reports on Forms 10-K for fiscal years ending on or after December 31, 2009. The key provisions of the
Reserve Ruling and Topic 932 ASU are as follows:

Expanding the definition of oil- and gas-producing activities to include the extraction of saleable hydrocarbons, in
the solid, liquid or gaseous state, from oil sands, coalbeds or other nonrenewable natural resources that are
intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction;

Adding to and amending other definitions used in estimating proved oil and gas reserves, such as "reliable

technology" and "reasonable certainty";

Broadening the types of technology that a registrant may use to establish reserves estimates and categories; and
Changing disclosure requirements and providing formats for tabular reserve disclosures, including the following

new disclosure provisions:
o Disclosure of reserves from non-traditional sources as oil and gas reserves,
o Optional disclosure of probable and possible reserves,
o Disclosure based on a new definition of the term "geographic area" and
o Disclosure of significant portions of reserve quantities and standardized measure of discounted future net cash

flows attributable to a consolidated subsidiary in which there is a significant noncontrolling interest.

The Company reports all reserves held under production sharing arrangements and concessions utilizing the
"economic interest" method, which excludes the host country's share of proved reserves. Estimated quantities for
production sharing arrangements reported under the "economic interest" method are subject to fluctuations in the
commodity prices of and recoverable operating expenses and capital costs. If costs remain stable, reserve quantities
attributable to recovery of costs will change inversely to changes in commodity prices. The reserve estimates as of
December 31, 2011, 2010 and 2009 utilized respective oil prices of $94.77, $77.16 and $59.49 per Bbl (reflecting
adjustments for oil quality), respective NGL prices of $46.47, $37.82 and $28.41 per Bbl, and respective gas prices of
$3.88, $4.07 and $3.19 per Mcf (reflecting adjustments for Btu content, gas processing and shrinkage).

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.

The following table provides a rollforward of total proved reserves by geographic area and in total for the years
ended December 31, 2011, 2010 and 2009, as well as proved developed and undeveloped reserves by geographic area
and in total as of the beginning and end of each respective year. Oil and NGL volumes are expressed in MBbls, gas
volumes are expressed in MMcf and total volumes are expressed in barrels of oil equivalent ("MBOE").

120

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2
2
1

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2011, 2010 and 2009

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, 2011, 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 $307.3 million at
December 31, 2011.

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.

123

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2011, 2010 and 2009

The following tables provide the standardized measure of discounted future cash flows by geographic area and

in total as of December 31, 2011, 2010 and 2009, as well as a roll forward in total for each respective year:

UNITED STATES
Oil and gas producing activities:
Future cash inflows ............................................................................ $
Future production costs ......................................................................
Future development costs ...................................................................
Future income tax expense .................................................................

10% annual discount factor ................................................................

Standardized measure of discounted future cash flows (a) ................... $
SOUTH AFRICA
Oil and gas producing activities:
Future cash inflows ............................................................................ $
Future production costs ......................................................................
Future development costs ...................................................................
Future income tax expense .................................................................

10% annual discount factor ................................................................

Standardized measure of discounted future cash flows ........................ $
TUNISIA
Oil and gas producing activities:
Future cash inflows ............................................................................ $
Future production costs ......................................................................
Future development costs ...................................................................
Future income tax expense .................................................................

10% annual discount factor ................................................................

Standardized measure of discounted future cash flows ........................ $
TOTAL
Oil and gas producing activities:
Future cash inflows ............................................................................ $
Future production costs ......................................................................
Future development costs (b) .............................................................
Future income tax expense .................................................................

10% annual discount factor ................................................................

Standardized measure of discounted future cash flows......................... $
__________
(a)

2011

December 31,

2010
(in thousands)

2009

59,106,103
(21,145,304)
(8,424,574)
(9,552,172)
19,984,053
(12,211,716)

44,100,276
(17,313,651)
(6,663,322)
(6,453,833)
13,669,470
(8,822,857)

29,884,670
(12,527,319)
(4,623,978)
(3,468,973)
9,264,400
(6,193,552)

7,772,337

4,846,613

3,070,848

147,022
(11,130)
(41,445)
(21,830)
72,617
(712)

71,905

750,078
(193,420)
(75,083)
(213,847)
267,728
(79,927)

187,801

114,254
(8,712)
(41,833)
(29,343)
34,366
6,320

123,215
(7,805)
(42,281)
(27,052)
46,077
1,502

40,686

47,579

1,771,661
(218,785)
(64,184)
(754,238)
734,454
(216,637)

517,817

-
-
-
-
-
-

59,220,357
(21,154,016)
(8,466,407)
(9,581,515)
20,018,419
(12,205,396)

45,995,152
(17,540,241)
(6,769,787)
(7,235,123)
14,450,001
(9,037,992)

30,781,770
(12,731,869)
(4,740,506)
(3,704,650)
9,604,745
(6,274,191)

7,813,023

5,412,009

3,330,554

(b)

Includes $378.6 million attributable to a 48 percent noncontrolling interest in Pioneer Southwest for 2011 and $214.2 million and
$99.6 million, respectively, attributable to a 38 percent noncontrolling interest in Pioneer Southwest for 2010 and 2009.
Includes $785.0 million, $823.5 million and $453.5 million of undiscounted future asset retirement expenditures estimated as of
December 31, 2011, 2010 and 2009, respectively, using current estimates of future abandonment costs. See Note K for
corresponding information regarding the Company's discounted asset retirement obligations.

124

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2011, 2010 and 2009

Changes in Standardized Measure of Discounted Future Net Cash Flows

Oil and gas sales, net of production costs ................................ $
Net changes in prices and production costs .............................
Extensions, discoveries and improved recovery .......................
Development costs incurred during the period ........................
Sales of minerals-in-place ........................................................
Purchases of minerals-in-place ................................................
Revisions of estimated future development costs ....................
Revisions of previous quantity estimates .................................
Accretion of discount ...............................................................
Changes in production rates, timing and other .........................
Change in present value of future net revenues .......................
Net change in present value of future income taxes .................

Balance, beginning of year ......................................................

Year Ended December 31,
2010

2011

2009

(in thousands)

(1,755,153) $
2,615,481
1,676,866
750,268
(1,021,513)
81,036
(1,280,213)
(442,120)
800,468
1,660,419
3,085,539
(684,525)
2,401,014
5,412,009

(1,373,943) $
2,098,422
1,017,597
380,754
(42,043)
20,957
(952,508)
626,693
437,523
1,415,999
3,629,451
(1,547,996)
2,081,455
3,330,554

(1,018,798)
1,006,250
82,431
183,936
(22,006)
-
(151,029)
(229,369)
385,681
281,326
518,422
(375,255)
143,167
3,187,387

Balance, end of year ................................................................. $

7,813,023 $

5,412,009 $

3,330,554

125

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2011, 2010 and 2009

Selected Quarterly Financial Results

The following table provides selected quarterly financial results for the years ended December 31, 2011 and

2010:

Year ended December 31, 2011:
Oil and gas revenues:
As reported ..................................................................................... $
Less discontinued operations ..........................................................
Adjusted ........................................................................................ $

Total revenues:
As reported ..................................................................................... $
Less discontinued operations ..........................................................
Adjusted ........................................................................................ $

Total costs and expenses:
As reported (b) ................................................................................ $
Less discontinued operations ..........................................................
Adjusted ........................................................................................ $

Net income (loss) .............................................................................. $
Net income (loss) attributable to common stockholders ................... $
Net income (loss) attributable to common stockholders per share:
Basic ............................................................................................... $
Diluted ............................................................................................ $

Year ended December 31, 2010:
Oil and gas revenues:
As reported ..................................................................................... $
Less discontinued operations ..........................................................
Adjusted ........................................................................................ $

Total revenues:
As reported (c) ................................................................................ $
Less discontinued operations ..........................................................
Adjusted ........................................................................................ $

Total costs and expenses:
As reported ..................................................................................... $
Less discontinued operations ..........................................................
Adjusted ........................................................................................ $

Quarter

First

Second

Third

Fourth (a)

(In thousands, except per share data)

497,130 $
(21,402)
475,728 $

583,931 $
(21,519)
562,412 $

610,509 $
(19,362)
591,147 $

664,776
-
664,776

283,123 $
(21,769)
261,354 $

831,569 $ 1,031,689 $
(21,536)
810,033 $ 1,012,145 $

(19,544)

703,053
-
703,053

401,112 $
(15,773)
385,339 $

419,589 $
(18,463)
401,126 $

460,073 $
(10,128)
449,945 $

893,769
-
893,769

343,804 $
348,594 $

265,700 $
245,577 $

385,598 $
351,464 $

(113,188)
(111,146)

2.96 $
2.96 $

2.07 $
2.03 $

2.96 $
2.95 $

(0.93)
(0.93)

507,796 $
(61,133)
446,663 $

462,142 $
(60,600)
401,542 $

471,372 $
(55,261)
416,111 $

471,759
(17,778)
453,981

817,428 $
(64,599)
752,829 $

662,394 $
(66,260)
596,134 $

616,382 $
(51,149)
565,233 $

486,110
(18,611)
467,499

396,348 $
(40,884)
355,464 $

405,168 $
(36,679)
368,489 $

426,231 $
(35,216)
391,015 $

501,189
(16,034)
485,155

Net income ........................................................................................ $
Net income attributable to common stockholders ............................. $
Net income attributable to common stockholders per share:
Basic ............................................................................................... $
Diluted ............................................................................................ $
________________________
(a) During the fourth quarters of 2011 and 2010, the Company committed to plans to sell Pioneer South Africa and Pioneer
Tunisia, respectively. Accordingly, the Pioneer South Africa and Pioneer Tunisia results of operations are classified as
discontinued operations in all quarters presented.

188,689 $
167,576 $

114,573 $
112,035 $

260,606 $
245,254 $

2.09 $
2.08 $

0.95 $
0.94 $

1.42 $
1.41 $

82,127
80,343

0.68
0.67

(b) 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.

(c) During the fourth quarter of 2010, the Company's total revenues include $122.2 million of net mark-to-market derivative

losses and a $140.0 million East Cameron 322 insurance recovery gain recorded in net hurricane activity.

126

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 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, 2011 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, 2011, 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, 2011, 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, 2011. The report, which
expresses an unqualified opinion on the effectiveness of the Company's internal control over financial reporting as of
December 31, 2011, is included in this Item under the heading "Report of Independent Registered Public Accounting
Firm."

127

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, 2011, 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, 2011, 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, 2011 and
2010 and the related consolidated statements of operations, stockholders' equity, cash flows and comprehensive
income (loss) for each of the three years in the period ended December 31, 2011, and our report dated February 29,
2012 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Dallas, Texas
February 29, 2012

128

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 2012 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 2012 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, 2011:

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 remaining
available for future issuance
under equity compensation
plans (excluding securities
reflected in first column) (b)

3,394,400
-
124,997

-
-

26,905 $

22.64
-
-

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) 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 less 625,003 cumulative shares issued through
December 31, 2011. See Note G 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 remaining securities for future issuance reflects the deduction of the maximum number of shares that could
be issued pursuant to grants of performance units outstanding at December 31, 2011.

-
22.64

26,905 $

(b)

(c)

-
3,519,397

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 2012 and is incorporated herein by reference.

129

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 2012 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 2012 and is incorporated herein by reference.

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

PART IV

(a) Listing of Financial Statements

Financial Statements

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, 2011 and 2010

Consolidated Statements of Operations for the Years Ended December 31, 2011, 2010 and 2009

Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2011, 2010 and 2009

Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009

Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2011, 2010 and

2009

Notes to Consolidated Financial Statements

Unaudited Supplementary Information

(b) Exhibits

The exhibits to this Report required to be filed pursuant to Item 15(b) are included in the Company's Form 10-

K filed with the SEC on February 29, 2012.

(c)

Financial Statement Schedules

No financial statement schedules are required to be filed as part of this Report or they are inapplicable.

130

SHAREHOLDER INFORMATION

Stock Exchange Listing – Common Stock
New York Stock Exchange: PXD

Corporate Headquarters
Pioneer Natural Resources Company
5205 N. O’Connor Blvd., Suite 200
Irving, TX 75039
(972) 444-9001
www.pxd.com

Stock Transfer Agent and Registrar
Communication concerning the transfer or exchange
of shares, dividends, lost certiﬁ cates or change of
address should be directed to:

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 17, 2012, at 9:00 a.m.
Central Time.

Information Requests
To receive additional copies of the Annual Report on
Form 10-K as ﬁ led with the SEC or to obtain other
Pioneer publications, please contact:

Pioneer Natural Resources Company
Investor Relations
5205 N. O’Connor Blvd., Suite 200
Irving, TX 75039
(972) 969-3583
Email: ir@pxd.com

Investor Relations/Media Contact
Shareholders, portfolio managers, brokers
and securities analysts seeking information
concerning Pioneer’s operations or ﬁ nancial
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,
Sustainable Development and Communication
at (972) 444-9001.

Pioneer Natural Resources Company
5205 N. O’Connor Blvd., Suite 200
Irving, TX 75039
(972) 444-9001
NYSE: PXD
www.pxd.com