?            recognizing net derivative losses of $124.0 million for the three
             months ended September 30, 2012, as compared to net derivative gains
             of $401.1 million for the three months ended September 30, 2011;


?            a $65.9 million increase in DD&A expense, primarily due to increased
             sales volumes;


?            a $64.1 million increase in oil and gas production costs, primarily
             due to increases in variable lease operating expenses and
             third-party transportation fees due to higher sales volumes;
             partially offset by


?            a $174.3 million decline in income tax provisions attributable to
             continuing operations; and


?            a $121.3 million increase in oil and gas revenues as a result of an
             increase in sales volumes, partially offset by lower average
             commodity prices.


•      During the third quarter of 2012, average daily sales volumes increased by
       28 percent to 153,016 BOEPD, as compared to 119,597 BOEPD during the third
       quarter of 2011. The increase in third quarter 2012 average daily sales
       volumes, as compared to the third quarter of 2011, was primarily due to
       the Company's successful drilling program during the last three months of
       2011 and the first nine months of 2012;


•      Average reported oil, NGL and gas prices decreased during the third
       quarter of 2012 to $89.87 per BBL, $31.28 per BBL and $2.62 per MCF,
       respectively, as compared to $92.11 per BBL, $48.33 per BBL and $4.05 per
       MCF, respectively, in the third quarter of 2011;


•      Average oil and gas production costs per BOE increased to $12.55 for the
       third quarter of 2012, as compared to $10.23 for the third quarter of
       2011, primarily due to increases in lease operating expenses, third party
       transportation charges and net natural gas plant charges. The increase in
       lease operating expenses is primarily due to increases in salt water
       disposal costs (principally comprised of water hauling fees) and higher
       repair and maintenance activity during the third quarter of 2012. The
       increase in third-party transportation costs is primarily due to
       gathering, treating and transportation costs associated with increasing
       sales volumes in the Eagle Ford Shale field. Net natural gas plant charges
       increased primarily due to a reduction in third-party gas volumes in
       Company-owned facilities as a result of lower gas and NGL prices being
       realized on the volumes retained as processing fees. See "Results of
       Operations," below for more information about changes in production costs;


•      Net cash provided by operating activities decreased to $432.1 million for
       the three months ended September 30, 2012, as compared to $465.6 million
       for the three months ended September 30, 2011. The $33.5 million decrease
       in net cash provided by operating activities is primarily due to working
       capital changes during the third quarter of 2012;


•      In August 2012, the Company completed the sale of Pioneer South Africa for
       net cash proceeds of $15.9 million, including normal closing adjustments.
       The Company recorded a pretax gain of $28.6 million on the sale of Pioneer
       South Africa in income (loss) from discontinued operations for the three
       and nine months ended September 30, 2012;


•      In early August 2012, the Company announced plans to pursue a joint
       venture partner to accelerate the development of the horizontal Wolfcamp
       Shale play in the southern 200,000 acres of the Company's total
       prospective position. See "Operations and Drilling Highlights" for more
       information about the Company's Wolfcamp Shale play;


•      In early September 2012, the Company announced plans to divest of its
       properties in the Barnett Shale field. The Company has opened a data room
       and is targeting completing the transaction during the first quarter of
       2013. Accordingly, the Company has classified its (i) Barnett Shale assets
       and liabilities as discontinued operations held for sale in the
       accompanying consolidated balance sheet as of September 30, 2012 and (ii)
       Barnett Shale results of operations as income from discontinued
       operations, net of tax in the accompanying consolidated statements of
       operations (representing a recasting of the Barnett Shale field results of
       operations for the three and nine months ended September 30, 2011 and the
       six months ended June 30, 2012, which were originally classified as
       continuing operations). See Note C of Notes to Consolidated Financial
       Statements included in "Item 1. Financial Statements" for more information
       about discontinued operations;

• As of September 30, 2012, the Company's net debt to book capitalization was 36 percent, as compared to 26 percent as

of December 31, 2011. The Company was upgraded to investment grade by one of its debt rating agencies during the fourth quarter of 2011 and by another rating agency during the second quarter of 2012.

Fourth Quarter 2012 Outlook
Based on current estimates, the Company expects the following operations and financial results from continuing operations for the quarter ending December 31, 2012:
Production is forecasted to average 154,000 to 158,000 BOEPD. This assumes the remaining NGL inventory at Mont Belvieu, Texas of 90,000 barrels will be drawn down during the fourth quarter, but will be offset by line fill requirements in the fourth quarter for the new Lone Star NGL pipeline in which the Company will be a shipper. The fourth quarter production estimate also assumes a negative impact ranging from 1,000 BOEPD to 2,000 BOEPD due to reduced ethane recoveries associated with gas processing facilities in the Spraberry field nearing capacity. See "Results of Operations" for more information about NGL inventories, the Lone Star NGL pipeline fill and related Spraberry gas processing limitations.
Production costs (including production and ad valorem taxes and transportation costs) are expected to average $14.50 to $16.50 per BOE based on continuing higher salt water disposal and electricity costs, higher per-BOE costs resulting from the gas processing capacity limitations negatively impacting sales volumes and current NYMEX strip commodity prices. DD&A expense is expected to average $13.50 to $15.50 per BOE.
Total exploration and abandonment expense is expected to be $25 million to $35 million. General and administrative expense is expected to be $60 million to $65 million. Interest expense is expected to be $53 million to $58 million, and other expense is expected to be $25 million to $35 million. Accretion of discount on asset retirement obligations is expected to be $2 million to $4 million.
Noncontrolling interest in consolidated subsidiaries' net income, excluding noncash mark-to-market adjustments, is expected to be $8 million to $11 million, primarily reflecting the public ownership in Pioneer Southwest. The Company's effective income tax rate, excluding the effect of net income attributable to noncontrolling interest, is expected to range from 35 percent to 40 percent assuming current capital spending plans and no significant mark-to-market changes in the Company's derivative position. Cash income taxes are expected to range from $2 million to $7 million, primarily attributable to state taxes.
Operations and Drilling Highlights
The following table summarizes the Company's average daily oil, NGL, gas and total production from continuing operations by asset area during the nine months ended September 30, 2012:

                                           Oil (BBLs)     NGLs (BBLs)     Gas (MCF)     Total (BOE)
Permian Basin                                 43,186          12,926        59,855          66,088
South Texas - Eagle Ford Shale                 9,267           6,616        57,132          25,405
Raton Basin                                        -               -       151,648          25,275
Mid-Continent                                  3,213           6,979        47,802          18,159
South Texas - Edwards and Austin Chalk            78               1        37,921           6,399
Alaska                                         4,325               -             -           4,325
Other                                              1               4           110              23
                                              60,070          26,526       354,468         145,674

During 2012 and 2011, the Company has focused its capital budgets and expenditures on oil- and liquids-rich-gas drilling activities as a result of the decline in gas prices. As a result of these capital activities and commodity price changes, the Company's total liquids production and revenue from continuing operations has increased to 59 percent and 88 percent, respectively, for the nine months ended September 30, 2012 from 51 percent and 77 percent, respectively, for the same period last year.

                       PIONEER NATURAL RESOURCES COMPANY

 The following table summarizes by geographic area the Company's finding and
development costs incurred during the nine months ended September 30, 2012:
                                                                                                Asset
                                 Acquisition Costs         Exploration      Development       Retirement
                               Proved       Unproved          Costs            Costs         Obligations         Total
                                                                    (in thousands)
Permian Basin                $   3,099     $  56,157     $     280,853     $  1,273,779     $      2,375     $ 1,616,263
South Texas - Eagle Ford
Shale                                -         9,740           131,179            4,973               62         145,954
Raton Basin                          -             -             6,397            6,469                -          12,866
Mid-Continent                        -         4,153             3,524           14,712                -          22,389
South Texas - Edwards and
Austin Chalk                         -           130             3,525            5,845                -           9,500
Barnett Shale                    8,673         7,732           171,476           47,528              337         235,746
Alaska                               -             -            62,522           88,641            2,532         153,695
Other                               47        39,967             1,777                9                -          41,800
                             $  11,819     $ 117,879     $     661,253     $  1,441,956     $      5,306     $ 2,238,213

The following table summarizes the Company's development and exploration/extension drilling activities for the nine months ended September 30, 2012:

                                                    Development Drilling
                          Beginning
                            Wells           Wells       Successful     Unsuccessful     Ending Wells
                         in Progress        Spud          Wells           Wells         in Progress
Permian Basin                    161           500            547                8              106
Raton Basin                        5             -              4                1                -
Barnett Shale                      -             4              4                -                -
Alaska                             1             3              2                -                2
Total United States              167           507            557                9              108



                                                      Exploration/Extension Drilling
                              Beginning Wells             Wells       Successful     Unsuccessful     Ending Wells
                                in Progress               Spud          Wells           Wells         in Progress
Permian Basin                      -                          31             16                -               15
South Texas - Eagle
Ford Shale                        39                          99            102                -               36
Mid-Continent                      5                           -              -                5                -
Barnett Shale                     26                          27             39                -               14
Alaska                             1                           2              -                1                2
Total United States               71                         159            157                6               67

Permian Basin area. The Company currently has 30 rigs operating in the Spraberry field, of which 25 are drilling vertical wells and five are drilling Wolfcamp Shale horizontal wells. During 2012, the Company expects to drill approximately 625 vertical wells and 30 to 35 horizontal Wolfcamp Shale wells.
In the horizontal Wolfcamp Shale play, the Company believes it has significant resource potential within its acreage based on its extensive geologic data covering the Wolfcamp A, B, C and D intervals and its drilling results to-date. The Company's horizontal drilling activity for the remainder of 2012 and 2013 will be primarily focused on the 200,000 acres in the southern part of the play where the Company expects to drill approximately 90 horizontal wells by the end of 2013 to hold approximately 50,000 expiring acres. The Company plans to continue drilling in the B interval and the A interval in this area. The Company's first two successful horizontal Wolfcamp Shale wells were drilled in northern Upton County in the Upper B interval in the Giddings Estate area. The first well had its one-year anniversary from the date of first production in mid-October and has produced 135 MBOE to date. The second well has been on production for ten months and has delivered cumulative production of 105 MBOE.

During the third quarter of 2012, the Company initiated plans to delineate the northern part of its Spraberry acreage position by drilling in Midland, Martin and Gaines Counties. Wells drilled in this area are expected to benefit from greater original oil in place and higher reservoir pressures associated with deeper drilling depths. Pioneer believes a successful drilling program in this area could substantially increase its prospective horizontal Wolfcamp Shale acreage position.

During the third quarter of 2012, the Company opened a data room and initiated plans to pursue a joint venture partner to accelerate the development of the horizontal Wolfcamp Shale in the southern 200,000 acres of the Company's total prospective acreage position. The Company is offering 33 percent to 50 percent of its working interest in the southern acreage. No assurance can be provided that the Company will be successful in attracting a joint venture partner or that a joint venture partner will offer an acquisition price that is acceptable to the Company.

The Company continues to drill vertically to deeper intervals in the Spraberry field below the Wolfcamp interval. This deeper drilling includes the Strawn, Atoka and Mississippian intervals. Production from these deeper intervals has contributed to the Company's production growth during 2012. The original 2012 drilling program planned for the Wolfcamp to be the deepest interval completed in approximately 50 percent of the wells. The remaining 50 percent of the wells were to be deepened below the Wolfcamp interval. The current drilling program reflects 65 percent of the wells being deepened below the Wolfcamp interval. Based on results to-date, the Company estimates that 70 percent of its Spraberry acreage position is prospective for the Strawn interval, 40 percent to 50 percent of its acreage position is prospective for the Atoka interval and that the Mississippian interval is prospective in 20 percent of the Company's Spraberry acreage.

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

The Company has expanded its integrated services to control drilling costs and support the execution of its accelerating drilling program. The Company has 15 Company-owned drilling rigs, five Company-owned vertical fracture stimulation fleets and two Company-owned horizontal fracture stimulation fleets currently operating in the Spraberry field. To support its growing operations, the Company also owns other field service equipment, including pulling units, fracture stimulation tanks, water transport trucks, hot oilers, blowout preventers, construction equipment and fishing tools. In addition, in early April 2012, the Company completed the acquisition of Premier Silica, which is expected to supply the Company's growing brown sand requirements for fracture stimulating wells in the vertical Spraberry and horizontal Wolfcamp Shale plays.
Eagle Ford Shale area. The Company's drilling activities in the South Texas area during 2012 continue to be primarily focused on delineation and development of Pioneer's substantial acreage position in the Eagle Ford Shale play. The 2012 drilling program has been focused on liquids-rich drilling, with only 10 percent of the wells designated to hold strategic dry gas acreage.
The Company completed 102 horizontal Eagle Ford Shale wells during the first nine months of 2012, all of which were successful, with average lateral lengths of approximately 5,500 feet and, on average, 13-stage fracture stimulations. The Company is currently running 11 drilling rigs and three fracture stimulation fleets, two of which are Pioneer-owned fleets, in the play.
The Company has also been testing the use of lower-cost white sand instead of ceramic proppant to fracture stimulate wells drilled in shallower areas of the field. The Company is expanding the use of white sand proppant to deeper areas of the field to further define its performance limits. Early well performance has been similar to direct offset ceramic-stimulated wells. The Company is continuing to monitor the performance of these wells and expects that 50 percent of its 2012 drilling program will have used lower-cost white sand proppant. During 2013, the Company expects that greater than 50 percent of the wells drilled will use white sand proppant.
The unconsolidated affiliate formed by the Company to operate gathering facilities in the Eagle Ford Shale area, EFS Midstream, is obligated to construct midstream assets in the Eagle Ford Shale area. Eleven of the 13 planned central gathering plants ("CGPs") were completed as of September 30, 2012. EFS Midstream is providing gathering, treating and transportation services for the Company during a 20-year contractual term. During 2011, EFS Midstream entered into a $300 million, five-year revolving credit facility that is being used to fund infrastructure investments that exceed its operating cash flows. Alaska. The Company owns a 70 percent working interest in, and is the operator of, the Oooguruk development project. Since inception, the Company has drilled 16 production wells and 10 injection wells to develop this project. During the first quarter of 2012, the Company drilled an exploration well which was drilled from an onshore location to further evaluate the productivity of the Torok formation and the feasibility of future development expansion. The Company flow tested the well during April 2012 until production could no longer be transported along the ice road being utilized. The well had a gross initial production rate of approximately 2,000 barrels of oil per day. The well is now shut in awaiting permanent onshore production facilities, for which an onshore development front-end engineering design (FEED) study has been initiated. In September 2012, the Company entered into a contract for a drilling rig that is now committed to drill a second well in this formation during the upcoming winter to further appraise this interval.
During the first quarter of 2012, the Company also completed its first successful mechanically diverted fracture stimulation

of a Nuiqsut interval well from the Oooguruk development facilities. Gross initial production from the test was at a rate of 4,000 barrels of oil per day. Based on the success of this fracture stimulation, the Company plans to fracture stimulate four new wells this winter using a similar completion design. Results of Operations from Continuing Operations Oil and gas revenues. Oil and gas revenues totaled $695.4 million and $2.0 billion for the three and nine months ended September 30, 2012, respectively, as compared to $574.1 million and $1.6 billion for the same respective periods in 2011.

The increase in oil and gas revenues during the three months ended September 30, 2012, as compared to the same period in 2011, is reflective of 52 percent, 40 percent and six percent increases in daily oil, NGL and gas sales volumes, respectively. Partially offsetting the effects of these production increases in the quarter-to-quarter comparison were declines of two percent, 35 percent and 35 percent in reported oil, NGL and gas prices, respectively. The increase in oil and gas revenues during the nine months ended September 30, 2012, as compared to the same period in 2011, is reflective of 63 percent, 32 percent and eight percent increases in daily oil, NGL and gas sales volumes, respectively. Partially offsetting the effects of these production increases in the nine month comparisons were declines of four percent, 25 percent and 41 percent in reported oil, NGL and gas prices, respectively.
The following table provides average daily sales volumes for the three and nine months ended September 30, 2012 and 2011:

                 Three Months Ended        Nine Months Ended
                   September 30,             September 30,
                  2012          2011        2012         2011
Oil (BBLs)       63,125        41,463      60,070       36,943
NGLs (BBLs)      30,352        21,748      26,526       20,132
Gas (MCF)       357,232       338,321     354,468      328,464
Total (BOE)     153,016       119,597     145,674      111,819

Average daily BOE sales volumes increased by 28 percent and 30 percent for the three and nine months ended September 30, 2012, as compared to the same respective periods in 2011, principally due to the Company's successful drilling program and the sale of NGLs that were placed in storage during the second quarter of 2012. Specifically, portions of the Company's gas production include NGLs that are separated at the Midkiff/Benedum and Sale Ranch gas processing facilities in West Texas. These NGLs are then transported to third-party fractionation facilities at Mont Belvieu. During May, a significant third-party facility was shut down for planned maintenance. When the facility came back on line in late May, it had operating problems and was not able to achieve its pre-shutdown fractionation capacity. As a result of these problems and the fractionation capacity limitations across the Mont Belvieu complex, the Company built an NGL inventory of 256 thousand barrels that could not be processed for sale in June, thereby reducing production for the second quarter by 2,800 BOEPD. During the third quarter of 2012, the Company was periodically able to utilize some available fractionation capacity across the Mont Belvieu complex to reduce its inventory levels. In addition, during September of 2012, the fractionation facility was able to partially increase its processing rates, thereby allowing the Company to begin selling a portion of its NGL inventory. Sales volumes for the third quarter of 2012 included 1,805 BOEPD of NGL inventory fractionated and sold, leaving approximately 90,000 barrels in NGL inventory that could not be processed as of September 30, 2012. The remaining NGL inventory is expected to be fractionated and sold during the three months ended December 31, 2012. In addition to the NGL inventory changes discussed above, production growth for the three and nine months ended September 30, 2012, as compared to the same periods in 2011, was negatively impacted by approximately 4,000 BOEPD and 2,000 BOEPD, respectively, due to the Midkiff/Benedum gas processing plants being forced to reject ethane into the residue gas stream during the second and third quarters of 2012 as a result of the NGL fractionation capacity limitations at Mont Belvieu. In early October 2012, the fractionation facility resolved its operating problems and restored its processing rates to its pre-shutdown processing capacity. However, the Company's fourth quarter production will be negatively impacted by volumes that will not be sold but used to fill a new NGL sales line. The impact of using fourth quarter volumes for line fill is expected to be 1,000 BOEPD to 1,200 BOEPD. Fourth quarter 2012 production is also expected to be negatively impacted by gas processing capacity limitations in the Spraberry field as a result of wet gas production for the Company and other industry participants growing faster than anticipated. For the fourth quarter, production is expected to be 1,000 BOEPD to 2,000 BOEPD lower as a result of the gas processing capacity limitations, leading to reduced recoveries of ethane. New gas processing facilities are being built and are expected to be on production in late March or early April of 2013.
The oil, NGL and gas prices that the Company reports are based on the market prices received for the commodities adjusted for transfers of the Company's deferred hedge gains and losses from AOCI-Hedging and the amortization of deferred VPP revenue. See "Derivative activities" and "Deferred revenue" discussion below for additional information regarding the Company's past cash

                       PIONEER NATURAL RESOURCES COMPANY

flow hedging activities and the amortization of deferred VPP revenue.
The following table provides the Company's average reported prices (including
transfers of deferred hedge gains and losses and the amortization of deferred
VPP revenue) and average realized prices (excluding transfers of deferred hedge
gains and losses and the amortization of deferred VPP revenue) for the three and
nine months ended September 30, 2012 and 2011:
                               Three Months Ended            Nine Months Ended
. . .