Financial and Operating Performance

The Company's financial and operating performance for the third quarter of 2009 included the following highlights:

• Earnings attributable to common stockholders was a net loss of $7.2 million ($.06 per diluted share), as compared to net loss attributable to common stockholders of $5.2 million ($.04 per diluted share) for the third quarter of 2008. The decrease in earnings attributable to common stockholders is primarily due to:

• A decline in oil and gas revenues due to NGL and gas price declines, partially offset by increases in oil price and sales volumes,

• $13.4 million of third quarter 2009 net unrealized derivative losses recorded under the mark-to-market accounting method and

• Negative price revisions to proved reserves associated with the commodity price declines, which increased depreciation, depletion and amortization expense, partially offset by

• Oil and gas production cost declines resulting from the Company's cost reduction initiatives,

• Production and ad valorem tax declines, primarily due to commodity price declines and

• A decline in impairment of oil and gas properties, associated with impairment of the Company's Uinta/Piceance assets during the third quarter of 2008.

• Daily sales volumes from continuing operations increased on a per-BOE basis by two percent to 112,623 BOEPD during the third quarter of 2009, as compared to 110,538 BOEPD during the third quarter of 2008. The increase in third quarter 2009 sales volumes, as compared to the third quarter of 2008, was primarily due to September 2008 production curtailments as a result of damage caused by Hurricanes Gustav and Ike to third-party NGL fractionation facilities.

• Average reported oil, NGL and gas prices from continuing operations decreased during the third quarter of 2009 to $78.20 per Bbl, $33.13 per Bbl and $3.64 per Mcf, respectively, as compared to respective prices of $80.37 per Bbl, $62.23 per Bbl and $7.98 per Mcf during the third quarter of 2008.

• Average oil and gas production costs and total ad valorem and production taxes per BOE from continuing operations decreased during the third quarter of 2009 to $8.72 and $2.71, respectively, as compared to respective costs of $10.55 and $4.53 per BOE during the third quarter of 2008, primarily as a result of cost reduction initiatives and commodity price declines.

Commodity prices. During the second half of 2008, the United States and other industrialized countries experienced a significant economic slowdown, which led to a substantial decline in worldwide energy demand. During this same time period, North American gas supply was increasing as a result of the rise in domestic unconventional gas production. The combination of lower energy demand due to the economic slowdown and higher North American gas supply resulted in significant declines in oil, NGL and gas prices during the second half of 2008 and continued into early 2009. Beginning in the second quarter of 2009, oil and NGL prices have generally been increasing, while gas prices have remained volatile. Although the Company has entered into derivative contracts on a large portion of its production volumes through 2011, a sustained lower commodity price environment would result in lower realized prices for unprotected volumes and reduce the prices at which the Company could enter into derivative contracts on additional volumes in the future. As a result, the Company's internal cash flows would be reduced for affected periods. The timing and magnitude of commodity price declines or recoveries cannot be predicted. A sustained decline in commodity prices could result in a shortfall in expected cash flows, which could negatively impact the Company's liquidity, financial position and future results of operations. See "Item 3. Quantitative and Qualitative Disclosures About Market Risk" and Note G of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information about the Company's derivative contracts.

Cost reduction initiatives. During the fourth quarter of 2008, the Company implemented initiatives to reduce capital spending, operating costs and administrative expenses to support its goal of delivering net cash flow from operating activities in excess of capital requirements in 2009 and to enhance and preserve financial flexibility. These initiatives include minimizing drilling activities until margins improve as a result of (i) commodity prices increasing and/or (ii) well cost reductions. As a result, the Company significantly reduced its 2009 rig activity and has realized and continues to pursue reductions in operating expenses and well costs to align costs with a lower commodity price environment. Rigs have been terminated or stacked in the Spraberry, Raton, Edwards Trend and

Barnett Shale areas and in Tunisia. Since the third quarter of 2008, when drilling and completion costs peaked, the Company has achieved an average reduction of approximately 30 percent in the cost of drilling and completing a well in the Spraberry field of West Texas. The Company's asset teams have also implemented initiatives that have reduced 2009 lease operating expense per BOE from continuing operations by 22 percent during the third quarter of 2009, as compared to the third quarter of 2008. The cost savings reflect reductions in electricity, water disposal and compression rental costs and an expansion of the Company's use of internal well services.

As a result of the successes realized from the aforementioned cost reduction initiatives and increases in 2009 oil prices, the Company is implementing a plan to resume oil- and liquids-rich-gas-focused drilling activities during 2010 and has preliminarily targeted its 2010 capital budget to be in a range of $800 million to $900 million (excluding acquisitions, effects of asset retirement obligations, capitalized interest and geological and geophysical administrative costs). The Company's 2009 annual capital costs (excluding acquisitions, effects of asset retirement obligations, capitalized interest and geological and geophysical administrative costs) are expected to total approximately $300 million. During the first nine months of 2009, the Company's capital costs (excluding acquisitions, effects of asset retirement obligations, capitalized interest and geological and geophysical administrative costs) were $224 million, as compared to $947 million during the first nine months of 2008, representing a 76 percent decrease.

Fourth Quarter 2009 Outlook

Based on current estimates, the Company expects that fourth quarter 2009 production will average 105,000 to 110,000 BOEPD, reflecting reduced 2009 drilling activity, downtime associated with a gas plant maintenance shutdown in South Africa and gas pipeline repairs and variability in the timing of oil cargo shipments in Tunisia.

Fourth quarter production costs (including production and ad valorem taxes and transportation costs) are expected to average $11.50 to $13.50 per BOE, based on NYMEX strip prices for oil, NGLs and gas. Production costs are expected to be impacted by higher production, lower production volumes and increased workover activity. Depletion, depreciation and amortization ("DD&A") expense is expected to average $15.50 to $17.00 per BOE based on the new SEC reserve pricing methodology that is expected to be implemented during the fourth quarter of 2009.

Total exploration and abandonment expense for the quarter is expected to be $20 million to $30 million, primarily related to exploration wells, including related acreage costs, and seismic and personnel costs. General and administrative expense is expected to be $35 million to $39 million. Interest expense is expected to be $42 million to $45 million. Accretion of discount on asset retirement obligations is expected to be $2 million to $4 million.

Noncontrolling interest in consolidated subsidiaries' net income is expected to be $8 million to $10 million, primarily reflecting the public ownership in Pioneer Southwest.

The Company also expects to recognize $5 million to $10 million of charges in other expense associated with certain drilling rigs being stacked as a result of the low commodity price environment.

The Company's fourth quarter effective income tax rate is expected to range from 40 percent to 50 percent, assuming current capital spending plans, higher tax rates in certain foreign jurisdictions and no significant mark-to-market changes in the Company's derivative position. Cash income taxes are expected to range from $10 million to $15 million, principally related to Tunisian income taxes.

Fourth quarter 2009 amortization of deferred hedge gains on discontinued and terminated oil and gas hedges is expected to be $25 million.

Operations and Drilling Highlights

The Company intends to limit 2009 capital expenditures, excluding acquisitions, effects of asset retirement obligations, capitalized interest and geological and geophysical administrative costs, to internally-generated operating cash flow. During the nine month period ended September 30, 2009, cash flow from operating activities was $410.8 million and the Company's capital expenditures, excluding acquisitions, effects of asset retirement obligations, capitalized interest and geological and geophysical administrative costs, were $224.2 million.

                       PIONEER NATURAL RESOURCES COMPANY



The following table summarizes by geographic area the Company's finding and
development costs incurred during the nine month period ended September 30,
2009:



                                                                                                     Asset
                                    Acquisition Costs          Exploration     Development        Retirement
                                    Proved     Unproved           Costs           Costs           Obligations      Total
                                                                       (in thousands)

United States:
Permian Basin                     $    3,586   $   5,971      $       6,686   $      72,971      $           1   $  89,215
Mid-Continent                             -           -                 352           2,852                 -        3,204
Rocky Mountains                           58       1,038             10,854          19,220                 -       31,170
Barnett Shale                            367       1,368             12,048             446                 -       14,229
Gulf of Mexico                            -           -                 304             (36 )               -          268
Onshore Gulf Coast                     4,224      33,685             24,105             856                328      63,198
Alaska                                    -         (347 )            2,876          79,072                 38      81,639

                                       8,235      41,715             57,225         175,381                367     282,923

South Africa                              65          -                 403             910                 -        1,378
Tunisia                                   -           -              16,521          10,291                 -       26,812
Other                                     -           -                 724              -                  -          724

                                          65          -              17,648          11,201                 -       28,914

Total Worldwide                   $    8,300   $  41,715      $      74,873   $     186,582      $         367   $ 311,837

The following table summarizes the Company's development and exploration/extension drilling activities for the nine months ended September 30, 2009:

                                            Development Drilling
                     Beginning Wells   Wells   Successful   Unsuccessful   Ending Wells
                       in Progress     Spud      Wells         Wells       in Progress
   United States                   7      22           27             -               2
   Tunisia                        -        1           -              -               1

   Total Worldwide                 7      23           27             -               3

                                       Exploration/Extension Drilling
                     Beginning Wells   Wells   Successful   Unsuccessful   Ending Wells
                       in Progress     Spud      Wells         Wells       in Progress
   United States                  10       9            8              2              9
   Tunisia                         5       1           -               3              3

   Total Worldwide                15      10            8              5             12

Permian Basin area. In the Spraberry field, production averaged 31,827 BOEPD and 34,520 BOEPD during the three and nine months ended September 30, 2009, respectively, representing associated increases of six percent and thirteen percent, as compared to the same periods of 2008. As a result of the Company's reduced 2009 capital budget, the Company only completed four additional wells in the Spraberry field during the three months ended September 30, 2009. During the nine months ended September 30, 2009, the Company completed 21 Spraberry field wells. The Company expects to drill a total of 44 to 48 wells during 2009 in the Spraberry field. The Company resumed drilling in the Spraberry field in August and has three rigs operating in the area. The Company has plans to add 11 additional rigs by year end, increasing to 19 rigs by mid-2010 and 24 rigs by the end of 2010.

The Company plans to drill approximately 425 Spraberry wells during 2010. The majority of the Spraberry wells will be drilled deeper to add the Wolfcamp formation, which provides incremental production and proved reserve potential. Substantial declines in well costs, new oil price derivatives and forward market prices for oil exceeding $70 per Bbl are supportive of the Company's plan to increase drilling activities during the fourth quarter of 2009 through 2010.

During 2008, the Company initiated a program to test 20-acre well down spacing performance as part of its announced recovery improvement initiatives, which also include secondary recovery waterflood projects, shale/silt interval testing and horizontal well initiative opportunities in the Spraberry field. The Company continues to monitor the 20-acre pilot wells and their offsets with available data. The Company drilled a total of twenty 20-acre wells prior to 2009. With all 20 wells on production, the results are encouraging and will continue to be monitored before determining future plans for 20-acre drilling.

The Company also plans to implement a 7,000-acre waterflood project in the Spraberry field during 2010.

The 20-acre well spacing, waterflood project and other initiatives described above are being performed to enhance hydrocarbon recovery, as a percentage of oil in place, in those areas of the Spraberry field that are expected to be conducive for these undertakings. However, the ultimate incremental recovery rates associated with these initiatives cannot be predicted at this time.

Mid-Continent area. In the Hugoton and West Panhandle fields, 2009 daily production averaged 17,683 BOEPD and 18,215 BOEPD during the three and nine months ended September 30, 2009, respectively, representing respective decreases of six percent and seven percent, as compared to the same periods of 2008. Third quarter 2009 production was negatively impacted by unplanned third-party pipeline repairs. The Company continues to achieve production benefits in both the Hugoton and West Panhandle fields through gathering system efficiencies and improved system surveillance.

In the Hugoton field, the Company has completed its testing of both re-completed and new drill wells that are commingled in the Chase and Council Grove formations. Future development plans will incorporate further expansion of this activity in the field. In the West Panhandle field, the Company is not planning any 2009 development drilling in support of the Company's cost reduction initiatives. The Company is planning to maximize operating results in the field through well recompletions, fracture stimulations and continued replication of its successful lateral well cleanout program.

Rocky Mountain area. The Company's Raton Basin production volumes averaged 31,525 BOEPD and 31,426 BOEPD during the three and nine months ended September 30, 2009, respectively, representing respective declines of six percent and four percent, as compared to the same periods of 2008. The Company has been able to maintain relatively stable production, with low rates of decline, through initiatives such as compressor upgrades and optimization of compressor configurations. Future drilling operations will resume once gas prices and drilling costs stabilize allowing the Company to achieve targeted rates of return.

South Texas area. In South Texas, the Company's production volumes averaged 10,833 BOEPD and 12,688 BOEPD during the three and nine months ended September 30, 2009, respectively. Production volumes during the third quarter of 2009 decreased by 16 percent, as compared to the third quarter of 2008, primarily due to reduced drilling expenditures in support of the aforementioned cost reduction initiatives and normal well declines. Production volumes for the nine months ended September 30, 2009 increased by four percent as compared to the nine months ended September 30, 2008.

The Company has a substantial number of Edwards play locations in inventory for development of the previously discovered Moray, Sawfish, Skipjack and Amberjack fields, as well as several as yet undrilled exploration prospects. Drilling activity in the Edwards play will resume when forecasted operating margins increase to a level that provides adequate economic returns on drilling. In the meantime, the Company continues to maintain its strong position in South Texas through both the renewal of existing leases and the acquisition of new leases.

During the third quarter of 2009, the Company began drilling the recently announced Sinor#5 well. This well was designed to delineate the potential of the Eagle Ford play in an unexplored area while taking advantage of the technical knowledge gained through the Edwards wells in the area that were drilled through the Eagle Ford shale horizon. The well flowed at an initial rate of approximately 11.3 MMcf-equivalent per day ("MMCFEPD") of gas (approximately 8.3 MMCFEPD of liquids-rich gas and 500 BOEPD of higher-valued condensate). As a result of the success of the well, the Company intends to expand its multi-well Eagle Ford drilling program to continuously operate one rig in the play through 2010 and test the benefits of longer laterals and additional fracture-stimulation stages. The Company is also exploring joint venture opportunities to accelerate Eagle Ford Shale development operations. The Eagle Ford Shale play is prospective over much of the 310,000 acres that the Company currently holds.

In order to accommodate its Edwards Trend and Eagle Ford Play growth, the Company added additional gas gathering and processing infrastructure during 2008. The expansion includes over 28 miles of gathering system pipeline, three additional operated gas treatment plants and two additional non-operated gas treatment plants.

Barnett Shale. In the Barnett Shale area of Texas, the Company's production volumes averaged 2,937 BOEPD and 3,061 BOEPD during the three and nine months ended September 30, 2009, respectively, representing respective increases of 46 percent and 44 percent, as compared to the same periods of 2008. During the third quarter of 2009, the Company continued to improve operational performance including multiple successful well workovers and an increase in the capacity of the Company's water disposal system. During 2009, the Company participated in four non-operated successful wells, with three additional wells drilled and awaiting completion at quarter end, and is preparing to commence a 3-D seismic shoot over a portion of its acreage in the fourth quarter of 2009.

Alaska area. During the first three quarters of 2009, the Company continued drilling activities at its Oooguruk development project. The Company's production from the project, which began in June 2008, averaged 5,530 BOPD and 4,271 BOPD during the three and nine months ended September 30, 2009, respectively. The Company drilled five horizontal wells within the project's Nuiqsut reservoir during the second and third quarters, of which three were fracture-stimulated production wells and two were unstimulated water injection wells. Early results from the first three fracture-stimulated production wells, which had a combined initial flow rate of 7,400 BOPD, suggest that stabilized production may be as much as two-to-three times that of an unstimulated injector.

On the Company's Cosmopolitan Unit project in the Cook Inlet, the Company drilled a lateral sidetrack during 2007 from an existing wellbore on an onshore site to further appraise the resource potential of the unit. The initial un-stimulated production test results were encouraging. The Company plans workover operations on the well in the fourth quarter of 2009 to repair the casing. The well may be fracture-stimulated in 2010, contingent upon the results of the casing repair and subsequent flow testing. The Company will continue to conduct permitting activities and facilities planning during the fourth quarter of 2009 and may drill another appraisal well during 2010.

South Africa. In South Africa, the Company's production averaged 5,803 BOEPD and 5,674 BOEPD during the three and nine months ended September 30, 2009, respectively, representing increases of 52 percent and 51 percent, as compared to the same periods of 2008. The substantial increases in production are reflective of the commencement of production from the most prolific well in Pioneer's South Coast Gas project during the fourth quarter of 2008. First production from the Company's Sable gas well was initiated in mid-October 2008 and the other wells in the South Coast Gas project resumed production in late-October. The operator of the South Coast Gas project began a major plant maintenance shutdown on September 24, 2009 at the Mossel Bay gas-to-liquids plant where the gas production is sold. The plant turnaround is expected to be completed and the plant back to full production capacity in early November. As a result, fourth quarter forecasted production is expected to be reduced by approximately 2,000 BOEPD.

In addition, the operator has also notified the Company that past production volumes reported for the South Coast Gas project were (in the operator's view) overstated due to potential meter measurement errors. During June 2009, the operator commenced reporting volumes for the Company's account from the South Coast Gas project at the reduced amount. The Company is awaiting further technical information from the operator in order to assess the extent of the errors, if any, and will be working closely with the operator and metering specialists during the fourth quarter of 2009 and early 2010 to validate the operator's position and better understand any metering errors to ensure that the Company has received, and will receive, its appropriate share of gas production from the South Coast Gas project. The Company does not expect that the resolution of this matter will have a material impact on its liquidity, results of operations or financial position.

Tunisia. The Company's two production concessions in Southern Tunisia averaged 6,485 BOEPD and 6,890 BOEPD of production during the three and nine months ended September 30, 2009, respectively, representing a decrease of 12 percent in the quarter-to-quarter comparison and an increase of 13 percent in the year-to-date comparison. In the Company-operated Cherouq Concession, production averaged 4,359 BOEPD during the nine months ended September 30, 2009, representing an increase of 58 percent, as compared to the same period of 2008. During 2009, the Company is completing the processing of the 295 square kilometers of 3-D seismic data acquired in 2008. The geosciences work program includes the integration of existing geologic data sets into a comprehensive basin modeling project targeted at reducing uncertainty and high-grading prospective exploration and development locations. Plans are currently underway to drill three wells in early-2010. Additionally, the Company is in the process of upgrading its existing production facilities by installing permanent equipment that is expected to reduce production costs.

During the fourth quarter of 2009, the Company plans to continue its exploratory and appraisal activities on the Adam Concession by participating in up to two non-operated wells. The Company also plans to begin a 3-D seismic acquisition program on the Borj El Khadra Permit during 2010.

In the Anaguid permit, the Company has prepared a plan of development in order to request approval to convert 308 square kilometers of the existing exploration permit into a production concession. Additionally, the Company plans to complete the interpretation of the previously acquired seismic data and drill an additional exploration well during early-2010.

Results of Operations

Oil and gas revenues. Oil and gas revenues totaled $410.0 million and $1.1 billion for the three and nine months ended September 30, 2009, as compared to $600.4 million and $1.8 billion for the same respective periods of 2008.

The decrease in oil and gas revenues from continuing operations during the three and nine months ended September 30, 2009, as compared to the same periods of 2008, is reflective of decreases in revenues for all geographic operating segments. The decrease in revenues in the United States was due to decreases in average reported NGL and gas prices, partially offset by increases in average reported oil prices and sales volume increases. United States average daily sales volumes increased during the three months ended September 30, 3009, as compared to the three months ended September 30, 2008, primarily due to a six percent decrease in scheduled VPP deliveries. United States average daily sales volumes during the nine months ended September 30, 2009 increased as compared to the nine months ended September 30, 2008, primarily as a result of successful 2008 drilling activity, sales of approximately 876 BOEPD of NGLs that were in storage as of December 31, 2008 and a seven percent reduction in scheduled VPP deliveries. Revenues in Tunisia decreased due to decreases in average reported oil and gas prices during the three and nine months ended September 30, 2009, as compared to the three and nine months ended September 30, 2008. Tunisian sales volumes also declined during the three months ended September 30, 2009 as compared to the three months ended September 30, 2008, primarily due to decreases in drilling activity in support of the Company's cost reduction initiatives and normal well declines. Tunisian average daily sales volumes increased during the nine months ended September 30, 2009 as compared to the . . .