Pioneer Natural Resources Reports Third 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 September 30, 2011.

Pioneer reported third quarter net income attributable to common
stockholders of $351 million, or $2.95 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 $191 million after tax, or $1.60 per diluted share.
Without the effect of this item, adjusted income for the third quarter
would have been $160 million, or $1.35 per diluted share. Also included
in Pioneer′s third quarter results was income of $26 million after tax,
or $0.21 per diluted share, related to unwinding certain oil and
interest rate derivatives.

Scott Sheffield, Chairman and CEO, stated, 'The Company delivered
another strong quarter, with production increasing to 128 thousand
barrels oil equivalent per day (MBOEPD), an increase of 9 MBOEPD, or 8%,
from the second quarter of 2011. This follows an increase of 7 MBOEPD,
or 7%, from the first quarter to the second quarter. Our three core
Texas liquids-rich growth assets, the Spraberry field, Eagle Ford Shale
and the Barnett Shale Combo, were the drivers of these quarterly
production increases. Fourth quarter production is forecasted to grow by
approximately 10 MBOEPD, reflecting the continued successful drilling in
these three assets. For 2011, production is expected to average
approximately 125 MBOEPD.?

'Based on our drilling plans for the Spraberry field, the Eagle Ford
Shale and the Barnett Shale Combo play, we expect the Company to deliver
production growth of 20+% in 2012 compared to 2011 and U.S. production
growth of 22+%. We also expect the Company to achieve a compound annual
production growth rate of 18+% through 2014, with liquids increasing
from 44% of total production in 2010 to 60% in 2014. This strong,
liquids-focused production growth is forecasted to generate compound
annual operating cash flow growth of 30+% over the 2011-2014 period.?

'We are excited about the successful horizontal well we recently
completed in the Wolfcamp Shale. It continues to flow naturally with a
peak seven-day average rate of 732 barrels oil equivalent per day
(BOEPD) and a peak 24-hour rate of 854 BOEPD, even with flow line
restrictions. This result, coupled with the strong production from other
industry players drilling horizontal wells in this interval and
Pioneer′s extensive geologic interpretation of the area, suggests
significant horizontal Wolfcamp Shale potential exists within Pioneer′s
acreage. We are currently focusing our efforts on more than 200,000
acres in the southern part of the field. We plan to drill three
additional horizontal Wolfcamp Shale wells by early 2012 and expect to
expand our horizontal drilling program in this area next year.?

'Owning fracture stimulation fleets, drilling 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 will be greater than $450 million.?

'We are funding our 2011 capital program of $2.1 billion from forecasted
operating cash flow of $1.4 billion to $1.5 billion and the redeployment
of proceeds from the sale of Tunisia. Pioneer has a strong financial
position, with a net debt-to-book capitalization of 31% as of September
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

The Spraberry field and the Eagle Ford Shale are the two most active
plays in the U.S., with the industry operating 225 rigs and 200 rigs in
each play, respectively. Pioneer is a drilling, production and
technology leader in both of these liquids-rich, high-margin plays.

In the Spraberry oil field in West Texas, Pioneer has increased its
drilling program to an average of 38 rigs in the third quarter,
including 15 Company-owned rigs. The Company has continued to expand its
integrated services to control drilling costs and support the execution
of its accelerated drilling program. Five Company-owned fracture
stimulation fleets are currently operating in the Spraberry field. 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 forecasted 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 its vertical integration equipment will provide
approximately one third of its rig requirements and two thirds of its
fracture stimulation requirements by the end of 2011. As a result, the
blended Pioneer and third-party well cost is expected to average $1.5
million to $1.6 million per well for 2011. Pioneer′s internal rate of
return on its 2011 Spraberry drilling program is expected to be
approximately 40% before tax based on flat commodity prices of $90 per
barrel for oil and $5 per thousand cubic feet (MCF) for gas, estimated
future production costs and an estimated ultimate recovery (EUR) of 140
thousand barrels oil equivalent (MBOE) for a vertical well completed
through the Lower Wolfcamp.

During 2010, Pioneer successfully added incremental production and
proved reserves from vertical completions in the Lower Wolfcamp and
organic rich shale/silt intervals. The Company is also continuing to
drill deeper intervals below the Wolfcamp in certain areas of the field.
This deeper drilling includes the Strawn, the Atoka and the
Mississippian intervals. The Company anticipates a potential increase of
up to 110 MBOE in the EUR of a Lower Wolfcamp well in areas of the field
where the Strawn and Atoka intervals are both present.

Pioneer has completed 113 vertical wells in the Strawn interval since
the drilling program began in 2010. Initial peak production rates from
this interval, when tested alone, have averaged 70 BOEPD. For wells that
have been on production for at least ten months, production has
increased by more than 25% compared to offset wells that have been
drilled only to the Lower Wolfcamp. This data 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 all zones in 25% of the vertical wells drilled in the fourth
quarter of 2011 and during 2012.

The Company completed its third vertical Atoka well in the third quarter
of 2011. The initial peak production rate from this interval alone
averaged 127 BOEPD. The Company plans to test the Atoka interval for
approximately six months and will then commingle this production with
production from all zones. The incremental cost to drill an Atoka well
ranges from approximately $300 thousand to $350 thousand as a result of
deeper drilling, larger casing and two additional fracture stimulation
stages. 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. The Company plans to test two to three additional single-zone
Atoka wells in the fourth quarter and is forecasting that 15% to 20% of
its 2012 vertical drilling program in the Spraberry will include wells
drilled to the Atoka interval, with production commingled from all zones.

Pioneer completed its second vertical test of the Mississippian interval
in the third quarter, with an initial peak production rate of 92 BOEPD.
The incremental cost per well for this deeper drilling, larger casing
and two additional fracture stimulation stages is approximately $300
thousand to $350 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 complete one to two additional
single-zone wells in the fourth quarter and is forecasting that 10% of
its 2012 vertical drilling program in the Spraberry will include wells
drilled to the Mississippian interval, with production commingled from
all zones.

The Company continues to test vertical downspacing in the Spraberry
field from 40 acres to 20 acres. Eleven 20-acre vertical wells have been
drilled during 2011, with six put on production. These 20-acre wells are
producing from the Lower Wolfcamp, Strawn and shale/silt intervals. As
was the case with 20-acre wells drilled during 2010, results continue to
indicate that production from these wells is significantly outperforming
the previous 110 MBOE type curve for a traditional Spraberry/Dean well.
The Company expects to drill three to five additional 20-acre downspaced
wells in 2011 and is targeting 30 to 50 20-acre wells in its 2012
vertical drilling program.

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 has flattened and an increase
in production is now being observed. Cumulative production from the area
flooded in the Upper Spraberry has increased by greater than 10%
compared to forecasted base production decline, with further increases
expected as additional wells respond to the water injection. Based on
these early results, reserve adds related to the waterflood are likely
during 2011.

The Company has one dedicated rig drilling horizontal wells in the
Wolfcamp Shale in the Spraberry field area. The Company successfully
completed its first horizontal well in Upton County, Texas with a
30-stage fracture stimulation in a 5,800-foot lateral section. The XBC
Giddings Estate 2041H continues to flow naturally with a peak seven-day
average rate of 732 BOEPD (591 barrels oil per day, 86 barrels natural
gas liquids (NGLs) per day and 332 MCF per day), and a peak 24-hour rate
of 854 BOEPD (686 barrels oil per day, 102 barrels NGLs per day and 395
MCF per day), even with flow line restrictions. Pioneer′s micro-seismic
analysis of the completion showed that the entire 800 foot thick target
zone was successfully fracture stimulated. The well is producing to
sales.

The results of the XBC Giddings 2041H well are encouraging, as this well
is 30 miles to 60 miles northwest of the area where most of the recent
successful industry drilling of horizontal Wolfcamp Shale wells has been
occurring. Based on this successful drilling activity and Pioneer′s
extensive geologic interpretation of the Wolfcamp Shale, the Company
believes it has significant horizontal Wolfcamp Shale potential within
its acreage and is currently focusing its efforts on more than 200,000
acres in the southern part of the field. Pioneer has not been drilling
vertical Spraberry wells in this area because the returns are marginal
and the southern acreage is not prospective for the deeper Strawn, Atoka
and Mississippian intervals.

Pioneer is currently drilling its second horizontal Wolfcamp Shale well
in Upton County with a planned 6,000-foot lateral section and 30-stage
fracture stimulation. Two additional horizontal Wolfcamp Shale wells are
planned in southern Reagan County by early 2012. These two wells are
expected to test longer lateral lengths and additional fracture
stimulation stages. Pioneer expects to expand its horizontal drilling
program in 2012.

Third quarter production from the Spraberry field averaged 47 MBOEPD, an
increase of 6 MBOEPD from the second quarter. Current production is
approximately 51 MBOEPD. Spraberry production is forecasted to continue
to grow to 51 MBOEPD to 53 MBOEPD in the fourth quarter, with full-year
2011 production expected to be towards the high end of the Company′s
full-year average guidance of 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 through 2014 excludes the potential contributions from
drilling vertical wells deeper to intervals below the Lower Wolfcamp and
the impacts from the expected expansion of horizontal Wolfcamp Shale
drilling.

In the liquids-rich Eagle Ford Shale in South Texas, Pioneer and its
joint venture partners are currently running 12 rigs. 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 later in the fourth quarter.
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, Pioneer has been able to
significantly increase the number of wells put on production, with a
further increase expected when the second Company-owned fleet commences
operations later this quarter.

The Company continues to see strong performance from its Eagle Ford
Shale drilling program. Wells drilled during the third quarter continued
to yield approximately 65% liquids, consisting of oil, condensate and
NGLs. The lateral length of each well continues to average approximately
5,500 feet and is being completed with a 13-stage fracture stimulation.

Eight central gathering plants (CGPs) have been completed as part of the
joint venture′s Eagle Ford Shale midstream business. Three additional
CGPs are planned for 2012. 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 ongoing midstream infrastructure build-out costs that are in excess
of operating cash flow are expected to be 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 $1.4 billion to $1.5 billion in 2011.

Pioneer′s gross well cost in the Eagle Ford Shale ranges from $7 million
to $8 million per well. Using this cost, flat commodity prices of $90
per barrel for oil and $5 per MCF for gas, estimated future production
costs, and excluding the benefit of the joint-venture drilling carry,
before tax internal rates of return are estimated to be 80% for high
condensate yield wells (200 barrels per million cubic feet) and 60% for
lean condensate yield wells (60 barrels per million cubic feet).

Pioneer has been testing the use of lower-cost white sand instead of
ceramic proppant to fracture stimulate wells drilled in shallower areas
of the field. Twenty wells have been tested to date, with a savings of
approximately $700 thousand per well. Early well performance has been
similar to direct offset ceramic-stimulated wells. Pioneer plans to
continue to monitor the performance of these wells and plans to use
white sand in approximately 30% of its 2012 drilling program.

Pioneer increased its Eagle Ford Shale production from 8 MBOEPD in the
second quarter to 14 MBOEPD in the third quarter as it continued to
successfully bring new wells on production. Current production is
approximately 20 MBOEPD. A further increase to 20 MBOEPD to 23 MBOEPD is
forecasted for the fourth quarter. As a result, annual production for
2011 is forecasted to average 12 MBOEPD to 15 MBOEPD 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
76,000-acre position, representing more than 700 drilling locations.
Pioneer is currently operating two rigs in the play. The Company
continued to see performance from new wells improve in the third
quarter. Production is liquids-rich, with approximately 75% of the
production being oil and NGLs.

Production in the third quarter for the Barnett Shale Combo play was 4
MBOEPD, up from 3 MBOEPD in the second quarter. Current production is
approximately 5 MBOEPD. The Company expects production to increase to 5
MBOEPD to 7 MBOEPD in the fourth quarter and average 4 MBOEPD to 5
MBOEPD for the full year. Current plans call for a further increase in
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 flat commodity prices
of $90 per barrel for oil and $5 per MCF for gas, estimated future
production costs, 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 40% before tax.

South Africa production was shut in for approximately three weeks during
the third quarter due to unplanned third-party gas-to-liquids plant
downtime. As a result, Pioneer′s third quarter production was reduced by
approximately 1 MBOEPD. The plant was again shut down in late September
due to an unrelated issue and has just come back on line at the end of
October. As a result, Pioneer′s fourth quarter production guidance has
been reduced by approximately 1.5 MBOEPD.

Third Quarter 2011 Financial Review

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

Sales averaged 128 MBOEPD, consisting of oil sales averaging 43 thousand
barrels per day (MBPD), NGL sales averaging 23 MBPD and gas sales
averaging 370 million cubic feet per day (MMCFPD). Compared to the
second quarter, third quarter oil sales increased by 6 MBPD, primarily
due to continued successful drilling and the addition of incremental oil
transport trucks in the Spraberry field. NGL sales during the third
quarter were essentially flat compared to the second quarter due to
unplanned downtime and takeaway limitations at the Midkiff/Benedum
plants in the Spraberry field. The plants are now back in full
operations and the takeaway limitations have been resolved. Gas sales
during the third quarter increased by 9 MMCFPD compared to the second
quarter as higher sales in the Eagle Ford Shale and Barnett Shale Combo
were partly offset by unplanned plant downtime in South Africa and the
constraints at Midkiff/Benedum.

The average reported price for oil was $92.24 per barrel and included
$2.88 per barrel related to deferred revenue from volumetric production
payments (VPPs) for which production was not recorded. The average
reported price for NGLs was $48.36 per barrel. The average reported
price for gas was $4.24 per MCF.

Production costs averaged $13.47 per barrel oil equivalent (BOE), an
increase of $0.65 per BOE from the second quarter of 2011. This increase
was primarily due to higher lease operating expenses related in large
part to increases in labor rates, chemical costs and electricity rates.
Higher natural gas processing expenses increased as a result of
unplanned downtime and NGL takeaway limitations at the Midkiff/Benedum
plants.

Depreciation, depletion and amortization (DD&A) expense averaged $14.18
per BOE. Exploration and abandonment costs were $20 million for the
quarter and included $2 million of acreage abandonments and $18 million
of geologic and geophysical expenses and personnel costs.

Fourth Quarter 2011 Financial Outlook

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

Production is forecasted to average 136 MBOEPD to 141 MBOEPD. South
Africa production was shut-in during the month of October due to
unplanned third-party gas-to-liquids plant downtime. The plant is now
back in operation, and production guidance for the quarter reflects the
October downtime and assumes the plant will be in full operation over
the remainder of the quarter.

Production costs are expected to average $12.50 to $14.50 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 $47 million to $52
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 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
40% 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
$10 million to $15 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 Wednesday, November 2, 2011, at 11:00 a.m. Central Time, Pioneer will
discuss its financial and operating results for the quarter ended
September 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) 718-5111 confirmation code: 3367644 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 November 30 by dialing (888)
203-1112 confirmation code: 3367644.

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.

_____________

(a) Average reported prices are attributable to continuing operations
and include the results of hedging activities and amortization of VPP
deferred revenue.

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 nine months ended September 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 nine months ended September 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.

_____________

(a) 'EBITDAX? represents earnings before depletion, depreciation and
amortization expense; exploration and abandonments; net hurricane
activity; unrealized mark-to-market derivative activity; accretion of
discount on asset retirement obligations; interest expense; income
taxes; (gain) loss on the disposition of assets, net; discontinued
operations; amortization of stock-based compensation; amortization of
deferred revenue and other noncash items.

(b) Discretionary cash flow equals cash flows from operating activities
before changes in operating assets and liabilities, cash activity
reflected in discontinued operations and hurricane activity, and cash
exploration expense.

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY NON-GAAP FINANCIAL MEASURES (continued)

(in millions, except per share data)

Adjusted income excluding unrealized mark-to-market ('MTM') derivative
gains, as presented in this press release, is presented and reconciled
to Pioneer's net income attributable to common stockholders that is
determined in accordance with GAAP because Pioneer believes that this
non-GAAP financial measure reflects an additional way of viewing aspects
of Pioneer's business that, when viewed together with its financial
results computed in accordance with GAAP, provides 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 this non-GAAP measure may enhance
investors' ability to assess Pioneer's historical and future financial
performance. This non-GAAP financial measure is not intended to be a
substitute for the comparable GAAP measure and should be read only in
conjunction with Pioneer's consolidated financial statements prepared in
accordance with GAAP. Unrealized MTM derivative gains and losses will
recur in future periods; however, the amount and frequency can vary
significantly from period to period. The table below reconciles
Pioneer's net income attributable to common stockholders for the three
months ended September 30, 2011, as determined in accordance with GAAP,
to adjusted income excluding unrealized MTM derivative gains for that
quarter.