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Pioneer Natural Resources Reports Fourth Quarter 2012 Financial and Operating Results and Announces 2013 Capital Budget



  Pioneer Natural Resources Reports Fourth Quarter 2012 Financial and
  Operating Results and Announces 2013 Capital Budget

Business Wire

DALLAS -- February 13, 2013

Pioneer Natural Resources Company (NYSE:PXD) (“Pioneer” or “the Company”)
today announced financial and operating results for the quarter ended December
31, 2012, and announced its 2013 capital budget.

Pioneer reported fourth quarter net income attributable to common stockholders
of $29 million, or $0.22 per diluted share (see attached schedule for a
description of the net income per diluted share calculation). Without the
effect of noncash derivative mark-to-market gains and other unusual items,
adjusted income for the fourth quarter was $107 million after tax, or $0.83
per diluted share.

Fourth quarter and other recent highlights included:

  * producing 165 thousand barrels oil equivalent per day (MBOEPD) in the
    fourth quarter, including Barnett Shale production (the Barnett Shale
    properties were reclassified from discontinued operations to continuing
    operations after the decision was made to discontinue efforts to divest of
    these properties),
  * producing 156 MBOEPD in the fourth quarter, excluding Barnett Shale
    production, which was in the middle of the Company’s fourth quarter
    guidance range of 154 MBOEPD to 158 MBOEPD (fourth quarter guidance
    excluded Barnett Shale production since it was classified as discontinued
    operations when the fourth quarter guidance was provided),
  * producing 156 MBOEPD from continuing operations in 2012 (includes Barnett
    Shale production), an increase of 29% compared to 2011 and at the top end
    of Pioneer’s full-year 2012 guidance; the strong production growth in 2012
    was driven by the Company’s drilling programs in the Spraberry vertical,
    horizontal Wolfcamp Shale, Eagle Ford Shale and Barnett Shale Combo areas,
  * delivering 264% drillbit reserve replacement (161 million barrels oil
    equivalent) at a drillbit finding and development cost, excluding pricing
    revisions, of $17.72 per barrel oil equivalent (BOE),
  * placing on production Pioneer’s first horizontal Wolfcamp Shale well in
    the B interval in Midland County, Texas, (24-hour peak initial flow rate
    of 1,693 barrels oil equivalent per day (BOEPD) and peak 20-day average
    natural flow rate of 1,510 BOEPD with approximately 75% oil content),
    which demonstrates the prospectivity of Pioneer’s northern
    Wolfcamp/Spraberry acreage that encompasses more than 600,000 gross acres,
  * initiating a two-year $1.0 billion horizontal drilling appraisal program
    of Pioneer’s northern Wolfcamp/Spraberry acreage, of which $0.4 billion is
    included in the 2013 drilling budget of $2.75 billion and the remainder is
    expected to be spent in 2014,
  * forecasting annual production growth of 12% to 16% from 2012 to 2013,
  * targeting 13% to 18% compound annual production growth for 2013 to 2015,
  * signing a $1.74 billion horizontal Wolfcamp Shale joint interest agreement
    with Sinochem, which equates to $21,000 per acre for approximately 10% of
    Pioneer’s aggregate Wolfcamp/Spraberry gross acreage position,
  * continuing to deliver improving horizontal Wolfcamp Shale results in the
    joint interest area, including:

       * placing on production Pioneer’s first horizontal Wolfcamp Shale well
         with a 10,000-foot lateral in the Upper B interval in Reagan County
         (24-hour peak flow rate of 1,203 BOEPD and peak 20-day average flow
         rate of 1,022 BOEPD with approximately 80% oil content);
       * placing on production Pioneer’s first Wolfcamp Shale Lower B interval
         well and a successful Wolfcamp Shale A interval well in Reagan County
         (both currently producing above type curve expectations);
       * well performance from existing wells continuing to meet type curve
         expectations; and
       * achieving targeted year-end 2012 horizontal Wolfcamp Shale production
         exit rate of 5 MBOEPD; and

  * increasing the Company’s estimated net resource potential from 6.7 billion
    barrels oil equivalent (BBOE) to greater than 8.0 BBOE, which includes 1.6
    BBOE from the southern horizontal Wolfcamp Shale joint interest area and
    3.0 BBOE from Pioneer’s northern Wolfcamp/Spraberry acreage.

Scott Sheffield, Chairman and CEO, stated, “Pioneer had another great year in
2012. We delivered strong production and reserve growth, while continuing to
be among the top performers in our peer group in total shareholder return. Our
extensive Midland Basin geologic analysis has identified multiple prospective
horizontal targets throughout Pioneer’s extensive 900,000-acre
Wolfcamp/Spraberry leasehold position with an aggregate estimated resource
potential of more than 4.6 BBOE. During 2012, we focused on appraising and
developing the southern 200,000 acres of the play. This culminated in the
signing of the joint interest agreement with Sinochem that will allow
horizontal development of the Wolfcamp Shale in this area to be accelerated.
We were also able to begin drilling horizontal wells on our northern acreage
to appraise the potential of the horizontal Wolfcamp Shale in this area. Early
results are extremely encouraging, and we are initiating a $1 billion dollar
appraisal program for 2013 and 2014 to confirm the estimated 3.0 BBOE of
resource potential we believe exists in our northern acreage, which should add
substantial net asset value to the Company.”

Mark-To-Market Derivative Gains and Unusual Items Included in Fourth Quarter
2012 Earnings

Pioneer’s fourth quarter earnings included unrealized mark-to-market gains on
derivatives of $14 million after tax, or $0.11 per diluted share.

Fourth quarter earnings also included a net charge of $92 million after tax,
or $0.72 per diluted share, related to the following unusual items:

  * a noncash impairment charge of $101 million after tax, or $0.78 per
    diluted share, to reduce the proved and unproved property basis of the
    Company’s Barnett Shale assets in Texas that were previously held for
    sale, partially offset by
  * Alaska production tax credit recoveries of $9 million after tax, or $0.06
    per diluted share.

Operations Update and Drilling Program

Pioneer’s successful horizontal Wolfcamp Shale and Jo Mill drilling results in
the Spraberry Trend Area field have led the Company to shift a significant
portion of its 2013 drilling activity from vertical drilling to more capital
efficient horizontal drilling. Pioneer is the largest acreage holder in the
Spraberry Trend Area field, where the Company believes it has greater than 4.6
BBOE of estimated resource potential from horizontal drilling based on its
extensive geologic data and its successful drilling results to date.

The Company recently signed an agreement with Sinochem to sell 40% of
Pioneer’s interest in 207,000 net acres leased by the Company in the southern
portion of the Spraberry Trend Area field for total consideration of $1.74
billion. At closing, Sinochem will pay $522 million in cash to Pioneer, before
normal closing adjustments, and will pay the remaining $1.2 billion by
carrying a portion of Pioneer’s share of future drilling and facilities costs.
The transaction is estimated to close by June 1, 2013, subject to governmental
and third-party approvals.

Under the agreement, Sinochem will acquire 82,800 net acres of leasehold held
by Pioneer in the Wolfcamp horizon. Pioneer retains 60% of its interest in the
Wolfcamp depths and deeper horizons, with Sinochem receiving 40% of Pioneer’s
interest. Pioneer will continue as operator and will conduct all leasing,
drilling, operations and marketing activities in the joint interest area. The
joint interest area covers defined portions of Upton, Reagan, Irion, Crockett
and Tom Green Counties in Texas. Pioneer retains its current working interests
in all horizons shallower than the Wolfcamp horizon.

In addition to funding its own drilling obligations for the horizontal
Wolfcamp Shale, Sinochem has agreed to fund 75% of Pioneer’s portion of
drilling and facilities costs after closing until the $1.2 billion of drilling
carry is fully utilized. At closing, Sinochem will pay its 40% share of net
expenditures in the joint interest area from the December 1, 2012 effective
date of the transaction to the closing date. Pioneer and Sinochem have agreed
to a development plan which forecasts the drilling of 86 horizontal Wolfcamp
Shale wells during 2013, increasing to 120 wells in 2014 and 165 wells in
2015.

Pioneer successfully drilled and completed 39 horizontal wells in the Wolfcamp
Shale joint interest area during 2012, of which 26 wells were placed on
production. Of the 26 wells on production, 22 wells were completed in the B
interval and 4 wells were completed in the A interval. Pioneer’s net
horizontal Wolfcamp Shale production in the joint interest area averaged 2
MBOEPD in 2012, with a year-end exit rate of 5 MBOEPD.

The thickness of the Wolfcamp B interval in the southern joint interest area
provides the opportunity to complete two stacked laterals in the interval
(referred to as Upper B interval and Lower B interval). The Company placed its
first Lower B interval well on production in the fourth quarter, which had an
initial 24-hour peak flow rate of 696 BOEPD. A Wolfcamp A interval well was
also placed on production in the fourth quarter with initial 24-hour peak flow
rate of 442 BOEPD. Both wells had an oil content of approximately 80% and
continue to produce above the 575 thousand barrel oil equivalent (MBOE)
average estimated ultimate recovery (EUR) type curve for horizontal Wolfcamp
Shale wells in the southern joint interest area.

Pioneer also placed its first horizontal Wolfcamp Shale well with a
10,000-foot lateral on production during January 2013. It had an initial peak
24-hour production rate of 1,203 BOEPD and an average peak 20-day flow rate of
1,022 BOEPD. The oil content of this well is approximately 80%. The
performance of this well is substantially above the 650 MBOE EUR type curve
that reflects the performance of the two horizontal Wolfcamp Shale B interval
wells that were drilled in the Giddings area of Upton County by Pioneer in
2011.

Pioneer expects to run 7 rigs in the southern joint interest area during 2013,
with an increase of 3 rigs per year expected in 2014 and 2015. The 2013
drilling program will continue to focus on delineating acreage and testing the
Wolfcamp A, Upper B, Lower B and D intervals, while the program in 2014 and
beyond will primarily focus on development drilling and accelerating
production growth. Approximately 50% of the wells drilled in this area during
2013 will be from pads, increasing to approximately 75% in 2014. The Company
has included $20 million in the 2013 southern joint interest area drilling
budget for coring, open-hole logging, micro-seismic and 3-D seismic
(“science”). The cost for drilling development wells is targeted at $7.5
million to $8.0 million for a 7,800-foot lateral well. The Company expects to
continue testing laterals as long as 10,000 feet at an additional cost of
approximately $1.5 million. Completion techniques will continue to be
optimized and downspacing opportunities will be evaluated. In particular,
slickwater fracture stimulations will be tested, which could save
approximately $1.0 million per well when compared to gel-conveyed fracture
stimulations.

During the fourth quarter of 2012, Pioneer completed two highly successful
horizontal Jo Mill wells. The two wells had an average 24-hour initial
production rate of 503 BOEPD with short laterals of approximately 2,500 feet.
The peak 30-day rates for these two wells averaged 434 BOEPD, with
approximately 80% oil content, and when normalized to 5,000 feet, the wells
have outperformed the 650 MBOE EUR type curve since being placed on
production.

Pioneer’s extensive Midland Basin geologic analysis, based upon data from
thousands of wells, has identified multiple prospective horizontal targets
with substantial oil in place throughout the Company’s northern
Wolfcamp/Spraberry acreage position of more than 600,000 gross acres. These
horizontal targets include the Jo Mill interval and the Wolfcamp and Spraberry
Shales. Prospectivity is defined by several geologic properties, including
original oil in place, kerogen content, thermal maturity, porosity and brittle
mineral fraction (increased fracability due to reduced clay content). The
depth of the targets is also important as reservoir pressure increases with
depth. Pioneer’s northern Wolfcamp/Spraberry acreage is located in the deepest
part of the Midland Basin, which should make this area very prospective for
horizontal targets.

The Company is currently operating one horizontal rig focused on delineating
its northern acreage position. The rig recently drilled the Company’s first
two horizontal Wolfcamp Shale wells in Midland County. The first well (DL Hutt
C #1H) was completed in the Wolfcamp B interval and had a lateral length of
7,380 feet. It had an initial peak 24-hour production rate of 1,693 BOEPD and
an average peak 20-day rate flowing naturally of 1,510 BOEPD. The oil content
of this well is approximately 75%. The performance of this well is
substantially above the 650 MBOE EUR type curve.

The second well in Midland County is scheduled to be completed in the Wolfcamp
A interval later in February. The rig is now drilling the first of two
horizontal Wolfcamp Shale delineation wells targeting the B interval in Martin
County.

To accelerate the delineation and appraisal of the northern Wolfcamp/Spraberry
acreage, the Company is initiating a $1 billion capital program over the next
two years to confirm the estimated 3.0 BBOE of resource potential that the
Company believes exists in its northern acreage, which has the potential to
add substantial net asset value. The 2013 drilling program, which is expected
to cost $400 million, is scheduled to ramp up to four rigs early in the second
quarter and drill a total of 30 to 40 wells targeting six different “stacked”
intervals. The six “stacked” intervals across the Company’s 600,000
prospective gross acres equates to greater than 3 million prospective gross
acres. Fifteen wells to 20 wells will be completed in the Wolfcamp A, B and D
intervals. Another 15 wells to 20 wells will be completed in the Jo Mill,
Middle Spraberry Shale and the Lower Spraberry Shale. The drilling cost for
these wells is expected to range from $7.5 million per well to $8.5 million
per well assuming 7,000-foot laterals. This cost excludes $80 million of
estimated “science” and infrastructure costs. The 2013 horizontal drilling
program is expected to deliver a year-end exit rate for horizontal production
from the northern acreage ranging from 5 MBOEPD to 7 MBOEPD.

Pioneer expects to increase the rig count on its northern Wolfcamp/Spraberry
acreage to 6 rigs to 8 rigs in 2014 and invest another $600 million to fund
the remainder of the two-year appraisal program. The 2014 program may also
include testing horizontal drilling in deeper intervals below the Wolfcamp
Shale.

Pioneer reduced its vertical drilling program in the Spraberry field from 40
rigs in the first quarter of 2012 to 20 rigs at the end of the year as
horizontal drilling activity increased. The Company drilled 132 vertical wells
in the fourth quarter and 631 wells over the entire year. Over the second half
of 2012, the number of vertical wells awaiting completion increased by 57
wells as the Company shifted its expenditures to more horizontal drilling.

Pioneer continued to successfully drill vertically to deeper intervals in the
Spraberry field below the Wolfcamp interval during 2012 (vertical Wolfcamp
40-acre type curve EUR of 140 MBOE with typical 24-hour initial production
(IP) rate of 90 BOEPD). Production from this deeper drilling has exceeded
expectations and is the primary contributor to the production outperformance
by this asset during 2012. The deeper drilling includes the Strawn, Atoka and
Mississippian intervals. The original 2012 drilling program called for the
Wolfcamp to be the deepest interval completed in approximately 50% of the
wells, with the remaining 50% of the wells to be drilled deeper to intervals
below the Wolfcamp interval. Approximately 65% of the wells drilled in 2012
were actually deepened below the Wolfcamp interval.

Pioneer placed 208 vertical commingled Strawn wells on production during 2012,
with an average 24-hour IP rate of 145 BOEPD. Production data continues to
support an incremental gross EUR per well from the Strawn interval of 30 MBOE.
Pioneer estimates that 85% of its Spraberry acreage position is prospective
for the Strawn interval, up from the previous estimate of 70%.

The Company placed 134 commingled vertical Atoka wells on production during
2012, with an average 24-hour IP rate of 180 BOEPD. Results from well tests
continue to support an incremental gross EUR of 50 MBOE to 70 MBOE for wells
completed in the Atoka interval. Pioneer continues to believe the Atoka
interval is prospective in 40% to 50% of its Spraberry acreage position.

The Company also placed 55 commingled vertical wells on production through the
Mississippian interval during 2012, with an average initial 24-hour IP rate of
140 BOEPD. Data from Mississippian wells drilled to date continues to support
an incremental gross EUR per well of 15 MBOE to 40 MBOE from this interval.
Pioneer continues to believe the Mississippian interval is prospective in 20%
of its Spraberry acreage.

Fourth quarter production from the Spraberry field averaged 69 MBOEPD. This
included production from the Strawn, Atoka and Mississippian intervals in
vertical Spraberry wells and horizontal production from the Wolfcamp Shale and
Jo Mill intervals. Fourth quarter production was negatively impacted by 1,700
BOEPD due to reduced ethane recoveries resulting from Spraberry gas processing
facilities operating above capacity due to greater-than-anticipated industry
production growth.

Spraberry production for 2012 averaged 66 MBOEPD, an increase of 46% compared
to 2011. Horizontal production averaged 2 MBOEPD during 2012 and exited the
year at 5 MBOEPD. For 2013, Spraberry production is forecasted to grow to 75
MBOEPD to 80 MBOEPD, an increase of 14% to 21% compared to 2012. This reflects
the vertical rig count decreasing from an average of 32 rigs in 2012 to 15
rigs in 2013, while the horizontal rig count is expected to increase from an
average of 3 rigs in 2012 to 11 rigs in 2013. This shift to more horizontal
and less vertical drilling is in response to the capital efficiencies that
Pioneer is gaining from drilling more horizontal wells. Pioneer expects
horizontal production to increase from an average of 2 MBOEPD in 2012 to 11
MBOEPD to 14 MBOEPD in 2013. This forecast assumes that more than 4 MBOEPD of
horizontal production on an annualized basis will be conveyed to Sinochem
after the closing of the joint interest transaction which is assumed to occur
on June 1, 2013.

Pioneer’s 2013 production forecast assumes that the inventory of vertical
wells awaiting completion will be drawn down by 60 wells to 70 wells over the
year. It also takes into account that the gas processing capacity shortfall in
the Spraberry area will continue into the second quarter until the new Driver
gas processing plant comes online in April and provides an additional 200
million cubic feet per day of processing capacity, thereby alleviating the
current bottleneck that is impacting ethane recoveries. Pioneer estimates that
the ongoing processing capacity limitations will continue to negatively impact
ethane recoveries and will decrease the Company’s first quarter production by
2 MBOEPD to 3 MBOEPD.

In the liquids-rich Eagle Ford Shale in South Texas, the Company drilled 30
wells in the fourth quarter and placed 37 wells on production. Pioneer
increased its Eagle Ford Shale production from 29 MBOEPD in the third quarter
of 2012 to 35 MBOEPD in the fourth quarter, achieving another record
production level. Strong well performance continues to drive this growth.
Full-year 2012 production averaged 28 MBOEPD. The Company expects 2013
production to range from 38 MBOEPD to 42 MBOEPD, an increase of 36% to 50%
compared to 2012.

Pioneer expects to drill approximately 130 Eagle Ford Shale wells in 2013 at a
cost of $7 million to $8 million per well. Essentially all of these wells will
be liquids-rich wells, with minimal dry gas drilling expected during the year.
Pioneer’s drilling operations in the Eagle Ford Shale continue to become more
efficient. The number of wells drilled from pads, as opposed to single-well
locations, is expected to increase from 45% of the wells drilled in 2012 to
80% of the wells drilled in 2013, reflecting that most of Pioneer’s acreage is
now held by production. Pad drilling saves $600 thousand to $700 thousand per
well and will result in Pioneer being able to drill 130 wells with 10 rigs in
2013 compared to drilling essentially the same number of wells in 2012 with 12
rigs.

Pioneer has been using lower-cost white sand instead of ceramic proppant to
fracture stimulate wells drilled in shallower areas of the field. The Company
is now expanding the use of white sand proppant to deeper areas of the field
to further define its performance limits. The Company tested 97 wells with
white sand proppant in 2011 and 2012, with a savings of approximately $700
thousand per well. Early well performance has been similar to direct offset
ceramic-stimulated wells. Pioneer is continuing to monitor the performance of
these wells and expects that greater than 50% of its 2013 drilling program
will use the lower-cost white sand proppant. The Company also expects to
improve well performance, EURs and well economics by increasing the average
lateral length of its wells from 5,700 feet in 2012 to 6,200 feet in 2013,
which will add approximately $500 thousand to the cost of drilling and
completing a well.

Eleven central gathering plants (CGPs) are now operational as part of the
joint venture’s Eagle Ford Shale midstream business. One additional CGP is
scheduled to be on line by the end of 2013. Pioneer’s share of its Eagle Ford
Shale joint venture midstream activities is conducted through a
partially-owned, unconsolidated entity. Operating cash flow from the midstream
business is expected to be able to fund ongoing midstream infrastructure
build-out costs. Cash flow from the services provided by the midstream
operations is not included in Pioneer’s forecasted operating cash flow.

In the liquids-rich Barnett Shale Combo play, Pioneer drilled 8 wells in the
fourth quarter and placed 8 wells on production. Pioneer is operating one rig
in the play but plans to increase to two rigs in the second quarter to hold
acreage in the highest-return areas of the Company’s 82 thousand net acreage
position. These areas have been identified from drilling data and
petrophysical and seismic analysis. Pioneer currently holds approximately 20%
of its acreage position by production, or 16 thousand net acres, and expects
to hold an additional 45 thousand net acres by production over the next three
years with a two-rig drilling program.

Production in the fourth quarter for the Barnett Shale Combo play was 9
MBOEPD, up from 7 MBOEPD in the third quarter. The Company expects production
to increase from an average of 7 MBOEPD in 2012 to 9 MBOEPD to 12 MBOEPD in
2013. Production is comprised of approximately 60% liquids (oil and natural
gas liquids) and 40% gas.

On the North Slope of Alaska, Pioneer continues to operate one rig and drill
development wells from its island drill site targeting the Nuiqsut and Torok
intervals. The Company’s fourth quarter production was four thousand barrels
oil per day (BOPD). During the first quarter of 2012, the Company completed
its first successful mechanically diverted fracture stimulation of a Nuiqsut
interval well. Based on the success of this mechanically diverted fracture
stimulation, the Company has drilled four more wells and is planning similar
stimulations during the current winter drilling season. Three of these wells
will be in the Nuiqsut interval and one will be in the Torok interval.

During the first quarter of 2012, the Company also drilled a successful
onshore appraisal well to test the southern extent of the Torok interval. The
production and subsurface data provided by this successful well supported the
addition of 50 million barrels of oil to the resource potential of the Torok
interval within Pioneer’s acreage. The well has been flow tested for the
second time and produced at a facility-limited rate of 2,800 BOPD,
significantly higher than the rates achieved in 2012. The well has been shut
in until permanent onshore production facilities are constructed for which an
onshore development FEED study is being progressed. Pioneer is currently
drilling a second onshore Torok well to further appraise this interval.

2013 Capital Budget

Pioneer’s capital program for 2013 of $3.0 billion (excludes acquisitions,
asset retirement obligations, capitalized interest and geological and
geophysical G&A) includes $2.75 billion for drilling, $25 million for vertical
integration, $70 million for the expansion of the Brady, Texas sand mine and
$145 million for Pioneer’s new Midland office building and several new field
buildings.

The following provides a breakdown of the drilling capital by asset:

  * Northern Wolfcamp/Spraberry area - $1,225 million (includes $400 million
    for the horizontal drilling program, $625 million for the vertical
    drilling program and $200 million for infrastructure additions and
    automation projects)
  * Southern Wolfcamp joint interest area - $425 million
  * Eagle Ford Shale - $575 million
  * Barnett Shale Combo - $185 million
  * Alaska - $190 million
  * Other - $150 million, including land capital for existing assets

The 2013 capital budget is expected to be funded from forecasted operating
cash flow of $2.0 billion, assuming commodity prices of $85 per barrel for oil
and $3.25 per thousand cubic feet (MCF) for gas, proceeds of $600 million from
Pioneer’s joint interest transaction with Sinochem (includes reimbursement by
Sinochem of capital expenditures less operating cash flow from the December 1,
2012 effective date to the estimated June 1, 2013 closing date) and $400
million from capital market activities.

Pioneer’s year-end 2012 net debt was $3.5 billion and net debt-to-book
capitalization was 37%. The Company will continue to target a net debt-to-book
capitalization below 35% and net debt-to-operating cash flow below 1.75 times.

Fourth Quarter 2012 Financial Review

The following financial results from continuing operations for the fourth
quarter of 2012 include the Barnett Shale assets that were reclassified to
continuing operations in the fourth quarter after the decision was made to
discontinue efforts to divest of these properties.

Liquids and gas sales averaged 165 MBOEPD, consisting of oil sales averaging
67 thousand barrels per day (MBPD), natural gas liquids (NGL) sales averaging
32 MBPD and gas sales averaging 395 million cubic feet per day.

The average price for oil was $85.60 per barrel including $1.71 per barrel
related to deferred revenue from volumetric production payments (VPPs) for
which production was not recorded. The Company’s remaining VPP expired on its
own terms at the end of 2012. The average reported price for NGLs was $30.69
per barrel and the average reported price for gas was $3.20 per MCF.

Production costs from continuing operations averaged $14.62 per BOE.
Depreciation, depletion and amortization (DD&A) expense averaged $14.54 per
BOE. An impairment charge of $88 million was recorded to reduce the carrying
value of the Barnett Shale proved properties to their estimated fair value as
part of the reclassification of the assets to continuing operations.
Exploration and abandonment costs were $89 million, principally comprised of
$72 million associated with the impairment of unproved Barnett Shale acreage
and $14 million for personnel costs. General and administrative expense
totaled $68 million, including performance-based compensation awards for 2012.
Interest expense was $54 million, and other expense was $27 million.

First Quarter 2013 Financial Outlook

The Company’s first quarter 2013 outlook for certain operating and financial
items is provided below.

Production is forecasted to average 165 MBOEPD to 170 MBOEPD. This forecast
assumes that first quarter production will be negatively impacted by 2,000
BOEPD to 3,000 BOEPD as a result of continuing reduced ethane recoveries
associated with gas processing facilities in the Spraberry field operating
above capacity as described above. New gas processing capacity of 200 million
cubic feet per day is expected to come on line during April and eliminate the
reduced ethane recoveries thereafter. The guidance for the first quarter
excludes the effects of potential ethane rejection to the extent the Company
decides to do so in the future.

Production costs are expected to average $14.00 to $16.00 per BOE. DD&A
expense is expected to average $13.50 to $15.50 per BOE. Total exploration and
abandonment expense is forecasted to be $25 million to $35 million.

General and administrative expense is expected to be $60 million to $65
million, interest expense is expected to be $53 million to $58 million and
other expense is expected to be $25 million to $35 million. Accretion of
discount on asset retirement obligations is expected to be $2 million to $4
million.

Noncontrolling interest in consolidated subsidiaries’ income, excluding
unrealized derivative mark-to-market adjustments, is expected to be $8 million
to $11 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 $2 million to $7 million and
are primarily attributable to state taxes.

The Company's financial and derivative mark-to-market results and open
derivatives positions are outlined on the attached schedules.

Earnings Conference Call

On Thursday, February 14, 2013, at 9:00 a.m. Central Time, Pioneer will
discuss its financial and operating results for the quarter ended December 31,
2012, and its 2013 capital budget, with an accompanying presentation.
Instructions for listening to the call and viewing the accompanying
presentation are shown below.

      Internet:    www.pxd.com
                   “Investors,” then “Earnings & Webcasts” to listen to the
      Select       discussion, view the presentation and see other related
                   material.
                    
                   Dial (877) 718-5108 confirmation code: 7431932 five minutes
      Telephone:   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 March 11, 2013, by dialing (888) 203-1112
confirmation code: 7431932.

Pioneer is a large independent oil and gas exploration and production company,
headquartered in Dallas, Texas, with operations 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, the receipt of approvals required to consummate the Company’s Southern
Wolfcamp joint venture transaction, litigation, the costs and results of
drilling and operations, availability of equipment, services, resources and
personnel required to complete the Company’s operating activities, access to
and availability of transportation, processing, fractionation and refining
facilities, Pioneer's ability to replace reserves, implement its business
plans or complete its development activities as scheduled, access to and cost
of capital, the financial strength of counterparties to Pioneer’s credit
facility and derivative contracts and the purchasers of Pioneer’s oil, NGL and
gas production, uncertainties about estimates of reserves and 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, the risks associated with the ownership and operation of an industrial
sand mining business and acts of war or terrorism. These and other risks are
described in Pioneer's 10-K and 10-Q Reports and other filings with the U.S.
Securities and Exchange Commission (SEC). 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 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.

An audit of proved reserves 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 ("SPE"). A
reserve audit as defined by the SPE is not the same as a financial audit.
Please see the Company's Annual Report on Form 10-K for a general description
of the concepts included in the SPE's definition of a reserve audit.

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

“Drillbit reserve replacement” is the summation of annual proved reserves, on
a BOE basis, attributable to technical revisions of previous estimates,
discoveries and extensions and improved recovery divided by annual production
of oil, NGLs and gas, on a BOE basis.

 
 
PIONEER NATURAL RESOURCES COMPANY
                                                               
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands)
                                                                 
                                               December 31,     December 31,
                                               2012             2011
ASSETS
Current assets:
Cash and cash equivalents                      $ 229,396        $ 537,484
Accounts receivable, net                         320,153          283,813
Income taxes receivable                          7,447            3
Inventories                                      197,056          241,609
Prepaid expenses                                 13,438           14,263
Discontinued operations held for sale            —                73,349
Derivatives                                      279,119          238,835
Other current assets, net                        3,746            12,936      
Total current assets                             1,050,355        1,402,292   
                                                                 
Property, plant and equipment, at cost:
Oil and gas properties, using the successful     14,491,263       12,249,332
efforts method of accounting
Accumulated depletion, depreciation and          (4,412,913 )     (3,648,465 )
amortization
Total property, plant and equipment              10,078,350       8,600,867   
                                                                 
Goodwill                                         298,142          298,142
Other property and equipment, net                1,217,694        573,075
Investment in unconsolidated affiliate           204,129          169,532
Derivatives                                      55,257           243,240
Other assets, net                                165,103          160,008     
                                                                 
                                               $ 13,069,030     $ 11,447,156  
                                                                 
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable                               $ 826,877        $ 716,211
Interest payable                                 68,083           57,240
Income taxes payable                             208              9,788
Current deferred income taxes                    86,481           57,713
Discontinued operations held for sale            —                75,901
Deferred revenue                                 —                42,069
Derivatives                                      13,416           74,415
Other current liabilities                        39,725           36,174      
Total current liabilities                        1,034,790        1,069,511   
                                                                 
Long-term debt                                   3,721,193        2,528,905
Deferred income taxes                            2,140,416        1,942,446
Derivatives                                      12,307           33,561
Other liabilities                                293,016          221,595
Equity                                           5,867,308        5,651,138   
                                                                 
                                               $ 13,069,030     $ 11,447,156  

 
 
PIONEER NATURAL RESOURCES COMPANY
                                                                
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
                                                                  
                    Three Months Ended           Twelve Months Ended
                    December 31,                 December 31,
                    2012          2011           2012            2011
Revenues and
other income:
Oil and gas         $ 734,640     $ 664,776      $ 2,811,660     $ 2,294,063
Interest and          (3,140  )     19,962         28,310          66,880
other
Derivative gains,     86,683        6,634          330,251         392,752
net
Hurricane             —             36             —               1,454
activity, net
Gain (loss) on
disposition of        503           (2,205   )     58,087          (3,644    )
assets, net
                      818,686       689,203        3,228,308       2,751,505  
Costs and
expenses:
Oil and gas           174,095       130,038        635,644         447,142
production
Production and ad     47,687        39,962         187,757         147,664
valorem taxes
Depletion,
depreciation and      220,454       171,921        810,191         578,268
amortization
Impairment of oil
and gas               87,709        354,408        532,589         354,408
properties
Exploration and       88,787        64,078         206,291         121,320
abandonments
General and           67,691        55,347         248,282         193,215
administrative
Accretion of
discount on asset     2,516         2,092          9,887           8,256
retirement
obligations
Interest              53,915        45,878         204,222         181,660
Other                 27,119        16,195         113,388         63,166     
                      769,973       879,919        2,948,251       2,095,099  
                                                                  
Income (loss)
from continuing       48,713        (190,716 )     280,057         656,406
operations before
income taxes
Income tax
benefit               (9,153  )     75,272         (92,384   )     (197,644  )
(provision)
Income (loss)
from continuing       39,560        (115,444 )     187,673         458,762
operations
Income from
discontinued          142           2,256          55,149          423,152    
operations, net
of tax
Net income (loss)     39,702        (113,188 )     242,822         881,914
Net (income) loss
attributable to       (10,868 )     2,042          (50,537   )     (47,425   )
noncontrolling
interests
Net income (loss)
attributable to     $ 28,834      $ (111,146 )   $ 192,285       $ 834,489    
common
stockholders
                                                                  
Basic earnings
per share:
Income (loss)
from continuing
operations          $ 0.23        $ (0.95    )   $ 1.10          $ 3.45
attributable to
common
stockholders
Income from
discontinued
operations            —             0.02           0.44            3.56       
attributable to
common
stockholders
Net income (loss)
attributable to     $ 0.23        $ (0.93    )   $ 1.54          $ 7.01       
common
stockholders
                                                                  
Diluted earnings
per share:
Income (loss)
from continuing
operations          $ 0.22        $ (0.95    )   $ 1.07          $ 3.39
attributable to
common
stockholders
Income from
discontinued
operations            —             0.02           0.43            3.49       
attributable to
common
stockholders
Net income (loss)
attributable to     $ 0.22        $ (0.93    )   $ 1.50          $ 6.88       
common
stockholders
                                                                  
Weighted average
shares
outstanding:
Basic                 123,240       119,223        122,966         116,904    
Diluted               126,945       119,223        126,320         119,215    

 
 
PIONEER NATURAL RESOURCES COMPANY
                                                               
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
                                                                 
                 Three Months Ended            Twelve Months Ended
                 December 31,                  December 31,
                 2012           2011           2012             2011
Cash flows
from operating
activities:
Net income       $ 39,702       $ (113,188 )   $ 242,822        $ 881,914
(loss)
Adjustments to
reconcile net
income (loss)
to net cash
provided by
operating
activities:
Depletion,
depreciation       220,454        171,921        810,191          578,268
and
amortization
Impairment of
oil and gas        87,709         354,408        532,589          354,408
properties
Exploration
expenses,          72,749         41,223         125,376          47,231
including dry
holes
Deferred           9,279          (76,423  )     85,459           188,579
income taxes
(Gain) loss on
disposition of     (503     )     2,205          (58,087    )     3,644
assets, net
Accretion of
discount on
asset              2,516          2,092          9,887            8,256
retirement
obligations
Discontinued       (46      )     9,436          (19,344    )     (376,717   )
operations
Interest           8,751          8,071          35,563           31,483
expense
Derivative
related            (24,485  )     47,847         68,604           (221,899   )
activity
Amortization
of stock-based     15,668         9,917          62,567           41,442
compensation
Amortization
of deferred        (10,575  )     (11,331  )     (42,069    )     (44,951    )
revenue
Other noncash      (18,600  )     3,245          (39,599    )     6,725
items
Change in
operating
assets and
liabilities,
net of effects
from
acquisitions
and
dispositions:
Accounts
receivable,        (20,260  )     (12,079  )     (28,206    )     (47,331    )
net
Income taxes       2,679          818            (5,953     )     29,406
receivable
Inventories        39,406         (21,440  )     33,059           (137,401   )
Prepaid            8,219          4,143          1,447            (3,415     )
expenses
Other current      6,393          (6,563   )     14,291           1,957
assets
Accounts           22,484         52,664         46,038           136,296
payable
Interest           27,144         23,285         10,842           (1,768     )
payable
Income taxes       (14      )     (5,816   )     (9,580     )     (7,623     )
payable
Other current      (8,563   )     15,241         (38,320    )     61,210      
liabilities
Net cash
provided by        480,107        499,676        1,837,577        1,529,714
operating
activities
Net cash used
in investing       (740,321 )     (705,934 )     (3,256,410 )     (1,560,787 )
activities
Net cash
provided by        155,724        533,177        1,110,745        457,397     
financing
activities
Net increase
(decrease) in      (104,490 )     326,919        (308,088   )     426,324
cash and cash
equivalents
Cash and cash
equivalents,       333,886        210,565        537,484          111,160     
beginning of
period
Cash and cash
equivalents,     $ 229,396      $ 537,484      $ 229,396        $ 537,484     
end of period

 
 
PIONEER NATURAL RESOURCES COMPANY
                                                                    
UNAUDITED SUMMARY PRODUCTION AND PRICE DATA
                                                                      
                                 Three Months Ended      Twelve Months Ended
                                 December 31,            December 31,
                                 2012        2011        2012        2011
Average Daily Sales
Volumes from
Continuing
Operations:
Oil (Bbls)            U.S.         67,070      50,231      62,645      40,618
Natural gas liquids   U.S.         31,939      26,163      29,816      22,487
("NGL") (Bbls)
Gas (Mcf)             U.S.         394,817     361,829     378,369     343,879
Total (BOE)           U.S.         164,812     136,699     155,522     120,418
                                                                      
Average Daily Sales
Volumes from
Discontinued
Operations:
Oil (Bbls)            South        —           452         428         530
                      Africa
                      Tunisia      —           —           —           547
                      Total        —           452         428         1,077
                                                                      
Gas (Mcf)             South        —           15,186      10,340      20,570
                      Africa
                      Tunisia      —           —           —           496
                      Total        —           15,186      10,340      21,066
                                                                      
Total (BOE)           South        —           2,983       2,151       3,958
                      Africa
                      Tunisia      —           —           —           630
                      Total        —           2,983       2,151       4,588
                                                                      
Average Reported
Prices (a):
Oil (per Bbl)         U.S.       $ 85.60     $ 95.75     $ 90.89     $ 96.60
NGL (per Bbl)         U.S.       $ 30.69     $ 45.70     $ 33.75     $ 46.27
Gas (per Mcf)         U.S.       $ 3.20      $ 3.37      $ 2.60      $ 3.84
Total (BOE)           U.S.       $ 48.45     $ 52.86     $ 49.40     $ 52.19

_____________

      Average reported prices are attributable to continuing operations and
(a)   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, generally acceptable accounting principles ("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 (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 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 (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 three and twelve months ended December 31, 2012 and 2011:

                                                                  
                         Three Months Ended          Twelve Months Ended
                         December 31,                December 31,
                         2012         2011           2012          2011
                         (in thousands)
                                                                    
Net income (loss)
attributable to common   $ 28,834     $ (111,146 )   $ 192,285     $ 834,489
stockholders
Participating basic        (516   )     (116     )     (3,029  )     (15,178 )
earnings
Basic net income
(loss) attributable to     28,318       (111,262 )     189,256       819,311
common stockholders
Reallocation of            24           —              161           385      
participating earnings
Diluted net income
(loss) attributable to   $ 28,342     $ (111,262 )   $ 189,417     $ 819,696  
common stockholders
                                                                              

The following table is a reconciliation of basic weighted average common
shares outstanding to diluted weighted average common shares outstanding for
the three and twelve months ended December 31, 2012 and 2011:

                                                                     
                                      Three Months Ended   Twelve Months Ended
                                      December 31,         December 31,
                                      2012       2011      2012        2011
                                      (in thousands)
                                                                        
Weighted average common shares
outstanding:
Basic                                 123,240    119,223   122,966     116,904
Dilutive common stock options (a)     143        —         183         190
Contingently issuable performance     196        —         180         424
unit shares
Convertible senior notes dilution     3,366      —         2,991       1,697
Diluted                               126,945    119,223   126,320     119,215

_____________

      Options to purchase 98,819 shares and 129,918 shares of the Company's
      common stock were excluded from the diluted income per share
(a)   calculations for the quarter and year ended December 31, 2012,
      respectively, because they would have been anti-dilutive to the
      calculation.
       
       

                      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 GAAP measures of net income (loss) 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 (loss) or net cash
provided by operating activities, as defined by GAAP.

                                                                
                    Three Months Ended           Twelve Months Ended
                    December 31,                 December 31,
                    2012          2011           2012            2011
                                                                  
Net income (loss)   $ 39,702      $ (113,188 )   $ 242,822       $ 881,914
Depletion,
depreciation and      220,454       171,921        810,191         578,268
amortization
Exploration and       88,787        64,078         206,291         121,320
abandonments
Impairment of oil
and gas               87,709        354,408        532,589         354,408
properties
Hurricane             —             (36      )     —               (1,454    )
activity, net
Accretion of
discount on asset     2,516         2,092          9,887           8,256
retirement
obligations
Interest expense      53,915        45,878         204,222         181,660
Income tax
(benefit)             9,153         (75,272  )     92,384          197,644
provision
(Gain) loss on
disposition of        (503    )     2,205          (58,087   )     3,644
assets, net
Income from
discontinued          (142    )     (2,256   )     (55,149   )     (423,152  )
operations
Derivative            (24,485 )     47,847         68,604          (221,899  )
related activity
Amortization of
stock-based           15,668        9,917          62,567          41,442
compensation
Amortization of       (10,575 )     (11,331  )     (42,069   )     (44,951   )
deferred revenue
Other noncash         (18,600 )     3,245          (39,599   )     6,725      
items
                                                                  
EBITDAX (a)           463,599       499,508        2,034,653       1,683,825
                                                                  
Cash interest         (45,164 )     (37,807  )     (168,659  )     (150,177  )
expense
Current income
tax benefit           126           (1,151   )     (6,925    )     (9,065    )
(provision)
                                                                  
Discretionary         418,561       460,550        1,859,069       1,524,583
cash flow (b)
                                                                  
Cash hurricane        —             36             —               1,454
activity
Discontinued
operations cash       96            11,692         35,805          46,435
activity
Cash exploration      (16,038 )     (22,855  )     (80,915   )     (74,089   )
expense
Changes in
operating assets      77,488        50,253         23,618          31,331     
and liabilities
Net cash provided
by operating        $ 480,107     $ 499,676      $ 1,837,577     $ 1,529,714  
activities

_____________

      “EBITDAX” represents earnings before depletion, depreciation and
      amortization expense; exploration and abandonments; impairment of oil
      and gas properties; net hurricane activity; accretion of discount on
(a)   asset retirement obligations; interest expense; income taxes; net gain
      or loss on the disposition of assets, net; income from discontinued
      operations; noncash derivative related activity; amortization of
      stock-based compensation; amortization of deferred revenue and other
      noncash items.
      Discretionary cash flow equals cash flows from operating activities
(b)   before changes in operating assets and liabilities and cash activity
      reflected in discontinued operations, hurricane activity and exploration
      expense.
       
       

                      PIONEER NATURAL RESOURCES COMPANY

        UNAUDITED SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES (continued)
                    (in thousands, except per share data)

Adjusted income excluding unrealized mark-to-market ("MTM") derivative gains,
and adjusted income excluding 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 and diluted common
shares outstanding (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, 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 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 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 and unusual items will recur in future
periods; however, the amount and frequency can vary significantly from period
to period. The tables below reconcile Pioneer's net income attributable to
common stockholders and diluted shares outstanding for the three months ended
December 31, 2012, as determined in accordance with GAAP, to income adjusted
for unrealized MTM derivative gains and adjusted income excluding unrealized
MTM derivative gains and unusual items for that quarter.

                                                                    
                                                       After-tax     Amounts
                                                       Amounts       Per Share
                                                                      
Net income attributable to common stockholders         $ 28,834      $ 0.22
Unrealized MTM derivative gains                          (13,835 )     (0.11 )
Income adjusted for unrealized MTM derivative gains      14,999        0.11
                                                                      
Income from discontinued operations                      (142    )     —
Impairment of Barnett shale assets previously held       100,511       0.78
for sale
Alaska petroleum production tax credit income            (8,516  )     (0.06 )
Adjusted income excluding unrealized MTM derivative    $ 106,852     $ 0.83   
gains and unusual items
                                                                              
                                                                              

 
 
PIONEER NATURAL RESOURCES COMPANY
 
SUPPLEMENTAL INFORMATION
 
Open Commodity Derivative Positions as of February 8, 2013
(Volumes are average daily amounts)
                                                                    
                                         Twelve Months Ending December 31,
                                         2013          2014          2015
                                                                      
Average Daily Oil Production
Associated with Derivatives (Bbls):
Collar contracts with short puts:
Volume                                     71,029        69,000        26,000
NYMEX price:
Ceiling                                  $ 119.76      $ 114.05      $ 104.45
Floor                                    $ 92.27       $ 93.70       $ 95.00
Short put                                $ 74.28       $ 77.61       $ 80.00
Swap contracts:
Volume                                     3,000         —             —
NYMEX price                              $ 81.02       $ —           $ —
Rollfactor swap contracts:
Volume                                     6,000         15,000        —
NYMEX roll price (a)                     $ 0.43        $ 0.38        $ —
Basis swap contracts:
Midland-Cushing index swap volume          2,055         —             —
Price (b)                                $ (5.75   )   $ —           $ —
Cushing-LLS index swap volume              252           —             —
Price (c)                                $ (7.60   )   $ —           $ —
Average Daily NGL Production
Associated with Derivatives (Bbls):
Collar contracts with short puts:
Volume                                     1,064         1,000         —
Index price
Ceiling                                  $ 105.28      $ 109.50      $ —
Floor                                    $ 89.30       $ 95.00       $ —
Short put                                $ 75.20       $ 80.00       $ —
Average Daily Gas Production
Associated with Derivatives (MMBtu):
Collar contracts with short puts:
Volume                                     —             25,000        225,000
NYMEX price:
Ceiling                                  $ —           $ 4.70        $ 5.09
Floor                                    $ —           $ 4.00        $ 4.00
Short put                                $ —           $ 3.00        $ 3.00
Collar contracts:
Volume                                     150,000       —             —
NYMEX price:
Ceiling                                  $ 6.25        $ —           $ —
Floor                                    $ 5.00        $ —           $ —
Swap contracts:
Volume                                     162,500       105,000       —
NYMEX price (d)                          $ 5.13        $ 4.03        $ —
Basis swap contracts:
Permian Basin index swap volume (e)        52,500        —             —
Price differential ($/MMBtu)             $ (0.23   )   $ —           $ —
Mid-Continent index swap volume (e)        50,000        10,000        —
Price differential ($/MMBtu)             $ (0.30   )   $ (0.19   )   $ —
Gulf Coast index swap volume (e)           60,000        —             —
Price differential ($/MMBtu)             $ (0.14   )   $ —           $ —

_____________

      Represent swaps that fix the difference between (i) each day's price per
      Bbl of West Texas Intermediate oil "WTI" for the first nearby month less
(a)   (ii) the price per Bbl of WTI for the second nearby NYMEX month,
      multiplied by .6667; plus (iii) each day's price per Bbl of WTI for the
      first nearby month less (iv) the price per Bbl of WTI for the third
      nearby NYMEX month, multiplied by .3333.
(b)   Represent swaps that fix the basis differential between Midland WTI and
      Cushing WTI.
(c)   Represent swaps that fix the basis differential between Cushing WTI and
      Louisiana Light Sweet crude "LLS".
(d)   Represents the NYMEX Henry Hub index price on the derivative trade date.
      Represent swaps that fix the basis differentials between the indices
(e)   price at which the Company sells its Permian Basin, Mid-Continent and
      Gulf Coast gas and the NYMEX Henry Hub index price used in gas swap and
      collar contracts.
       
       

Interest rate derivatives. As of February 8, 2013, the Company had interest
rate derivative contracts that lock in a fixed forward annual interest rate of
3.21 percent, for a 10-year period ending in December 2025, on a notional
amount of $250 million. These derivative contracts mature and settle by their
terms during December 2015.

Marketing and basis transfer derivatives. Periodically, the Company enters
into gas buy and sell marketing arrangements to fulfill firm pipeline
transportation commitments. Associated with these gas marketing arrangements,
the Company may enter into gas index swaps to mitigate price risk. The
following table presents Pioneer’s open marketing derivative positions as of
February 8, 2013:

                                                               
                                                2013
                                                First Quarter   Second Quarter
                                                                 
Average Daily Gas Production Associated with
Marketing Derivatives (MMBtu):
Basis swap contracts:
Index swap volume                                    40,000           8,242
Price differential ($/MMBtu)                    $    0.25       $     0.35
                                                                       
                                                                       

Derivative Gains, Net
(in thousands)
                                                          
                                      Three Months Ended   Twelve Months Ended
                                      December 31,         December 31,
Noncash changes in fair value:
Oil derivative gains                  $    23,921          $    217,765
NGL derivative gains (losses)              (3,886    )          1,209
Gas derivative gains (losses)              2,553                (290,058   )
Diesel derivative losses                   —                    (270       )
Marketing derivative gains (losses)        88                   (22        )
Interest rate derivative gains             1,809                5,930       
Total noncash derivative gains             24,485               (65,446    )
(losses), net (a)
                                                            
Cash settled changes in fair value:
Oil derivative gains                       13,462               4,139
NGL derivative gains                       2,311                13,403
Gas derivative gains (b)                   46,578               402,981
Diesel derivative gains (b)                —                    3,497
Marketing derivative gains (losses)        (153      )          36
Interest rate derivative losses (b)        —                    (28,359    )
Total cash derivative gains, net           62,198               395,697     
Total derivative gains, net           $    86,683          $    330,251     

_____________

      Total noncash derivative gains (losses), net includes $2.5 million and
(a)   $16.2 million of net gains attributable to noncontrolling interests in
      consolidated subsidiaries during the three and twelve months ended
      December 31, 2012, respectively.
      During the twelve months ended December 31, 2012, the Company terminated
      (i) swap, collar, three-way and basis swap derivative contracts for 2014
      and 2015 gas production, (ii) swap derivative contracts for 2013 diesel
(b)   fuel and (iii) $200 million notional amount of interest rate derivative
      contracts. As a result of these transactions, the Company realized
      $116.4 million of net proceeds during the twelve months ended December
      31, 2012.

Contact:

Pioneer Natural Resources
Investors
Frank Hopkins, 972-969-4065
or
Eric Pregler, 972-969-5756
or
Josh Jones, 972-969-5822
or
Media and Public Affairs
Susan Spratlen, 972-969-4018
or
Suzanne Hicks, 972-969-4020
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