EXHIBIT 99.1

News Release

Pioneer Natural Resources Reports

Third Quarter 2013 Financial and Operating Results

Dallas, Texas, November 4, 2013 -- Pioneer Natural Resources Company (NYSE:PXD) (“Pioneer” or “the Company”) today announced financial and operating results for the quarter ended September 30, 2013.

Pioneer reported third quarter net income attributable to common stockholders of $91 million, or $0.65 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 losses and other unusual items, adjusted income for the third quarter was $176 million after tax, or $1.26 per diluted share.

Third quarter and other recent highlights included:

• producing 173 thousand barrels oil equivalent per day (MBOEPD) in the third quarter, which was slightly below the Company’s third quarter guidance, primarily due to the deferral of 3 MBOEPD as a result of increased pad drilling in the Eagle Ford Shale area that caused delays in placing new wells on production; third quarter production also reflects the conveyance of 3 MBOEPD to Sinochem as part of the southern Wolfcamp joint venture transaction and the continued growth of horizontal Wolfcamp Shale production;

• forecasting full-year 2013 production growth of 14%, which reflects the delays attributable to pad drilling in the Eagle Ford Shale area and treating the expected sale of the Company’s Alaska operations as discontinued operations;

• progressing the highly successful northern horizontal Spraberry/Wolfcamp drilling program by placing on production Pioneer’s first three Wolfcamp D interval wells including (i) the E.T. O’Daniel #2H in Midland County with a 24-hour peak initial production rate of 3,156 barrels oil equivalent per day (BOEPD), representing the highest horizontal 24-hour peak initial production rate for any interval in the Midland Basin to date, and an oil content of 69%; (ii) the Hutt C #4H in Midland County with a 24-hour peak initial production rate of 2,128 BOEPD, a peak 30-day average production rate of 856 BOEPD and an oil content of 69%; and (iii) the Scharbauer Ranch #201H in Martin County with a 24-hour peak initial production rate of 1,509 BOEPD, a peak 30-day average production rate of 662 BOEPD and an oil content of 60%;

• extending the Wolfcamp D play 50 miles west of recent industry Wolfcamp D activity;

• concluding that early production data from Pioneer’s initial Wolfcamp D interval wells on its northern acreage suggests that estimated ultimate recoveries (EURs) for these wells will equal or exceed average industry Wolfcamp D results in the Midland Basin to date;

• placing on production (i) Pioneer’s third Wolfcamp B interval well in Midland County (DL Hutt C #3H), which had the highest 24-hour peak initial production rate of 2,227 BOEPD for any Wolfcamp B interval well in the Midland Basin to date, a 30-day peak average production rate of 1,087 BOEPD and an oil content of 75% and (ii) Pioneer’s second Wolfcamp B interval well in Martin County (Scharbauer Ranch #202H) with a 24-hour peak initial production rate of 979 BOEPD, a 20-day peak average production rate of 815 BOEPD and an oil content of 73%;

• concluding that production data from Pioneer’s initial Wolfcamp B and Wolfcamp A interval wells on its northern acreage suggests that EURs for these wells are expected to exceed 800 thousand barrels oil equivalent (MBOE);

• placing on production the Company’s first two Lower Spraberry Shale interval wells and its third Jo Mill Shale interval well during late October/early November in Midland and Martin counties; these wells are currently flowing back fracture stimulation water and have not yet achieved 24-hour peak initial production rates;

• reporting that Pioneer currently has 13 horizontal wells on production with three of these wells currently flowing back, seven wells awaiting completion and five wells currently drilling;

• running five horizontal rigs in the northern Spraberry/Wolfcamp area that are drilling multiple Wolfcamp, Jo Mill and Spraberry Shale interval wells in Midland, Martin, Glasscock and Andrews counties; expect to increase to 10+ rigs in early 2014;

• testing horizontal downspacing in the Giddings area of the southern Wolfcamp joint venture area from 720 feet to 480 feet; 12 new horizontal wells have been placed on production in the Upper and Lower Wolfcamp B intervals with an average 24-hour peak initial production rate of 1,016 BOEPD per well;

• downspacing horizontal wells in the liquids-rich areas of the Eagle Ford Shale from 1,000-foot spacing between wells to 500-foot spacing between wells using zipper fracture-stimulation, which added approximately 300 locations and increased well EURs by 20% compared to offset single wells; further testing of downspacing to 300-foot well spacing in the liquids-rich areas is underway, with these activities having the potential to add 300 to 400 incremental locations;

• completing Pioneer’s first successful Upper Eagle Ford Shale well with a 24-hour peak initial production rate of 1,620 BOEPD, similar to offset Lower Eagle Ford Shale wells; approximately 25% of Pioneer’s acreage is prospective for this interval;

• announcing an agreement to sell the Company’s Alaska subsidiary for $550 million, with closing expected by year end 2013; and

• decreasing Pioneer’s net debt-to-book capitalization to 21% at the end of the third quarter.

Scott D. Sheffield, Chairman and CEO, stated, “Pioneer delivered a number of significant accomplishments in the third quarter, including drilling a horizontal Wolfcamp D well that has the highest initial production rate in the Midland Basin from any interval, achieving the highest initial production rate from the horizontal Wolfcamp B interval in the Midland Basin and extending the productivity of the Wolfcamp D interval 50 miles west of recent industry Wolfcamp D activity. We also made significant steps forward in downspacing with the completion of a 12-well pilot in the southern Wolfcamp joint venture area and successfully reducing the spacing between wells in the liquids-rich area of the Eagle Ford Shale from 1,000 feet to 500 feet. Additionally, we completed our first successful horizontal well in the Upper Eagle Ford Shale and announced the sale of our Alaska asset.”

“Although third quarter production was slightly below our guidance range as a result of delays in bringing new wells on production in the Eagle Ford Shale related to increased pad drilling, we expect fourth quarter production to grow significantly as these delayed wells and a substantial number of new pad wells from the Eagle Ford Shale and the Spraberry/Wolfcamp areas are placed on production. We are forecasting 2013 production growth of 14% compared to 2012.”

“Based on the strong production results from our initial Wolfcamp B and Wolfcamp A interval wells across our northern Midland Basin acreage, we believe that EURs for these wells will exceed 800 MBOE. We also believe that EURs for our initial Wolfcamp D interval wells will equal or exceed average industry Wolfcamp D results to date. As a result of this strong performance, we expect to increase our rig count in the northern Spraberry/Wolfcamp Shale from 5 rigs currently to 10+ rigs in 2014.”

Mark-To-Market Derivative Losses and Unusual Items Included in Third Quarter 2013 Earnings

Pioneer’s third quarter earnings included unrealized mark-to-market losses on derivatives of $85 million after tax, or $0.60 per diluted share.

Third quarter earnings also included unusual items that netted a loss of $0.01 per diluted share. Unusual items included Alaska Petroleum Production Tax credit recoveries that were offset by charges associated with the abandonment of unproved dry gas leaseholds in the Eagle Ford Shale area, merger-related costs related to the Pioneer Southwest transaction and adjustments to the previously announced net gain on the southern Wolfcamp joint venture transaction.

Operations Update and Drilling Program

Pioneer is the largest acreage holder in the Spraberry Trend Area field, where the Company believes it has greater than 4.6 billion barrels oil equivalent (BBOE) of estimated resource potential from horizontal drilling based on its extensive geologic data and its successful drilling results to date. Of this amount, 3.0 BBOE is in the northern Spraberry/Wolfcamp portion of Pioneer’s acreage and 1.6 BBOE is in the southern Wolfcamp joint venture area.

The Company is conducting a horizontal drilling program in 2013 and 2014 to appraise its northern Spraberry/Wolfcamp acreage. Pioneer expects to spud 34 wells during 2013, targeting six different “stacked” intervals across its northern acreage. The six stacked intervals across the Company’s 600,000 prospective gross acres in the northern portion of its acreage position equates to greater than 3 million prospective gross acres. Nineteen wells are expected to be drilled in the Wolfcamp A, B and D intervals. Another 15 wells are expected to be drilled in the Jo Mill, Middle Spraberry and Lower Spraberry Shales. The drilling and completion cost for these wells is expected to average $7.5 million to $8.5 million per well assuming 7,000-foot laterals. This cost excludes “science” and facilities costs, estimated at approximately $80 million in 2013.

Pioneer placed its first three horizontal Wolfcamp D interval wells on production during the third quarter and in October. The E.T. O’Daniel #2H well in Midland County had a 24-hour peak initial production rate of 3,156 BOEPD and an oil content of 69%. This is the highest initial production rate for any interval in the Midland Basin to date. The well was placed on production at the end of October, so no extended production data is available yet. The well was completed utilizing a 39-stage hybrid fracture stimulation over the well’s perforated lateral length of 9,112 feet. The Hutt C #4H in Midland County had a 24-hour peak initial production rate of 2,128 BOEPD, a 30-day peak average production rate of 856 BOEPD and an oil content of 69%. The well was completed utilizing a 25-stage hybrid fracture stimulation over the well’s perforated lateral length of 6,962 feet. The Scharbauer Ranch #201H in Martin County had a 24-hour peak initial production rate of 1,509 BOEPD, a 30-day peak average production rate of 662 BOEPD and an oil content of 60%. The well was completed utilizing a 33-stage hybrid fracture stimulation over the well’s perforated lateral length of 7,682 feet.

Early production data from these initial Wolfcamp D interval wells suggests that EURs for these wells will equal or exceed average industry Wolfcamp D interval results to date. These successful wells, which are spread out over a significant portion of Pioneer’s northern acreage, also extend the play 50 miles west of recent industry Wolfcamp D drilling activity.

In the third quarter, Pioneer placed on production the Company’s third Wolfcamp B interval well in Midland County, Texas. The DL Hutt C #3H had the highest 24-hour peak initial production rate of 2,227 BOEPD to date in the Midland Basin for Wolfcamp B interval wells. The well had a 30-day peak average production rate of 1,087 BOEPD and an oil content of 75%. The well was completed utilizing a 30-stage hybrid fracture stimulation over the well’s perforated lateral length of 7,142 feet.

The Company also placed on production the Company’s second Wolfcamp B interval well in Martin County during the third quarter. The Scharbauer Ranch #202H had a 24-hour peak initial production rate of 979 BOEPD and a 20-day peak average production rate of 815 BOEPD, with an oil content of 73%. The well

was completed utilizing a 35-stage hybrid fracture stimulation over the well’s perforated lateral length of 8,342 feet.

Pioneer has five horizontal Wolfcamp Shale wells on production in Midland and Martin Counties. In addition to the two Wolfcamp B interval wells that were placed on production during the third quarter, the Company has two other Wolfcamp B interval wells and one Wolfcamp A interval well on production. The oldest well has nine months of production history with cumulative production of 170 MBOE (Wolfcamp B), while the other two wells have produced 115 MBOE (Wolfcamp A) over five months and 100 MBOE (Wolfcamp B) over six months, respectively. The production data from these wells suggests that EURs for these wells, which are spread out over a significant portion of Pioneer’s northern Spraberry/Wolfcamp acreage, are expected to exceed 800 MBOE. Before-tax internal rates of return for wells with EURs of 800 MBOE are expected to be approximately 125% and pay out in less than one year. This assumes a single well drilling and completion cost of $8 million and an oil price of $95 per barrel.

The Company also placed on production the Company’s first two Lower Spraberry Shale interval wells and its third Jo Mill Shale interval well during late October/early November in Midland and Martin counties. These wells are currently flowing back fracture stimulation water and have not yet achieved 24-hour peak rates. Since the Lower Spraberry Shale and Jo Mill Shale interval wells are at shallower depths than the Wolfcamp Shale interval wells, these wells can flow back fracture stimulation water for 30 days to 60 days before achieving initial peak production rates due to lower subsurface pressures.

The Company is currently running five horizontal rigs across its northern acreage and expects to increase to 10+ rigs in early 2014. The five-rig program is expected to spud 14 wells by year end. The wells are split evenly between Wolfcamp Shale and Spraberry Shale wells in Midland, Martin, Glasscock and Andrews counties. To date, the Company has placed 13 horizontal wells on production, with three of these currently flowing back. This includes eight Wolfcamp Shale wells and five Spraberry Shale wells in Midland, Martin and Upton counties. Seven horizontal wells are currently awaiting completion in Midland and Andrews counties, of which four are Wolfcamp Shale wells and three are Spraberry Shale wells. The majority of the wells are being drilled on two-well pads to gain efficiencies; therefore, the wells will not be completed until after the second well on each pad is drilled. It is expected to take 120 days to 150 days from the time the first well on a two-well pad is spud until both wells on the pad are placed on production. This includes the extra time required for “science” and appraisal activities. This is resulting in “lumpy” production growth. By the end of this year, Pioneer’s appraisal program will extend approximately 65 miles north of the area where the first two successful Wolfcamp B interval wells were drilled two years ago on the Giddings Estate lease.

The Company placed 16 new horizontal wells on production in the southern Wolfcamp joint venture area during the third quarter, with 24-hour peak initial production rates up to 1,241 BOEPD. Well performance across the area continues to meet expectations and reinforces the Company’s estimate that wells in this area will deliver an average EUR of at least 575 MBOE over the life of the well.

Pioneer is currently running eight rigs in the joint venture area and expects to spud approximately 100 wells in 2013 with an average lateral length of 8,300 feet. This includes twenty-four 10,000-foot lateral wells, with fifteen of these wells scheduled to be spud in the fourth quarter. These longer lateral wells are expected to increase the well’s EUR by 40% at an incremental cost of 20%. The average drilling and completion cost for the 2013 program is $7.5 million to $8.0 million per well. Approximately 70% of the wells drilled in this area during 2013 will be on three-well pads. It is taking approximately 150 days from the time the first well on a three-well pad is spud until all three wells on the pad are placed on production. This is also resulting in “lumpy” production growth.

Pioneer is testing downspacing from 720-foot spacing between wells (116-acre spacing) to 480-foot spacing between wells (77-acre spacing) in the Giddings area. The initial test includes 12 wells that have been drilled on three-well pads using zipper fracture stimulations. The wells are also staggered between the Upper Wolfcamp B and Lower Wolfcamp B intervals. All 12 wells are currently on production. The average 24-hour peak initial production rate for the 12 wells was 1,016 BOEPD. The wells all have

approximately 6,200-foot perforated lateral lengths and were completed utilizing a 21-stage hybrid fracture stimulation. The initial production rates for the 12 downspaced wells compares favorably to the initial two Giddings Wolfcamp B interval wells, which averaged 830 BOEPD at similar lateral lengths.

Pioneer is also operating 15 vertical rigs in the Spraberry field during 2013, which are expected to drill approximately 300 wells. These rigs are required to meet continuous drilling obligations. Approximately 90% of the 300 wells in the 2013 vertical drilling program are expected to be completed in the deeper Strawn and Atoka intervals. Pioneer drilled 75 vertical wells in the third quarter and placed 86 vertical wells on production. With 15 rigs running, vertical production is expected to decline in 2013 by 10%. The Company expects to reduce its vertical rig count going forward, allowing it to devote more of its capital to higher rate of return horizontal drilling.

Third quarter production from the entire Spraberry/Wolfcamp area averaged 79 MBOEPD. This included an increase in horizontal production to 8 MBOEPD and a decrease in vertical production to 71 MBOEPD. Third quarter production was impacted by the conveyance of 3 MBOEPD to Sinochem as part of the southern Wolfcamp joint venture transaction and the loss of approximately 1 MBOEPD due to the Midkiff/Benedum gas processing system rejecting ethane as a result of low ethane prices. Production for the fourth quarter is forecasted to grow to 85 MBOEPD to 88 MBOEPD as a result of placing approximately 45 new horizontal wells on production during the quarter.

For 2013, total Spraberry/Wolfcamp production is forecasted to grow to 80 MBOEPD to 81 MBOEPD, an increase of 21% to 22% compared to 2012. The range has been increased from the previous forecast of 17% to 21% to reflect the strong performance by this asset over the first nine months of 2013. The 2013 growth forecast for the Spraberry/Wolfcamp area also reflects that the vertical rig count decreased from an average of 32 rigs in 2012 to 15 rigs in 2013, while the horizontal rig count increased from an average of three rigs in 2012 to an average of 12 rigs in 2013. Pioneer expects horizontal production to increase from an average of 2 MBOEPD in 2012 to 10 MBOEPD in 2013.

In the liquids-rich Eagle Ford Shale play in South Texas, Pioneer has added approximately 300 drilling locations in the liquids-rich area of the play as a result of downspacing from 1,000 feet between wells (120-acre spacing) to 500 feet (60-acre spacing) between wells. The Company also utilized zipper fracture stimulation on three-well and four-well pads in the same liquids-rich areas where downspacing has been implemented. Using this fracture stimulation technique on the pad wells improves the fracture network and has resulted in EURs for the zipper fracture-stimulated wells increasing by 20% as compared to offset single wells, or from 1.0 million barrels oil equivalent (MMBOE) to 1.2 MMBOE.

Further testing of downspacing to 300 feet between wells is underway in the liquids-rich areas where 500-foot spacing was successful. Early results are encouraging, and the potential exists to add 300 to 400 drilling locations. This testing will include staggered laterals in the Upper Eagle Ford Shale interval and the Lower Eagle Ford Shale interval. Pioneer’s first Upper Eagle Ford Shale well was recently successfully completed with a 24-hour peak initial production rate of 1,620 BOEPD, comparable to Lower Eagle Ford Shale interval wells. Approximately 25% of Pioneer’s acreage is expected to be prospective for this interval.

Pioneer expects to drill approximately 130 Eagle Ford Shale wells in 2013 at a cost of $7 million to $8 million per well for lateral lengths of approximately 5,500 feet. Essentially all of these wells will be in Pioneer’s liquids-rich acreage. 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 more than 80% of the wells drilled in 2013, reflecting that most of Pioneer’s acreage is now held by production. Pad sizes range from two wells to six wells per pad. None of the wells are fracture stimulated until all of the wells on a pad are drilled. Therefore, the timing between when the first well on a pad is spud and when the pad is placed on production is dependent on how many wells are drilled from the pad and is significantly extended compared to single- well drilling. For perspective, it is taking 100 days to 125 days from the time the first well on a three-well pad is spud until all three wells on the pad are placed on production. Consequently, the Company’s pad drilling is resulting in

“lumpy” quarter-to-quarter production growth. The Company placed 26 wells on production during the third quarter of 2013, of which 11 were in September, and expects to place approximately 45 wells on production during the fourth quarter. 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 a similar number of wells in 2012 with 12 rigs.

After delivering consistent quarterly production growth since the inception of Pioneer’s drilling activity in the Eagle Ford Shale in 2009, production for the third quarter declined by 3 MBOEPD compared to the second quarter. This reflects delays in placing wells on production related to increased pad drilling in the third quarter (approximately 2,000 BOEPD) and a higher number of wells that had to be shut in for offset fracture stimulation activity related to downspacing tests (approximately 1,000 BOEPD). At times during the third quarter, as much as 8% of Eagle Ford Shale production was shut in for this reason. Based on the number of wells that were placed on production towards the end of the third quarter (11 in September) and the schedule to place wells on production in the fourth quarter, production is forecasted to increase from 35 MBOEPD in the third quarter to 39 MBOEPD to 41 MBOEPD in the fourth quarter. The Company expects 2013 production to range from 37 MBOEPD to 38 MBOEPD, an increase of 34% to 38% compared to full-year 2012 production of 28 MBOEPD. This reflects a reduction in the previous full-year guidance range which was 38 MBOEPD to 42 MBOEPD.

2013 Capital Budget

Pioneer’s capital program for 2013 remains unchanged at $3 billion (includes land capital but excludes asset retirement obligations, capitalized interest and geological and geophysical G&A). The capital program includes $2.75 billion of drilling capital and $240 million for vertical integration additions and construction of new field and office buildings. Drilling capital expenditures totaled $608 million in the third quarter of 2013 and $2.1 billion for the first nine months of 2013.

The 2013 capital budget is expected to be funded from forecasted operating cash flow of $2.3 billion, assuming commodity prices for the full year of $98 per barrel for oil and $3.70 per thousand cubic feet (MCF) for gas, and from cash on the balance sheet.

Pioneer’s net debt as of September 30, 2013 was $2.1 billion, the same level as June 30, 2013. The Company has $1.5 billion available from its unsecured credit facility that matures in 2017. Net debt-to-book capitalization was 21% at the end of the third quarter, down from 22% at the end of the second quarter. The Company will continue to target a net debt-to-book capitalization below 35% and net debt-to-operating cash flow below 1.5 times.

Sale of Alaska Subsidiary

On October 25, 2013, the Company announced that it had entered into a purchase and sale agreement with Caelus Energy Alaska LLC to sell 100% of the equity in Pioneer’s subsidiary, Pioneer Natural Resources Alaska, Inc., for cash proceeds of $550 million, subject to normal closing adjustments. Proceeds from the sale will be redeployed to the Company’s core, oil-related Spraberry/Wolfcamp assets. The transaction has an effective date of October 1, 2013 and is expected to close by the end of the year or early in 2014.

The sale of Pioneer’s Alaska subsidiary is expected to result in a noncash loss of approximately $350 million, which will be recorded in the fourth quarter of 2013. The financial and operating results related to Pioneer’s Alaska activities are expected to be reflected as discontinued operations for the quarter ending December 31, 2013, and for all prior periods that will be presented in the Company’s December 31, 2013 Form 10-K. Net production from the Alaska subsidiary averaged approximately 4 thousand barrels of oil per day (MBPD) over the first nine months of 2013.

Third Quarter 2013 Financial Review

Sales volumes for the third quarter of 2013 averaged 173 MBOEPD. Oil sales averaged 74 MBPD, natural gas liquids (NGLs) sales averaged 37 MBPD and gas sales averaged 368 million cubic feet per day.

The average realized price for oil was $101.83 per barrel. The average realized price for NGLs was $30.17 per barrel and the average realized price for gas was $3.32 per MCF. These prices exclude derivatives.

Production costs averaged $14.81 per barrel oil equivalent (BOE). Depreciation, depletion and amortization (DD&A) expense averaged $16.14 per BOE. Exploration and abandonment costs were $32 million, principally comprised of $8 million associated with acreage abandonments, $7 million for seismic data and $17 million for personnel costs. General and administrative expense totaled $74 million. Interest expense was $45 million and other expense was $25 million.

Fourth Quarter 2013 Financial Outlook

The Company’s fourth quarter 2013 outlook for certain operating and financial items is provided below. This outlook excludes Alaska operations which are expected to be reflected as discontinued operations beginning in the fourth quarter.

Production is forecasted to average 179 MBOEPD to 184 MBOEPD.

Production costs are expected to average $14.00 per BOE to $16.00 per BOE. DD&A expense is expected to average $15.50 per BOE to $17.50 per BOE. Total exploration and abandonment expense is forecasted to be $25 million to $35 million.

General and administrative expense is expected to be $70 million to $75 million, interest expense is expected to be $44 million to $49 million and other expense is expected to be $25 million to $35 million. Accretion of discount on asset retirement obligations is expected to be $3 million to $5 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%. Current income taxes are expected to be $10 million to $15 million and are primarily attributable to federal alternative minimum tax and 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 Tuesday, November 5, 2013, at 9:00 a.m. Central Time, Pioneer will discuss its financial and operating results for the quarter ended September 30, 2013, with an accompanying presentation. Instructions for listening to the call and viewing the accompanying presentation are shown below.

Internet: www.pxd.com

Select “Investors,” then “Earnings & Webcasts” to listen to the discussion, view the presentation and see other related material.

Telephone: Dial (800) 967-7188 confirmation code: 7779932 five minutes before the call. View the presentation via Pioneer’s internet address above.

A replay of the webcast will be archived on Pioneer’s website. A telephone replay will be available through November 30, 2013, by dialing (888) 203-1112 confirmation code: 7779932.

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, satisfaction of the conditions to the closing of the Company’s agreement to sell its Alaska subsidiary, 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 the Company’s industrial sand mining and oilfield services businesses 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.

Pioneer Natural Resources Contacts:

Investors

Frank Hopkins - 972-969-4065

Josh Jones - 972-969-5822

Mike Bandy - 972-969-4513

Media and Public Affairs

Susan Spratlen - 972-969-4018

Suzanne Hicks - 972-969-4020

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)

	September 30, 2013			December 31, 2012
ASSETS
Current assets:
Cash and cash equivalents	$	744,120		$	229,396
Accounts receivable, net	413,452			320,153
Income taxes receivable	10,168			7,447
Inventories	226,438			197,056
Prepaid expenses	19,984			13,438
Derivatives	114,166			279,119
Other current assets, net	4,933			3,746
Total current assets	1,533,261			1,050,355
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting	16,074,308			14,491,263
Accumulated depletion, depreciation and amortization	(5,086,258		)	(4,412,913		)
Total property, plant and equipment	10,988,050			10,078,350
Goodwill	279,687			298,142
Other property and equipment, net	1,258,627			1,217,694
Investment in unconsolidated affiliate	235,631			204,129
Derivatives	86,574			55,257
Other assets, net	163,114			165,103
	$	14,544,944		$	13,069,030
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	1,060,384		$	826,877
Interest payable	36,509			68,083
Income taxes payable	129			208
Deferred income taxes	60,340			86,481
Derivatives	6,436			13,416
Other current liabilities	51,013			39,725
Total current liabilities	1,214,811			1,034,790
Long-term debt	2,851,212			3,721,193
Derivatives	7,719			12,307
Deferred income taxes	2,415,663			2,140,416
Other liabilities	292,788			293,016
Equity	7,762,751			5,867,308
	$	14,544,944		$	13,069,030

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Revenues and other income:
Oil and gas	$	908,757		$	716,327		$	2,541,748		$	2,077,020
Interest and other	21,087			10,256			41,561			31,450
Derivative gains (losses), net	(102,535		)	(123,994		)	(333		)	243,568
Gain (loss) on disposition of assets, net	(487		)	12,848			214,917			57,584
	826,822			615,437			2,797,893			2,409,622
Costs and expenses:
Oil and gas production	181,340			179,687			529,968			461,549
Production and ad valorem taxes	53,946			49,779			162,080			140,070
Depletion, depreciation and amortization	256,260			207,398			736,613			589,737
Impairment of oil and gas properties	—			—			—			444,880
Exploration and abandonments	31,509			27,039			83,109			117,504
General and administrative	73,722			62,567			204,127			180,591
Accretion of discount on asset retirement obligations	3,180			2,497			9,499			7,371
Interest	45,138			54,441			138,678			150,307
Other	24,947			32,011			65,007			86,269
	670,042			615,419			1,929,081			2,178,278
Income from continuing operations before income taxes	156,780			18			868,812			231,344
Income tax provision	(58,233		)	(10,614		)	(309,591		)	(83,231		)
Income (loss) from continuing operations	98,547			(10,596		)	559,221			148,113
Income (loss) from discontinued operations, net of tax	—			32,295			(465		)	55,007
Net income	98,547			21,699			558,756			203,120
Net income attributable to noncontrolling interests	(7,422		)	(2,475		)	(29,705		)	(39,669		)
Net income attributable to common stockholders	$	91,125		$	19,224		$	529,051		$	163,451
Basic earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$	0.65		$	(0.11	)	$	3.87		$	0.87
Income (loss) from discontinued operations attributable to common stockholders	—			0.26			—			0.44
Net income attributable to common stockholders	$	0.65		$	0.15		$	3.87		$	1.31
Diluted earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$	0.65		$	(0.11	)	$	3.82		$	0.85
Income (loss) from discontinued operations attributable to common stockholders	—			0.26			—			0.43
Net income attributable to common stockholders	$	0.65		$	0.15		$	3.82		$	1.28
Weighted average shares outstanding:
Basic	138,586			123,111			135,057			122,874
Diluted	138,946			123,111			136,835			126,111

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Cash flows from operating activities:
Net income	$	98,547		$	21,699		$	558,756		$	203,120
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization	256,260			207,398			736,613			589,737
Impairment of oil and gas properties	—			—			—			444,880
Exploration expenses, including dry holes	7,945			12,844			20,238			52,574
Deferred income taxes	66,574			18,889			300,312			76,180
(Gain) loss on disposition of assets, net	487			(12,848		)	(214,917		)	(57,584		)
Accretion of discount on asset retirement obligations	3,180			2,497			9,499			7,371
Discontinued operations	—			(22,842		)	(158		)	(19,245		)
Interest expense	4,132			8,660			13,039			26,812
Derivative related activity	136,556			237,088			122,068			93,088
Amortization of stock-based compensation	18,762			15,929			52,789			46,899
Amortization of deferred revenue	—			(10,575		)	—			(31,494		)
Other noncash items	5,265			(13,485		)	559			(20,998		)
Change in operating assets and liabilities, net of effects from acquisitions and dispositions:
Accounts receivable, net	(56,065		)	(41,827		)	(88,993		)	(7,946		)
Income taxes receivable	(9,241		)	(7,180		)	(2,721		)	(8,632		)
Inventories	(27,336		)	26,971			(28,015		)	(6,347		)
Prepaid expenses	2,907			6,653			(7,289		)	(6,772		)
Other current assets	(759		)	16,744			1,778			7,898
Accounts payable	193,517			(7,026		)	184,345			23,554
Interest payable	(24,954		)	(16,384		)	(31,574		)	(16,302		)
Income taxes payable	(828		)	(1,659		)	(98		)	(9,566		)
Other current liabilities	(6,541		)	(9,486		)	(21,963		)	(29,757		)
Net cash provided by operating activities	668,408			432,060			1,604,268			1,357,470
Net cash used in investing activities	(648,212		)	(694,023		)	(1,461,908		)	(2,516,089		)
Net cash provided by financing activities	28,299			278,080			372,364			955,021
Net increase (decrease) in cash and cash equivalents	48,495			16,117			514,724			(203,598		)
Cash and cash equivalents, beginning of period	695,625			317,769			229,396			537,484
Cash and cash equivalents, end of period	$	744,120		$	333,886		$	744,120		$	333,886

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUMMARY PRODUCTION AND PRICE DATA

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Average Daily Sales Volumes from Continuing Operations:
Oil (Bbls)	73,944		64,342		74,319		61,159
Natural gas liquids ("NGL") (Bbls)	37,363		32,824		34,938		29,103
Gas (Mcf)	367,823		376,364		383,937		372,846
Total (BOE)	172,611		159,894		173,247		152,403
Average Reported Prices (a):
Oil (per Bbl)	$	101.83	$	89.88	$	93.77	$	92.84
NGL (per Bbl)	$	30.17	$	30.96	$	29.58	$	34.88
Gas (per Mcf)	$	3.32	$	2.62	$	3.41	$	2.38
Total (BOE)	$	57.23	$	48.70	$	53.74	$	49.74

__________

(a) Average reported prices are attributable to continuing operations and, for 2012, include the results of hedging activities and amortization of volumetric production payment ("VPP") deferred revenue. During 2012, all remaining deferred hedge losses were transferred to earnings and, as of December 31, 2012, all VPP production volumes had been delivered and there were no further obligations under VPP contracts or 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") provide that share- and unit-based awards with guaranteed dividend or distribution participation rights qualify as "participating securities" during their vesting periods. Participating securities participate in the Company's dividend or partnership distributions and are assumed to participate in the Company's undistributed income proportionate to their share of the weighted average outstanding common shares, but are not assumed to participate in the Company's net losses because they are not contractually obligated to do so. The Company's basic net income per share attributable to common stockholders is computed as (i) net income attributable to common stockholders, (ii) less participating share- and unit-based basic earnings (iii) divided by weighted average basic shares outstanding. The Company's diluted net income per share attributable to common stockholders is computed as (i) basic net income attributable to common stockholders, (ii) plus the reallocation of participating earnings (iii) divided by weighted average diluted shares outstanding. During periods in which the Company realizes a loss from continuing operations attributable to common stockholders, securities or other contracts to issue common stock would be dilutive to loss per share; therefore, conversion into common stock is assumed not to occur.

The following table is a reconciliation of the Company's net income attributable to common stockholders to basic net income attributable to common stockholders and to diluted net income attributable to common stockholders for the three and nine months ended September 30, 2013 and 2012:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(in thousands)
Net income attributable to common stockholders	$	91,125		$	19,224		$	529,051		$	163,451
Participating basic earnings	(1,239		)	(357		)	(6,729		)	(2,499		)
Basic net income attributable to common stockholders	89,886			18,867			522,322			160,952
Reallocation of participating earnings	3			—			102			134
Diluted net income attributable to common stockholders	$	89,889		$	18,867		$	522,424		$	161,086

The following table is a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three and nine months ended September 30, 2013 and 2012:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2013	2012	2013	2012
	(in thousands)
Weighted average common shares outstanding:
Basic	138,586	123,111	135,057	122,874
Dilutive common stock options	128	—	141	196
Convertible senior notes dilution	—	—	1,453	2,866
Contingently issuable performance unit shares	232	—	184	175
Diluted	138,946	123,111	136,835	126,111

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Net income	$	98,547		$	21,699		$	558,756		$	203,120
Depletion, depreciation and amortization	256,260			207,398			736,613			589,737
Exploration and abandonments	31,509			27,039			83,109			117,504
Impairment of oil and gas properties	—			—			—			444,880
Accretion of discount on asset retirement obligations	3,180			2,497			9,499			7,371
Interest expense	45,138			54,441			138,678			150,307
Income tax provision	58,233			10,614			309,591			83,231
(Gain) loss on disposition of assets, net	487			(12,848		)	(214,917		)	(57,584		)
(Income) loss from discontinued operations	—			(32,295		)	465			(55,007		)
Derivative related activity	136,556			237,088			122,068			93,088
Amortization of stock-based compensation	18,762			15,929			52,789			46,899
Amortization of deferred revenue	—			(10,575		)	—			(31,494		)
Other noncash items	5,265			(13,485		)	559			(20,998		)
EBITDAX (a)	653,937			507,502			1,797,210			1,571,054
Cash interest expense	(41,006		)	(45,781		)	(125,639		)	(123,495		)
Current income tax (provision) benefit	8,341			8,275			(9,279		)	(7,051		)
Discretionary cash flow (b)	621,272			469,996			1,662,292			1,440,508
Discontinued operations cash activity	—			9,453			(623		)	35,762
Cash exploration expense	(23,564		)	(14,195		)	(62,871		)	(64,930		)
Changes in operating assets and liabilities (c)	70,700			(33,194		)	5,470			(53,870		)
Net cash provided by operating activities	$	668,408		$	432,060		$	1,604,268		$	1,357,470

__________

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

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 losses, and adjusted income excluding unrealized MTM derivative losses and unusual items, as presented in this press release, are presented and reconciled to Pioneer's net income attributable to common stockholders (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 table below reconciles Pioneer's net income attributable to common stockholders for the three months ended September 30, 2013, as determined in accordance with GAAP, to income adjusted for unrealized MTM derivative losses and adjusted income excluding unrealized MTM derivative losses and unusual items for that quarter.

	After-tax Amounts		Amounts Per Share
Net income attributable to common stockholders	$	91,125	$	0.65
Unrealized MTM derivative losses	84,648		0.60
Income adjusted for unrealized MTM derivative losses	175,773		1.25
Net unusual items included in income (a)	164		0.01
Adjusted income excluding unrealized MTM derivative losses and unusual items	$	175,937	$	1.26

__________

(a) Third quarter unusual items included Alaska Petroleum Production Tax credits offset by abandonment of unproved dry gas leaseholds, Pioneer Southwest merger-related transaction costs and adjustments to the net gain on the southern Wolfcamp joint venture transaction.

PIONEER NATURAL RESOURCES COMPANY

SUPPLEMENTAL INFORMATION

Open Commodity Derivative Positions as of October 31, 2013

(Volumes are average daily amounts)

	2013			Year Ending December 31,
	Fourth Quarter			2014			2015			2016
Average Daily Oil Production Associated with Derivatives (Bbl):
Collar contracts with short puts:
Volume	69,000			69,000			85,000			25,000
NYMEX price:
Ceiling	$	120.55		$	114.05		$	98.98		$	93.30
Floor	$	91.39		$	93.70		$	88.06		$	85.00
Short put	$	74.22		$	77.61		$	73.06		$	70.00
Swap contracts:
Volume	9,750			10,000			—			—
NYMEX price	$	95.57		$	93.87		$	—		$	—
Rollfactor swap contracts:
Volume	11,000			19,000			—			—
NYMEX roll price (a)	$	0.85		$	0.45		$	—		$	—
Basis swap contracts:
Cushing to LLS index swap volume	3,000			—			—			—
Price differential ($/Bbl) (b)	$	8.53		$	—		$	—		$	—
Average Daily NGL Production Associated with Derivatives (Bbl):
Collar contracts with short puts (c):
Volume	1,064			1,000			—			—
Index price:
Ceiling	$	105.28		$	109.50		$	—		$	—
Floor	$	89.30		$	95.00		$	—		$	—
Short put	$	75.20		$	80.00		$	—		$	—
Collar contracts (d):
Volume	2,500			3,000			—			—
Index price:
Ceiling	$	12.68		$	13.72		$	—		$	—
Floor	$	10.50		$	10.78		$	—		$	—
Average Daily Gas Production Associated with Derivatives (MMBtu):
Collar contracts with short puts:
Volume	—			115,000			285,000			20,000
NYMEX price:
Ceiling	$	—		$	4.70		$	5.07		$	5.36
Floor	$	—		$	4.00		$	4.00		$	4.00
Short put	$	—		$	3.00		$	3.00		$	3.00
Collar contracts:
Volume	152,500			—			—			—
NYMEX price:
Ceiling	$	6.22		$	—		$	—		$	—
Floor	$	4.98		$	—		$	—		$	—
Swap contracts:
Volume	165,870			175,000			20,000			—
NYMEX price (e)	$	5.10		$	4.02		$	4.31		$	—
Basis swap contracts:
Permian Basin index swap volume (f)	52,500			10,000			10,000			—
Price differential ($/MMBtu)	$	(0.23	)	$	(0.15	)	$	(0.13	)	$	—
Mid-Continent index swap volume (f)	50,000			75,082			20,000			—
Price differential ($/MMBtu)	$	(0.30	)	$	(0.20	)	$	(0.21	)	$	—
Gulf Coast index swap volume (f)	60,000			—			—			—
Price differential ($/MMBtu)	$	(0.14	)	$	—		$	—		$	—

__________

(a)	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 (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 Cushing WTI and Louisiana Light Sweet crude ("LLS").
(c)	Represent collar contracts with short puts that reduce the price volatility of natural gasoline forecasted for sale by the Company at Mont Belvieu, Texas-posted prices.
(d)	Represent collar contracts that reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices.
(e)	Represents the NYMEX Henry Hub index price on the derivative trade date.
(f)	Represent swaps that fix the basis differentials between the indices 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 September 30, 2013, the Company was a party to interest rate derivative contracts whereby the Company will receive a fixed interest rate of 3.95 percent in exchange for paying a floating interest rate comprised of the three-month LIBOR plus an average rate of 1.11 percent on a notional amount of $400 million through July 15, 2022.

Derivative Losses, Net

(in thousands)

The following table summarizes net derivative gains and losses that the Company has recorded in it earnings for the three and nine months ended September 30, 2013:

	Three Months Ended September 30, 2013			Nine Months Ended September 30, 2013
Noncash changes in fair value:
Oil derivative losses	$	(114,494	)	$	(58,621	)
NGL derivative gains (losses)	(2,023		)	812
Gas derivative losses	(26,426		)	(80,392		)
Marketing derivative gains	—			22
Interest rate derivative gains	6,387			16,111
Total noncash derivative losses, net (a)	(136,556		)	(122,068		)
Cash settled changes in fair value:
Oil derivative gains (losses)	(8,599		)	6,250
NGL derivative gains	907			872
Gas derivative gains	41,713			114,299
Marketing derivative losses	—			(168		)
Interest rate derivative gains	—			482
Total cash derivative gains, net	34,021			121,735
Total derivative losses, net	$	(102,535	)	$	(333	)

__________

(a) Total noncash net derivative losses include $2.2 million of net losses and $2.5 million of net gains attributable to noncontrolling interests in consolidated subsidiaries during the three and nine months ended September 30, 2013, respectively.