Pioneer Natural Resources Reports Second Quarter 2011 Financial and Operating Results

Pioneer Natural Resources Company (NYSE:PXD) ('Pioneer? or 'the
Company?) today announced financial and operating results for the
quarter ended June 30, 2011.

Pioneer reported second quarter net income attributable to common
stockholders of $246 million, or $2.03 per diluted share (see attached
schedule for a description of the earnings per diluted share
calculation). Net income included unrealized mark-to-market gains on
derivatives of $133 million after tax, or $1.10 per diluted share.
Without the effect of this item, adjusted income for the second quarter
would have been $113 million, or $0.93 per diluted share.

Also included in Pioneer′s second quarter results was a loss from
discontinued operations of $2 million after tax, or $0.01 per diluted
share, primarily related to post-closing adjustments associated with the
sale of Pioneer′s Tunisian subsidiaries in February 2011.

Scott Sheffield, Chairman and CEO, stated, 'The Company delivered
another strong quarter, with second quarter production increasing to 119
thousand barrels oil equivalent per day (MBOEPD), an increase of 8
MBOEPD, or 7%, from the first quarter of 2011, despite losing 2 MBOEPD
of production during the second quarter due to a shortage of third-party
oil transport trucks in the Spraberry field. Our three core growth
assets (Spraberry field, Eagle Ford Shale and the Barnett Shale Combo)
all contributed to the quarterly production increase. Second half
production is forecasted to grow by approximately 10 MBOEPD per quarter
as these three assets continue to deliver quarterly production growth
and incremental oil transportation capacity is added in the Spraberry
field. We continue to expect to deliver full-year 2011 production
ranging from 125 MBOEPD to 130 MBOEPD, recognizing that production is
likely to be towards the lower end of the range due to the severe
weather and unplanned third-party impacts we experienced during the
first half of the year.?

'In the Spraberry field, we are increasing our rig count from 35 rigs to
45 rigs by year-end 2011, earlier than previously anticipated. Based on
the accelerated drilling activity, combined with the production
additions being delivered from our successful deeper drilling program in
the Spraberry field and the production growth anticipated for the Eagle
Ford Shale and the Barnett Shale Combo plays, we are increasing the
Company′s 2012 production growth target from 18+% to 20+%. We are also
extending our compound annual production growth target of 18+% through
2014. We are increasing our drilling budget in 2011 by $200 million to
fund the accelerated drilling and deeper drilling in the Spraberry
field. The budget increase also includes third-party service cost
inflation and utilizing more third-party equipment as a result of delays
in the delivery of certain Company-owned fracture stimulation equipment
earlier in the year. Third-party service cost inflation has been limited
to 3%, reflecting the significant benefits being generated by the
Company′s expanding vertical integration investments.?

'Owning fracture stimulation fleets, rigs and other service-related
equipment is not only enhancing the execution of our drilling program,
but it is also providing significant cash savings versus contracting for
these services at market rates. We estimate that by year-end 2011, the
Company′s annualized cash savings from vertical integration investments
compared to third-party services will be greater than $450 million per
year. To further ensure execution of our drilling program and reduce
costs by an additional $80 million per year beginning in 2012, we have
recently purchased additional well service equipment for the Spraberry
field and have ordered additional fracture stimulation fleets for
delivery in mid-2012. The related increase to our 2011 vertical
integration budget will be $100 million.?

'We are funding our drilling program for 2011 from forecasted operating
cash flow of $1.5 billion and the redeployment of a portion of the
proceeds from the sale of Tunisia earlier this year. Our forecasted
production growth generates a 30+% compound annual operating cash flow
growth over the 2011 through 2014 period. Pioneer has a strong financial
position, with a net debt-to-book capitalization of 32% as of June 30,
2011, and is committed to maintaining net debt-to-book capitalization
below 35% and net debt to operating cash flow at less than 1.75 times.?

Operations Update and Drilling Program

In the Spraberry field in West Texas, Pioneer′s drilling program has
continued to ramp up, with 35 rigs operating at mid-year, including 14
Company-owned rigs. The Company is accelerating its planned drilling
ramp-up in the field and is on track to increase to 45 rigs by year-end
2011 instead of during 2012.

As Pioneer ramps up drilling in the Spraberry field, the Company
continues to expand its integrated services to control drilling costs
and support the execution of its accelerated drilling program. Four
Company-owned fracture stimulation fleets are currently operating, with
one additional fleet scheduled to be operational during the fourth
quarter of 2011. To support its growing operations, the Company also
owns other oil 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, forecasted fracture stimulation sand supply requirements through
2015 and well cementing services through 2016.

Vertical integration in the Spraberry field is saving Pioneer up to $500
thousand per well compared to utilizing third-party services at market
rates. Pioneer expects that its vertical integration equipment will
provide approximately one third of its rig requirements and two thirds
of its fracture stimulation requirements in 2011. As a result, the
blended Pioneer and third-party 2011 well cost is expected to average
$1.5 million to $1.6 million per well. Pioneer′s internal rate of return
on its 2011 Spraberry drilling program is expected to be 45% before tax
based on current NYMEX strip commodity prices and estimated future
production costs.

The Company′s increasing fracture stimulation capacity in the Spraberry
field is accelerating the pace at which wells are being placed on
production as evidenced by 146 wells being placed on production during
the second quarter, an increase of 50 wells from the first quarter.
Further increases are expected during the second half of the year.

Second quarter production from the Spraberry field averaged 41 MBOEPD.
Spraberry production was reduced by approximately 2 MBOEPD due to a
shortage of third-party oil transport trucks in the Permian Basin. The
truck shortage was primarily caused by third-party transporters
diverting their trucks to other areas. To alleviate this shortage and
cover forecasted production growth, Pioneer has contracted with several
third parties for additional oil transport trucks beginning in the third
quarter. The Company is also aggressively adding new gathering pipelines
to reduce trucking requirements.

As a result of the Company′s initiatives to increase the rate at which
wells are placed on production and add incremental oil transportation
capacity, Spraberry production is forecasted to continue to grow
quarterly over the remainder of the year, with full-year 2011 production
expected to average 43 MBOEPD to 46 MBOEPD. Production is forecasted to
further increase to 54 MBOEPD to 59 MBOEPD in 2012, 68 MBOEPD to 74
MBOEPD in 2013 and 77 MBOEPD to 84 MBOEPD in 2014. The forecast for 2012
represents an increase of approximately 5% to the previous forecast for
2012 as a result of increasing the rig count from 35 rigs to 45 rigs by
the end of 2011 instead of during 2012. The accelerated rig count growth
is also expected to benefit production in 2013 and 2014.

During 2010, Pioneer successfully added incremental production and
proved reserves from vertical completions in the Lower Wolfcamp and
organic rich shale/silt intervals. The testing of deeper intervals below
the Wolfcamp in certain areas of the field is now underway. This deeper
interval testing includes the Strawn, the Atoka and, more recently, the
Mississippian intervals. The Company anticipates a potential increase of
up to 110 thousand barrels oil equivalent (MBOE) in the estimated
ultimate recovery (EUR) of a Spraberry well in areas of the field where
the Strawn and Atoka intervals are both present.

Pioneer has completed 85 Spraberry wells in the Strawn interval since
the testing program began in 2010. Initial peak production rates from
this interval, when tested alone, have averaged 70 barrels oil
equivalent per day (BOEPD). Production data to date suggests a potential
incremental EUR per well of 20 MBOE to 40 MBOE from the Strawn interval.
The incremental cost per well for this deeper drilling and one
additional fracture stimulation stage is approximately $60 thousand.
Pioneer believes the Strawn interval is prospective in 40% of its
Spraberry acreage and expects to complete and commingle this interval
with upper intervals in 25% of the wells in its 2011 drilling program.

The Company completed its first two vertical Atoka wells in the second
quarter of 2011. The initial peak production rate from this interval
alone averaged 150 BOEPD. The Company plans to test the Atoka interval
for six months and then comingle this production with production from
upper intervals. The incremental cost to drill an Atoka well ranges from
approximately $250 thousand to $750 thousand. The high end of the range
reflects deeper drilling, adding an intermediate casing string and a CO₂
fracture stimulation, while the low end of the range reflects shallower
drilling and a water fracture stimulation, but no intermediate casing
string. The Company plans to test 10 Atoka wells in 2011. Pioneer
believes the Atoka interval is prospective in 25% to 50% of its
Spraberry acreage. Incremental EURs per well from this interval are
estimated to range from 50 MBOE to 70 MBOE based on offset well data.

Pioneer completed its first vertical test of the Mississippian interval
in the second quarter, with an initial peak production rate of 105
BOEPD. The incremental cost per well for this deeper drilling and one
additional fracture stimulation stage is approximately $150 thousand to
$250 thousand. Offset well data indicates a potential incremental EUR
per well of 15 MBOE to 30 MBOE. Pioneer believes the Mississippian
interval is prospective in 10% to 20% of its Spraberry acreage. The
Company expects to drill 24 wells to test the play, with 10 of these
wells scheduled for 2011.

The Company has one rig dedicated towards research and development of
horizontal drilling applications in multiple intervals of the Spraberry
field. The first well to test the Lower Wolfcamp shale interval was a
3,500-foot lateral with a 15-stage fracture stimulation completion. The
well had an initial production rate of 200 barrels oil per day and 120
thousand cubic feet (MCF) of gas per day with less than 50% of its load
water recovered. The program calls for drilling six more horizontal
wells during the second half of 2011 targeting the Tippett Shale (Middle
Wolfcamp) and Jo Mill (Middle Spraberry) intervals. The first Tippett
Shale well, with a planned lateral section of 6,000 feet and a 30-stage
fracture stimulation completion, is currently being drilled.

The Company continues to test downspacing in the Spraberry field from 40
acres to 20 acres. Twenty-four 20-acre wells have been drilled since
2010. These 20-acre wells are producing from the Lower Wolfcamp, Strawn
and shale/silt intervals. Results continue to indicate production from
these wells is outperforming the previous 110 MBOE type curve for a
traditional Spraberry/Dean well. The Company expects to drill 10 to 20
additional 20-acre downspaced wells in 2011.

Water injection was initiated in the third quarter of 2010 on the
Company′s 7,000-acre waterflood project in the Upper Spraberry interval.
Results continue to be encouraging, as the production decline from 110
producing wells in the surveillance area continues to flatten. Oil
production response has also been observed in additional wells, with no
premature water breakthrough. Based on the results of historical
waterflood projects, an ultimate 50% uptick in production from the
flooded Upper Spraberry interval is expected.

In the highly prospective Eagle Ford Shale in South Texas, Pioneer and
its joint venture partners have increased the rig count from 9 rigs in
the second quarter to 12 rigs currently, with expected further increases
to 14 rigs in early 2012, 16 rigs in early 2013 and 19 rigs in 2014. To
improve the execution of its drilling and completions program and reduce
costs, Pioneer purchased two fracture stimulation fleets for its Eagle
Ford Shale completions. One fleet was placed in service in April and the
other fleet is expected to be operational during the fourth quarter of
2011. The Company also entered into a two-year contract for a dedicated
third-party fracture stimulation fleet, which commenced operating in
April. With the start-up of these two fleets and some spot market
fracture stimulation capacity that became available for a short period
in the second quarter, Pioneer was able to increase the number of wells
placed on production from 5 wells in the first quarter to 18 wells in
the second quarter. Further increases in the number of wells placed on
production are expected during the second half of the year.

Six central gathering plants (CGPs) have been completed as part of the
joint venture′s Eagle Ford Shale midstream business. The seventh CGP is
scheduled to commence operation during the third quarter, with the
eighth CGP expected to commence operation in the fourth quarter.

Pioneer′s gross well cost in the Eagle Ford Shale ranges from $7 million
to $8 million per well. Using this cost and current NYMEX strip
commodity prices, and excluding the benefit of the joint-venture
drilling carry, before tax internal rates of return are estimated to be
greater than 100% for high condensate yield wells (200 barrels per
million cubic feet) and 75% for lean condensate yield wells (60 barrels
per million cubic feet).

As a result of the increased rig count and fracture stimulation capacity
in the Eagle Ford Shale, Pioneer increased its Eagle Ford Shale
production from 5 MBOEPD in the first quarter to 8 MBOEPD in the second
quarter. With the number of wells placed on production expected to
further increase during the second half of 2011 and future years, annual
production is forecasted to average 12 MBOEPD to 15 MBOEPD in 2011 and
grow to 26 MBOEPD to 30 MBOEPD in 2012, 40 MBOEPD to 45 MBOEPD in 2013
and 54 MBOEPD to 60 MBOEPD in 2014.

In the liquids-rich Barnett Shale Combo play, Pioneer has built a
72,000-acre position, representing more than 600 drilling locations.
Pioneer is currently operating two rigs in the play. The Company has
acquired 160 square miles of 3-D seismic covering its acreage and is in
the process of permitting an additional 190 square miles. Fourteen wells
were placed on production during the second quarter with 7-day initial
production rates averaging 350 BOEPD, including the incremental uplift
from natural gas liquids (NGLs).

Production in the second quarter for the Barnett Shale Combo play was 3
MBOEPD, up from 2 MBOEPD in the first quarter. The Company expects to
generate quarterly production growth over the remainder of 2011 and
average 4 MBOEPD to 5 MBOEPD for the full year. The Company plans to
increase the rig count from 2 rigs in 2011 to 4 rigs in 2012, which is
expected to further increase production to 9 MBOEPD to 12 MBOEPD in
2012, 18 MBOEPD to 22 MBOEPD in 2013 and 26 MBOEPD to 31 MBOEPD in 2014.
Assuming current NYMEX strip commodity prices, an average per well
drilling cost of $3 million and a gross EUR of 320 MBOE, Pioneer′s
internal rate of return in the Barnett Shale Combo play is expected to
be 50% before tax. A Pioneer-owned fracture stimulation fleet commenced
operating in the play during the second quarter.

2011 Capital Budget

Pioneer′s capital budget for 2011 is being increased from $1.8 billion
to $2.1 billion, consisting of $1.8 billion for drilling operations and
$300 million for vertical integration and facilities. Of the $300
million increase, $200 million is attributable to drilling and $100
million to vertical integration. The 2011 budget excludes acquisitions,
asset retirement obligations, capitalized interest and geological and
geophysical G&A.

The increase of $200 million for drilling is primarily due to:

• 
  deeper drilling to the Strawn, Atoka and Mississippian intervals in
  the Spraberry field and the Company′s horizontal research and
  development drilling program in the field ($50 million),
  
• 
  increasing from 35 rigs to 45 rigs in the Spraberry field by year end,
  which is earlier than anticipated ($50 million),
  
• 
  the unplanned use of third-party fracture stimulation services due to
  delays in the delivery of Company-owned equipment during the first
  half of 2011 ($50 million) and
  
• 
  third-party service cost creep of only 3% ($50 million), reflecting
  the substantial benefits of the Company′s vertical integration
  investments, particularly in fracture stimulation fleets.
  

The increase of $100 million for vertical integration is primarily due
to:

• 
  adding well service and water trucks in the Spraberry field and
  
• 
  ordering additional Company-owned fracture stimulation fleets for
  delivery in mid-2012.
  

Benefits from the increased capital spending for drilling and vertical
integration include:

• 
  increasing the Company′s production growth target for 2012 from 18+%
  to 20+%, resulting primarily from increasing the Spraberry production
  forecast from 52 MBOEPD to 56 MBOEPD to 54 MBOEPD to 59 MBOEPD,
  
• 
  adding incremental EUR from deeper Spraberry intervals,
  
• 
  funding the Spraberry horizontal research and development program and
  
• 
  increasing annual cash savings from vertical integration by an
  incremental $80 million in 2012 compared to current third-party
  service cost rates (year-end 2011 annualized cash savings estimated to
  be greater than $450 million).
  

The revised 2011 drilling capital of $1.8 billion continues to be
focused on oil and liquids-rich drilling, with 75% of the capital
allocated to the Spraberry and Eagle Ford Shale plays. The following
provides a breakdown of the forecasted spending by asset:

• 
  Spraberry - $1.3 billion
  
• 
  Eagle Ford Shale - $120 million (reflects 25% of anticipated 2011
  drilling costs; remaining 75% covered by drilling carry from Reliance
  Industries Limited)
  
• 
  Barnett Shale Combo - $210 million
  
• 
  Alaska - $100 million
  
• 
  Other assets - $100 million
  

The vertical integration funds of $300 million are for the expansion of
Pioneer′s integrated well service operations in the Spraberry field, the
establishment of similar services in the Eagle Ford Shale and Barnett
Shale Combo plays, and the build-out of facilities to support vertical
integration (yards, buildings and shops). This spending is being
recorded in Other Property and Equipment.

Eagle Ford Shale Midstream Operations

Pioneer′s share of its Eagle Ford Shale joint-venture midstream
activities is conducted through a partially-owned, unconsolidated
entity. Beginning in June 2011, funding for the ongoing midstream
infrastructure build-out is being provided from external debt sources.
Cash flow from the services provided by the midstream operations is not
included in Pioneer′s forecasted operating cash flow of $1.5 billion in
2011.

Second Quarter 2011 Financial Review

The following financial results for the second quarter of 2011 reflect
continuing operations.

Sales averaged 119 MBOEPD, consisting of oil sales averaging 36 thousand
barrels per day (MBPD), NGL sales averaging 22 MBPD and gas sales
averaging 362 million cubic feet per day.

The average reported price for oil was $104.35 per barrel and included
$3.38 per barrel related to deferred revenue from volumetric production
payments (VPPs) for which production was not recorded. The average
reported price for NGLs was $48.16 per barrel. The average reported
price for gas was $4.31 per MCF.

Production costs averaged $12.82 per barrel oil equivalent (BOE), a
decrease of $0.49 per BOE from the first quarter of 2011. This decrease
was primarily related to increased third-party throughput volumes at
Pioneer′s natural gas processing facilities, higher NGL price
realizations on third-party volumes and reduced gathering system
operating costs.

Depreciation, depletion and amortization (DD&A) expense averaged $14.26
per BOE. Exploration and abandonment costs were $20 million for the
quarter and included $3 million of acreage abandonments and $17 million
of geologic and geophysical expenses and personnel costs.

Third Quarter 2011 Financial Outlook

The Company′s third quarter 2011 outlook for certain operating and
financial items is provided below.

Production is forecasted to average 125 MBOEPD to 131 MBOEPD. South
Africa production is currently shut in due to unplanned third-party
gas-to-liquids plant downtime. Production guidance excludes the
potential for this downtime to be extended beyond four weeks.

Production costs are expected to average $12.00 to $14.00 per BOE, based
on current NYMEX strip commodity prices. DD&A expense is expected to
average $13.50 to $15.00 per BOE. Total exploration and abandonment
expense is forecasted to be $25 million to $35 million.

General and administrative expense is expected to be $45 million to $50
million, interest expense is expected to be $44 million to $48 million,
and other expense is expected to be $20 million to $30 million.
Accretion of discount on asset retirement obligations is expected to be
$2 million to $4 million.

Noncontrolling interest in consolidated subsidiaries′ income, excluding
unrealized derivative mark-to-market adjustments, is expected to be $9
million to $12 million, primarily reflecting the public ownership in
Pioneer Southwest Energy Partners L.P.

The Company′s effective income tax rate is expected to range from 35% to
45% based on current capital spending plans and the assumption of no
significant unrealized derivative mark-to-market changes in the
Company′s derivative position. Current income taxes are expected to be
$5 million to $10 million and are primarily attributable to South Africa.

The Company′s financial and derivative mark-to-market results, open
derivatives positions for oil, NGL and gas, amortization of net deferred
gains on discontinued commodity hedges and future VPP amortization are
outlined on the attached schedules.

Earnings Conference Call

On Thursday, August 4, 2011, at 10:00 a.m. Central Time, Pioneer will
discuss its financial and operating results for the quarter ended June
30, 2011, with an accompanying presentation. Instructions for listening
to the call and viewing the accompanying presentation are shown below.

Internet: www.pxd.com

Select 'Investors,? then 'Earnings Calls & Webcasts? to listen to the
discussion and view the presentation.

Telephone: Dial (877) 741-4245 confirmation code: 3333505 five minutes
before the call. View the presentation via Pioneer′s internet address
above.

A replay of the webcast will be archived on Pioneer′s website. A
telephone replay will be available through August 25 by dialing (888)
203-1112 confirmation code: 3333505.

Pioneer is a large independent oil and gas exploration and production
company, headquartered in Dallas, Texas, with operations primarily in
the United States. For more information, visit Pioneer′s website at www.pxd.com.

Except for historical information contained herein, the statements in
this news release 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 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 include, among other things, volatility of commodity
prices, product supply and demand, competition, the ability to obtain
environmental and other permits and the timing thereof, other government
regulation or action, the ability to obtain approvals from third parties
and negotiate agreements with third parties on mutually acceptable
terms, litigation, the costs and results of drilling and operations,
availability of equipment, services and personnel required to complete
the Company′s operating activities, access to and availability of
transportation, processing and refining facilities, Pioneer's ability to
replace reserves, implement its business plans or complete its
development activities as scheduled, access to and cost of capital, the
financial strength of counterparties to Pioneer′s credit facility and
derivative contracts and the purchasers of Pioneer′s oil, NGL and gas
production, uncertainties about estimates of reserves and resource
potential and the ability to add proved reserves in the future, the
assumptions underlying production forecasts, quality of technical data,
environmental and weather risks, including the possible impacts of
climate change, international operations and acts of war or terrorism.
These and other risks are described in Pioneer's 10-K and 10-Q Reports
and other filings with the Securities and Exchange Commission. In
addition, Pioneer may be subject to currently unforeseen risks that may
have a materially adverse impact on it. Pioneer undertakes no duty to
publicly update these statements except as required by law.

Cautionary Note to U.S. Investors -- The U.S. Securities and Exchange
Commission (the 'SEC?) prohibits oil and gas companies, in their filings
with the SEC, from disclosing estimates of oil or gas resources other
than 'reserves,? as that term is defined by the SEC. In this news
release, Pioneer includes estimates of quantities of oil and gas using
certain terms, such as 'resource potential,? 'estimated ultimate
recovery,? 'EUR? or other descriptions of volumes of reserves, which
terms include quantities of oil and gas that may not meet the SEC′s
definitions of proved, probable and possible reserves, and which the
SEC's guidelines strictly prohibit Pioneer from including in filings
with the SEC. These estimates are by their nature more speculative than
estimates of proved reserves and accordingly are subject to
substantially greater risk of being recovered by Pioneer. U.S. investors
are urged to consider closely the disclosures in the Company′s periodic
filings with the SEC.Such filings are available from the Company
at 5205 N. O′Connor Blvd., Suite 200, Irving, Texas 75039,
Attention: Investor Relations, and the Company′s website at www.pxd.com.
These filings also can be obtained from the SEC by calling
1-800-SEC-0330.

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY EARNINGS PER SHARE INFORMATION

The Company uses the two-class method of calculating basic and diluted
earnings per share. Under the two-class method of calculating earnings
per share, GAAP provides that share- and unit-based awards with
guaranteed dividend or distribution participation rights qualify as
'participating securities' during their vesting periods. The Company's
basic net income per share attributable to common stockholders is
computed as (i)  net income attributable to common stockholders,
(ii)  less participating share- and unit-based basic earnings
(iii)  divided by weighted average basic shares outstanding. The
Company's diluted net income per share attributable to common
stockholders is computed as (i)  basic net income attributable to common
stockholders, (ii)  plus the reallocation of participating earnings
(iii)  divided by weighted average diluted shares outstanding. During
periods in which the Company realizes a loss from continuing operations
attributable to common stockholders, securities or other contracts to
issue common stock would be dilutive to loss per share; therefore,
conversion into common stock is assumed not to occur.

The following table is a reconciliation of the Company's net income
attributable to common stockholders to basic net income attributable to
common stockholders and to diluted net income attributable to common
stockholders for the three and six months ended June 30, 2011 and 2010:

The following table is a reconciliation of basic weighted average common
shares outstanding to diluted weighted average common shares outstanding
for the three and six months ended June 30, 2011 and 2010:

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES

(in
thousands)

EBITDAX and discretionary cash flow ('DCF') (as defined below) are
presented herein, and reconciled to the generally accepted accounting
principle ('GAAP') measures of net income and net cash provided by
operating activities because of their wide acceptance by the investment
community as financial indicators of a company's ability to internally
fund exploration and development activities and to service or incur
debt. The Company also views the non-GAAP measures of EBITDAX and DCF as
useful tools for comparisons of the Company's financial indicators with
those of peer companies that follow the full cost method of accounting.
EBITDAX and DCF should not be considered as alternatives to net income
or net cash provided by operating activities, as defined by GAAP.

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY NON-GAAP FINANCIAL MEASURES (continued)

(in
millions, except per share data)

Income adjusted for unrealized mark-to-market ('MTM') derivative gains,
and income adjusted for unrealized MTM derivative gains and unusual
items, as presented in this press release, are presented and reconciled
to Pioneer's net income attributable to common stockholders that is
determined in accordance with GAAP because Pioneer believes that these
non-GAAP financial measures reflect an additional way of viewing aspects
of Pioneer's business that, when viewed together with its financial
results computed in accordance with GAAP, provide a more complete
understanding of factors and trends affecting its historical financial
performance and future operating results, greater transparency of
underlying trends and greater comparability of results across periods.
In addition, management believes that these non-GAAP measures may
enhance investors' ability to assess Pioneer's historical and future
financial performance. These non-GAAP financial measures are not
intended to be substitutes for the comparable GAAP measures and should
be read only in conjunction with Pioneer's consolidated financial
statements prepared in accordance with GAAP. Unrealized MTM net
derivative gains and losses and net discontinued operations will recur
in future periods; however, the amount and frequency of each item can
vary significantly from period to period. The table below reconciles
Pioneer's net income attributable to common stockholders for the three
months ended June 30, 2011, as determined in accordance with GAAP, to
income adjusted for unrealized MTM derivative gains, and income adjusted
for unrealized MTM derivative gains and unusual items, for that quarter.