EXHIBIT 99.1

News Release

Pioneer Natural Resources Reports

Third Quarter 2014 Financial and Operating Results

Dallas, Texas, November 4, 2014 -- Pioneer Natural Resources Company (NYSE:PXD) (“Pioneer” or “the Company”) today announced financial and operating results for the quarter ended September 30, 2014.

Pioneer reported third quarter net income attributable to common stockholders of $374 million, or $2.58 per diluted share (see attached schedule for a description of the net income per diluted share calculation). Without the effect of noncash derivative mark-to-market gains and other unusual items, adjusted income for the third quarter was $195 million after tax, or $1.35 per diluted share.

Third quarter and other recent highlights included:

• producing 186 thousand barrels oil equivalent per day (MBOEPD) from continuing operations in the third quarter (reflects Barnett Shale and Hugoton divestitures as discontinued operations), an increase of 10 MBOEPD, or 6%, compared to the second quarter of 2014; oil production increased nine thousand barrels per day quarter over quarter; third quarter production growth was primarily driven by the Company’s successful Spraberry/Wolfcamp horizontal drilling program;

• narrowing 2014 production growth forecast from continuing operations from a range of 16% to 19% to a range of 18% to 19% based on (i) being on schedule to more than double the number of horizontal wells placed on production in the Spraberry/Wolfcamp in the second half of 2014 compared to the first half of the year, (ii) mid-October production being greater than 195 MBOEPD and (iii) fourth quarter production forecasted to be in the range of 200 MBOEPD to 205 MBOEPD;

• forecasting drilling capital expenditures of approximately $3.1 billion for 2014;

• continuing to forecast annual production growth from continuing operations of 16% to 21% through 2016;

• protecting cash flow with derivative coverage of greater than 85% of forecasted oil production for the remainder of 2014, greater than 85% for 2015 and 45% of forecasted 2016 production;

• having 100% of the Company’s Spraberry/Wolfcamp area oil production protected against volatility in the Midland-Cushing oil price differential;

• continuing to deliver production results that support strong estimated ultimate recoveries (EURs) and internal rates of return (IRRs) from Pioneer’s horizontal Wolfcamp and Lower Spraberry Shale wells placed on production in its northern Spraberry/Wolfcamp acreage since early 2013;

• delineating the Wolfcamp A interval on a significant portion of Pioneer’s northern Spraberry/Wolfcamp acreage by placing 11 wells on production during the third quarter at an average 24-hour initial production rate of 1,225 barrels oil equivalent per day (BOEPD) and average lateral length of approximately 6,900 feet;

• continuing the Company’s successful downspacing and staggering program in the Eagle Ford Shale, which included placing 18 wells on production in Upper targets during the third quarter;

• exporting six cargoes of Eagle Ford Shale condensate from July through early November with improved pricing compared to domestic condensate sales;

• observing that multiple independent studies have recently been published that support lifting the oil export ban in the U.S.;

• announcing the closing of Pioneer’s Hugoton and Barnett Shale asset sales for $328 million and $150 million, respectively, including normal closing adjustments;

• maintaining a strong balance sheet with $550 million of cash on hand at the end of the third quarter and net debt-to-book capitalization of 23%; and

• announcing plans to divest Pioneer’s 50.1% share of Eagle Ford Shale Midstream business.

Scott D. Sheffield, Chairman and CEO, stated, “The Company delivered another great quarter, with strong earnings, production at the top end of our third-quarter guidance range and continued impressive horizontal well performance in the Spraberry/Wolfcamp. We have successfully transformed our Spraberry/Wolfcamp acreage from a vertical play into a world-class horizontal play and are delivering the second half production growth we forecasted earlier this year. We now expect to grow production by 18% to 19% in 2014,the upper end of our full-year guidance range, and believe we can deliver consistent annual production growth of 16% to 21% through 2016 at attractive returns ranging from 40% to 80% in a $70 to $80 oil price environment.”

“Looking beyond 2014, Pioneer plans to continue to prudently develop our industry-leading position in the Spraberry/Wolfcamp. Our rig contracts provide us with the flexibility to adjust our rig count with fluctuations in oil prices. Construction of front-end loaded infrastructure, which is expected to provide significant future cost savings and support Pioneer’s long-term growth plans in the Spraberry/Wolfcamp, is expected to continue. This infrastructure includes a field-wide water distribution network, continued build-out of horizontal tank batteries, additional gas processing facilities and expansion of the Brady sand mine.”

Mark-To-Market Derivative Losses and Unusual Items Included in Third Quarter 2014 Earnings

Pioneer’s third quarter earnings included noncash mark-to-market gains on derivatives of $216 million after tax, or $1.49 per diluted share, and a loss from discontinued operations of $37 million after tax, or $0.26 per diluted share, associated with the Barnett Shale and Hugoton results during the quarter.

Spraberry/Wolfcamp Operations Update

Over the 2011 through 2014 period, Pioneer has successfully transformed its Spraberry/Wolfcamp acreage from a vertical play into a world-class horizontal play. This includes:

• successfully appraising six highly prospective stacked intervals on more than 825,000 gross acres; wells producing from these intervals exhibit strong EURs and IRRs with high oil content;

• significantly increasing the net asset value of the Company by growing net recoverable resource potential from 3.1 billion barrels oil equivalent (BBOE) to 9.6 BBOE and identifying a multi-year inventory of more than 20,000 drilling locations;

• more than doubling Spraberry/Wolfcamp production from 45 MBOEPD in 2011 to 103 MBOEPD in the third quarter of 2014;

• entering into a joint venture with Sinochem in the southern portion of the Wolfcamp play;

• building a premier pressure pumping company and acquiring a frac sand company (fourth largest in the U.S.) with strategic proximity to the Spraberry/Wolfcamp;

• increasing Pioneer’s gross gas processing capacity in the Spraberry/Wolfcamp from 285 million cubic feet per day (MMCFPD) to approximately one billion cubic feet per day;

• securing long-term water supplies to support drilling and fracture stimulation operations in the Spraberry/Wolfcamp; and

• negotiating third party sales transactions that provide Pioneer with premium pricing on its Spraberry/Wolfcamp oil production.

The Company successfully placed 65 horizontal oil wells on production during 2013 and the first nine months of 2014 across its northern acreage position in the Wolfcamp Shale and Lower Spraberry Shale intervals. Of these, 56 wells were in the Wolfcamp A, B and D intervals and nine wells were in the Lower Spraberry Shale interval. Production data from these wells continues to support EURs of:

• 800 thousand barrels oil equivalent (MBOE) to more than 1 million barrels oil equivalent (MMBOE) for Wolfcamp B interval wells in Midland, Martin, Glasscock and Andrews counties,

• 800 MBOE to more than 1 MMBOE for Wolfcamp A interval wells in Midland and Glasscock counties,

• 650 MBOE to more than 800 MBOE for Wolfcamp D interval wells in Midland, Martin, Glasscock and Andrews counties, and

• 650 MBOE to 1 MMBOE for Lower Spraberry Shale interval wells in Midland, Martin, Glasscock and Andrews counties.

Of the 65 horizontal Wolfcamp A, B and D wells and Lower Spraberry Shale wells that have been placed on production across Pioneer’s northern Spraberry/Wolfcamp acreage since the beginning of 2013, 33 wells were placed on production during the third quarter of 2014. Examples of the strongest initial performance (IP) results from these third-quarter wells include:

Well Name	Interval	24-hour IP Rate	Oil %	Lateral Length
DL Hutt C #36H	Wolfcamp B	1,646 BOEPD	67%	7,289’
Mabee K #5H	Wolfcamp B	1,555 BOEPD	81%	9,056’
E.T. O’Daniel #6H	Wolfcamp B	1,545 BOEPD	75%	8,559’
E.T. O’Daniel #5H	Wolfcamp A	1,922 BOEPD	79%	8,342’
E.T. O’Daniel #3H	Wolfcamp A	1,903 BOEPD	77%	9,466’
Flanagan 14 Lloyd A #4H	Wolfcamp A	1,231 BOEPD	80%	6,529’
Hutt E #3212H	Wolfcamp A	976 BOEPD	79%	4,502’
DL Hutt C #34H	Wolfcamp D	1,848 BOEPD	68%	7,383’
Houston Ranch 12 Fowler A 1H	Wolfcamp D	1,755 BOEPD	74%	6,149’
DL Hutt C #37H	Wolfcamp D	1,273 BOEPD	67%	7,382’
SSU #3002H	Lower Spraberry Shale	687 BOEPD	78%	4,982’
SSU #3001H	Lower Spraberry Shale	597 BOEPD	77%	4,874’

Additionally, Pioneer is continuing to successfully appraise the Jo Mill Shale and Middle Spraberry Shale intervals. Early production from a Jo Mill Shale well drilled in Upton County (Pembrook #1401H with a 5,106-foot lateral) and a Middle Spraberry Shale well drilled in Upton County (Pembrook #1402H with a 4,982-foot lateral) during the third quarter are tracking the performance of Pioneer’s best Jo Mill Shale interval and Middle Spraberry Shale interval wells placed on production earlier this year in Martin and Midland counties, respectively. The Jo Mill Shale interval wells are tracking an 800 MBOE type curve on average, while the Middle Spraberry Shale wells are tracking a 700 MBOE type curve on average. Pioneer plans to continue to appraise both of these intervals, although activity may be deferred in a low oil price environment.

Pioneer has been transitioning from a horizontal appraisal program in 2013 to a horizontal development program across its northern acreage during 2014. The Company increased its horizontal rig count in the northern Spraberry/Wolfcamp area from five rigs at year-end 2013 to 16 rigs in early 2014 and expects to place approximately 100 wells on production during 2014 in this area. Approximately 80% of these wells are expected to be Wolfcamp A, B and D interval wells. The remaining 20% will be Spraberry Shale wells (Lower Spraberry Shale, Jo Mill Shale and Middle Spraberry Shale). Three-well pads are being utilized to drill most of the wells in the 2014 program. The Company has recently initiated completion optimization testing in Midland and Martin counties, which includes increasing proppant concentration per lateral foot, increasing clusters per stage and reducing fluid volume. The Company expects results from this testing to be available later next year.

Pioneer also expects to place approximately 100 wells on production in the southern Wolfcamp joint venture area during 2014. Two-well and three-well pads are being utilized to drill essentially all of the wells in the 2014 program. During the third quarter, more efficient drilling and completion operations resulted in

an eight-day reduction in the time it took to place three-well pads on production. The 2014 drilling program is focused on the higher-return areas in northern Upton and Reagan counties, with approximately two-thirds of the wells being completed in the Wolfcamp B interval and the remainder being a mix of Wolfcamp A, C and D interval wells.

During the first nine months of 2014, Pioneer operated an average of 11 vertical rigs to meet continuous drilling obligations and drill water disposal wells in the Spraberry/Wolfcamp. The Company expects to reduce the vertical rig count to six rigs during the fourth quarter, which will allow it to allocate more of its capital to higher rate-of-return horizontal drilling. Pioneer expects to place more than 200 vertical wells on production during 2014. Approximately 90% of the vertical wells in the 2014 drilling program are expected to be completed in the deeper Strawn and Atoka intervals.

Pioneer’s third quarter production from the Spraberry/Wolfcamp (northern acreage and southern Wolfcamp joint venture area combined) averaged 103 MBOEPD. Of this volume, 37 MBOEPD was produced from horizontal wells and 66 MBOEPD was produced from vertical wells. Seventy-three horizontal wells were placed on production during the third quarter, of which 33 wells were in the northern portion of Pioneer’s acreage and 40 wells were in the southern Wolfcamp joint venture area. The 73 wells placed on production in the third quarter were more than the Company’s earlier estimate of 58 wells for the quarter primarily due to several wells being accelerated from the fourth quarter to the latter part of the third quarter. These additional wells primarily reflect improved drilling and completion times in the southern Wolfcamp joint venture area. Pioneer also placed 59 vertical wells on production during the third quarter.

Third quarter production increased by 11 MBOEPD compared to the second quarter, as horizontal production growth of 15 MBOEPD more than offset declines in vertical production of 4 MBOEPD. Oil production was up 9 MBOEPD from the second quarter to the third quarter.

Spraberry/Wolfcamp production is forecasted to be 98 MBOEPD to 100 MBOEPD in 2014, an increase of 25% to 27% compared to 2013 (narrowed from the Company’s earlier range of 96 MBOEPD to 100 MBOEPD). This growth is second-half weighted, primarily as a result of adding 11 horizontal rigs early in the year on Pioneer’s northern acreage and moving to three-well pad drilling. The total number of horizontal wells placed on production in the Spraberry/Wolfcamp is expected to more than double in the second half of 2014 compared to the first half of the year.

Spraberry/Wolfcamp Infrastructure Plans

Pioneer’s long-term growth plan is focused on optimizing the development of the field and identifying the future requirements for water, field infrastructure, gas processing, sand, pipeline takeaway, oilfield services, tubulars, electricity, systems, buildings and roads. Pioneer plans to continue construction of front-end loaded infrastructure, which is expected to provide significant future cost savings and support Pioneer’s long-term growth plan in the Spraberry/Wolfcamp. This infrastructure includes a field-wide water distribution network, continued build-out of horizontal tank batteries, additional gas processing facilities and expansion of the Brady sand mine.

As part of its long-term development plan for the Spraberry/Wolfcamp, Pioneer’s objective is to reduce its reliance on fresh water used in drilling and fracture stimulation operations and mitigate the need for the disposal of produced water through recycling, while also reducing its cost for water acquisition and transportation. Alternative sources of water supply include effluent water, brackish water wells drilled by Pioneer (e.g. Santa Rosa aquifer), brackish water acquired from third-party sources and recycled produced water. Pioneer has agreed to purchase approximately 120 thousand barrels per day of effluent water from City of Odessa beginning in the second half of 2015 and is finalizing an agreement with City of Midland to purchase approximately 240 thousand barrels per day of effluent water beginning in the second half of 2017.

Current plans reflect the construction of a field-wide distribution system to transport water by pipeline directly from these alternative sources to frac ponds near planned drilling locations to improve efficiency and reduce costs associated with trucking water. This distribution system is expected to include (i) a 100-mile mainline (30-inch to 36-inch diameter pipeline) stretching across the field, (ii) feeder lines from the Odessa and Midland effluent water plants, (iii) up to 20 subsystems to deliver water to planned drilling locations, (iv) 125 to 150 frac ponds to store water near planned drilling locations, and (v) fiber optic lines to improve communication and data management across the field. Flexibility exists to defer the build-out of subsystems and frac ponds in a lower commodity price environment. The cost to construct the entire system is estimated at $800 million to $1 billion over the next four to five years.

The water distribution system is expected to be completed in phases that are coordinated with the timing of connecting new water sources and future drilling programs. The initial phase includes the 100-mile mainline and the feeder lines from the Odessa and Midland effluent water plants. Subsystems and frac ponds will be built in the initial phase in areas where significant drilling is planned, with other subsystems and frac ponds being developed over time as drilling expands across the field. A total of approximately $500 million to $700 million is expected to be spent in 2015 and 2016 for the initial phase.

Pioneer estimates that it will save approximately $500 thousand per well by constructing the field-wide water distribution system. This savings results primarily from utilizing less-expensive water sources, eliminating higher-cost trucking of water, allowing centralized water recycling and providing lower infrastructure costs. Overall, this project should ensure both the availability and deliverability of a low-cost, long-term water supply across Pioneer’s acreage position and allow for centralized recycling.

New large-scale tank batteries and saltwater disposal facilities are being constructed to handle the higher volumes that are produced from horizontal wells, which results in front-end loaded capital spending. Pioneer’s 2014 capital program included approximately $250 million for the construction of these facilities. An additional $600 million is expected to be required for new facilities over the next two years. The cost of future wells will benefit from the front-end spending for this facility infrastructure.

The 2014 capital program also included approximately $100 million for Pioneer’s 27% share of Atlas Pipeline Partners, L.P.’s (Atlas) new Edward gas processing plant (200 MMCFPD) and 30% share of West Texas Gas’ new Sale Ranch gas processing plant (200 MMCFPD). The Company expects to spend an additional $175 million over the next two years for two additional gas processing plants and associated gathering system investments. The first of these will be a new 200 MMCFPD plant built by Atlas in Martin County during the fourth quarter of 2015, followed potentially by another new 200 MMCFPD plant in 2016.

Pioneer’s future proppant requirements for fracture stimulation operations are expected to increase as the Company’s drilling program in the Spraberry/Wolfcamp ramps up. The Company’s sand mine in Brady, Texas, is strategically located within close proximity to the Midland Basin (190 miles) and is the primary source of proppant for its Spraberry/Wolfcamp operations. Production at the mine is approaching total capacity of 750 thousand tons per year. As a result, the Company plans to expand the mine in 2015 to enable it to produce 2.1 million tons per year. The cost of this expansion is expected to be approximately $125 million in 2015 and will include additional sand storage and pre-investment in facilities for a future expansion. Proved and probable reserves at the Brady facility total 68 million tons.

Eagle Ford Shale Operations Update

In the liquids-rich area of the Eagle Ford Shale play in South Texas, Pioneer continues to expect to place approximately 125 horizontal wells on production in 2014. Of this total, approximately 50 wells will be in Upper targets as part of the Company’s downspacing and staggering program in the Lower and Upper Eagle Ford Shale. Wells are being downspaced from 500 feet to a range of 175 feet to 300 feet between staggered wells.

Thirty-five wells were placed on production in Upper targets during the first nine months of 2014 as part of the downspacing and staggering program, of which 18 wells were added in the third quarter. Early production results from these wells are similar to offset Lower Eagle Ford Shale wells. Approximately 25% of Pioneer’s acreage is expected to be prospective for the Upper Eagle Ford Shale.

The Company is now utilizing a two-string casing design instead of a three-string casing design in most of its wells in the liquids-rich area of the Eagle Ford Shale play. This change is lowering drilling costs by $750 thousand to $1 million per well, primarily as a result of reducing drilling days and casing costs on each well.

Pioneer has continued to improve its Eagle Ford Shale completion design by increasing the pounds of white sand proppant pumped per foot, increasing the barrels of fracture stimulation fluid pumped per minute in each cluster, reducing cluster spacing and utilizing combinations of the above. This optimization program is increasing EURs by 20% to 30%, which more than offsets the increase in drilling and completion capital.

Pioneer’s third quarter production from the Eagle Ford Shale averaged a record 47 MBOEPD. Thirty-five wells were placed on production during the third quarter. For 2014, the Company expects to place approximately 125 liquids-rich wells on production in the Eagle Ford Shale. Most of these wells will be drilled utilizing three-well and four-well pads. The 2014 program reflects longer lateral lengths and larger fracture stimulations compared to 2013. Full-year production is forecasted to range from 46 MBOEPD to 47 MBOEPD, an increase of 24% to 26%, compared to 2013 (narrowed from the Company’s earlier range of 46 MBOEPD to 49 MBOEPD).

Optimizing Returns In a Lower Price Environment

Pioneer is identifying and implementing a number of optimization and cost reduction initiatives to address the recent decline in oil prices. The Company will focus its horizontal drilling activity in the Spraberry/Wolfcamp on the best intervals. These intervals include the Wolfcamp B, Wolfcamp A and Lower Spraberry Shale where EURs are expected to be 800 MBOE to 1 MMBOE. Further appraisal of other intervals, including the Middle Spraberry Shale and Jo Mill Shale, may be deferred. Field-wide completion optimization testing will continue while other “science” activities will be limited.

2014 Capital Budget

Pioneer’s capital program for 2014 is forecasted at $3.4 billion (excludes acquisitions, asset retirement obligations, capitalized interest, geological and geophysical G&A and capital expenditures associated with the Alaska and Barnett Shale assets prior to their sale). It includes $3.1 billion for drilling and $0.3 billion for vertical integration and the construction of new field and office buildings.

The 2014 capital budget is expected to be funded from forecasted operating cash flow of $2.4 billion, proceeds from asset divestitures and cash on hand of $550 million as of September 30, 2014.

Pioneer’s net debt at the end of the third quarter was $2.1 billion, with net debt-to-book capitalization of 23%. The Company will continue to target a net debt-to-book capitalization below 35% and net debt-to-operating cash flow below 1.5.

Third Quarter 2014 Financial Review

Sales volumes from continuing operations for the third quarter of 2014 averaged 186 MBOEPD (excludes Barnett Shale and Hugoton production, which is reflected in discontinued operations). Oil sales averaged 89 thousand barrels per day (MBPD), natural gas liquids (NGLs) sales averaged 40 MBPD and gas sales averaged 344 MMCFPD.

The average realized price for oil was $90.82 per barrel. The average realized price for NGLs was $28.44 per barrel, and the average realized price for gas was $3.79 per MCF. These prices exclude the effects of derivatives.

Production costs from continuing operations averaged $13.17 per barrel oil equivalent (BOE). Depreciation, depletion and amortization (DD&A) expense averaged $16.03 per BOE. Exploration and abandonment costs were $22 million, principally comprised of $5 million for seismic data and $16 million for personnel costs. General and administrative expense totaled $81 million. Interest expense was $46 million and other expense was $20 million.

Fourth Quarter 2014 Financial Outlook

The Company’s fourth quarter 2014 outlook for certain operating and financial items is provided below.

Production is forecasted to average 200 MBOEPD to 205 MBOEPD.

Production costs are expected to average $13.25 per BOE to $15.25 per BOE. DD&A expense is expected to average $15.00 per BOE to $17.00 per BOE. Total exploration and abandonment expense is forecasted to be $25 million to $35 million.

General and administrative expense is expected to be $80 million to $85 million, interest expense is expected to be $46 million to $51 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.

The Company’s effective income tax rate is expected to range from 35% to 40%. Current income taxes are expected to be $1 million to $5 million and are primarily attributable to state taxes.

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

Earnings Conference Call

On Wednesday, November 5, 2014, at 9:00 a.m. Central Time, Pioneer will discuss its financial and operating results for the quarter ended September 30, 2014, 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) 967-7135 and confirmation code: 2596808 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, 2014, by dialing (888) 203-1112 and confirmation code: 2596808.

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, completion of planned divestitures, litigation, the costs and results of drilling and operations, availability of equipment, services, resources and personnel required to perform the Company's drilling and 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 Securities and Exchange Commission. In addition, Pioneer may be subject to currently unforeseen risks that may have a materially adverse impact on it. Pioneer undertakes no duty to publicly update these statements except as required by law.

Cautionary Note to U.S. Investors --The 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,” “net recoverable resource potential,” “estimated ultimate recovery,” “EUR,” “oil-in-place” 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. In addition, the SEC permits U.S. companies with mining operations, in their filings with the SEC, to disclose only “reserves,” which are mineral deposits that a company can economically and legally extract or produce. The SEC normally only permits users to report mineralization that does not constitute reserves as in-place tonnage and grade without reference to unit measures. U.S. investors are cautioned not to assume that Pioneer’s estimates of resource potential of mineral deposits reflect economically recoverable quantities. Any inaccuracy in our estimates related to our mineral reserves and non-reserve mineral deposits could result in lower than expected sales and higher than expected costs. 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

Michael Bandy - 972-969-4513

Steven Cobb - 972-969-5679

Media and Public Affairs

Tadd Owens - 972-969-5760

Suzanne Hicks - 972-969-4020

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions)

	September 30, 2014			December 31, 2013
ASSETS
Current assets:
Cash and cash equivalents	$	550		$	393
Accounts receivable, net	490			434
Income taxes receivable	22			5
Inventories	237			220
Prepaid expenses	23			16
Deferred income taxes	2			—
Assets held for sale	—			584
Derivatives	128			76
Other current assets, net	39			2
Total current assets	1,491			1,730
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting	15,010			13,529
Accumulated depletion, depreciation and amortization	(5,183		)	(4,903		)
Total property, plant and equipment	9,827			8,626
Goodwill	272			274
Other property and equipment, net	1,303			1,224
Investment in unconsolidated affiliate	221			225
Derivatives	57			91
Other assets, net	101			124
	$	13,272		$	12,294
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	1,330		$	1,060
Interest payable	36			62
Income taxes payable	1			—
Deferred income taxes	—			19
Liabilities held for sale	—			39
Derivatives	1			12
Other current liabilities	71			58
Total current liabilities	1,439			1,250
Long-term debt	2,662			2,653
Derivatives	—			10
Deferred income taxes	1,734			1,473
Other liabilities	284			293
Equity	7,153			6,615
	$	13,272		$	12,294

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per share data)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Revenues and other income:
Oil and gas	$	967		$	820		$	2,795		$	2,296
Sales of purchased oil and gas	202			82			554			194
Interest and other	2			8			9			3
Derivative gains (losses), net	341			(102		)	19			—
Gain (loss) on disposition of assets, net	1			(1		)	11			206
	1,513			807			3,388			2,699
Costs and expenses:
Oil and gas production	168			150			493			440
Production and ad valorem taxes	58			49			169			147
Depletion, depreciation and amortization	274			222			734			650
Purchased oil and gas	194			85			535			196
Exploration and abandonments	22			30			80			65
General and administrative	81			72			244			200
Accretion of discount on asset retirement obligations	3			3			9			9
Interest	46			45			138			139
Other	20			24			55			65
	866			680			2,457			1,911
Income from continuing operations before income taxes	647			127			931			788
Income tax provision	(236		)	(48		)	(319		)	(281		)
Income from continuing operations	411			79			612			507
Income (loss) from discontinued operations, net of tax	(37		)	19			(113		)	52
Net income	374			98			499			559
Net income attributable to noncontrolling interests	—			(7		)	—			(30		)
Net income attributable to common stockholders	$	374		$	91		$	499		$	529
Basic earnings per share attributable to common stockholders:
Income from continuing operations	$	2.84		$	0.51		$	4.24		$	3.49
Income (loss) from discontinued operations	(0.26		)	0.14			(0.79		)	0.38
Net income	$	2.58		$	0.65		$	3.45		$	3.87
Diluted earnings per share attributable to common stockholders:
Income from continuing operations	$	2.84		$	0.51		$	4.23		$	3.44
Income (loss) from discontinued operations	(0.26		)	0.14			(0.79		)	0.38
Net income	$	2.58		$	0.65		$	3.44		$	3.82
Weighted average shares outstanding:
Basic	143			139			143			135
Diluted	143			139			143			137

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Cash flows from operating activities:
Net income	$	374		$	99		$	499		$	559
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization	274			222			734			650
Impairment of inventory and other property and equipment	3			4			7			8
Exploration expenses, including dry holes	1			8			11			10
Deferred income taxes	250			57			315			276
(Gain) loss on disposition of assets, net	(1		)	1			(11		)	(206		)
Accretion of discount on asset retirement obligations	3			3			9			9
Discontinued operations	68			44			247			114
Interest expense	4			4			13			13
Derivative related activity	(337		)	137			(39		)	122
Amortization of stock-based compensation	20			19			63			53
Other	16			(1		)	42			(8		)
Change in operating assets and liabilities:
Accounts receivable, net	(18		)	(56		)	(77		)	(89		)
Income taxes receivable	(15		)	(9		)	(17		)	(3		)
Inventories	(19		)	(27		)	(27		)	(28		)
Prepaid expenses	(13		)	3			(11		)	(7		)
Other current assets	3			(1		)	(1		)	2
Accounts payable	66			194			96			184
Interest payable	(26		)	(25		)	(26		)	(32		)
Income taxes payable	—			(1		)	1			—
Other current liabilities	(37		)	(7		)	(30		)	(22		)
Net cash provided by operating activities	616			668			1,798			1,605
Net cash used in investing activities	(525		)	(648		)	(1,628		)	(1,462		)
Net cash provided by (used in) financing activities	14			28			(13		)	372
Net increase in cash and cash equivalents	105			48			157			515
Cash and cash equivalents, beginning of period	445			696			393			229
Cash and cash equivalents, end of period	$	550		$	744		$	550		$	744

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUMMARY PRODUCTION AND PRICE DATA

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Average Daily Sales Volumes from Continuing Operations:
Oil (Bbls)	88,973		67,674		82,485		68,650
Natural gas liquids ("NGL") (Bbls)	39,819		31,507		37,319		29,268
Gas (Mcf)	343,711		320,938		336,749		334,876
Total (BOE)	186,077		152,671		175,929		153,730
Average Realized Prices from Continuing Operations:
Oil (per Bbl)	$	90.82	$	101.70	$	92.94	$	93.24
NGL (per Bbl)	$	28.44	$	30.87	$	30.36	$	29.92
Gas (per Mcf)	$	3.79	$	3.30	$	4.28	$	3.39
Total (BOE)	$	56.51	$	58.39	$	58.20	$	54.71

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. 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, if any, (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 and diluted net income attributable to common stockholders for the three and nine months ended September 30, 2014 and 2013:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(in millions)
Net income attributable to common stockholders	$	374		$	91		$	499		$	529
Participating basic earnings	(4		)	(1		)	(5		)	(7		)
Basic and diluted net income attributable to common stockholders	$	370		$	90		$	494		$	522

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, 2014 and 2013:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2014	2013	2014	2013
	(in millions)
Weighted average common shares outstanding:
Basic	143	139	143	135
Convertible senior notes dilution	—	—	—	2
Diluted (a)	143	139	143	137

_______________

(a) The Company excluded 33,591 shares and 11,197 shares attributable to unvested performance units from the diluted income per share calculations for the three and nine months ended September 30, 2014, respectively, because they would have been anti-dilutive to the calculation. Options to purchase 38,842 shares of the Company's common stock were excluded from the diluted income per share calculations for the three and nine months ended September 30, 2013 because they would have been anti-dilutive to the calculation.

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES

(in millions)

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,
	2014			2013			2014			2013
Net income	$	374		$	98		$	499		$	559
Depletion, depreciation and amortization	274			222			734			650
Exploration and abandonments	22			30			80			65
Impairment of inventory and other property and equipment	3			4			7			8
Accretion of discount on asset retirement obligations	3			3			9			9
Interest expense	46			45			138			139
Income tax provision	236			48			319			281
(Gain) loss on disposition of assets, net	(1		)	1			(11		)	(206		)
(Income) loss from discontinued operations, net of tax	37			(19		)	113			(52		)
Derivative related activity	(337		)	137			(39		)	122
Amortization of stock-based compensation	20			19			63			53
Other	16			(1		)	42			(8		)
EBITDAX (a)	693			587			1,954			1,620
Cash interest expense	(42		)	(41		)	(125		)	(126		)
Current income tax (provision) benefit	14			9			(4		)	(5		)
Discretionary cash flow (b)	665			555			1,825			1,489
Discontinued operations cash activity	31			63			134			166
Cash exploration expense	(21		)	(22		)	(69		)	(55		)
Changes in operating assets and liabilities	(59		)	72			(92		)	5
Net cash provided by operating activities	$	616		$	668		$	1,798		$	1,605

_______________

(a)

“EBITDAX” represents earnings before depletion, depreciation and amortization expense; exploration and abandonments; impairment of inventory and other property and equipment; accretion of discount on asset retirement obligations; interest expense; income taxes; net (gain) loss on the disposition of assets; (income) loss from discontinued operations, net of tax; noncash derivative related activity; amortization of stock-based compensation and other 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.

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES (continued)

(in millions, except per share data)

Net income adjusted for noncash mark-to-market ("MTM") derivative gains, and adjusted income excluding MTM derivative gains and unusual items, as presented in this press release, are presented and reconciled to Pioneer's net income attributable to common stockholders (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. Noncash 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, 2014, as determined in accordance with GAAP, to income adjusted for noncash MTM derivative gains and adjusted income excluding noncash MTM derivative gains and unusual items for that quarter.

	After-tax Amounts			Amounts Per Share
Net income attributable to common stockholders	$	374		$	2.58
Noncash MTM derivative gains	(216		)	(1.49		)
Income adjusted for noncash MTM derivative gains	158			1.09
Loss associated with discontinued operations (a)	37			0.26
Adjusted income excluding noncash MTM derivative gains and unusual items	$	195		$	1.35

_______________

(a) Represents (i) third quarter results of operations for the Hugoton, Barnett Shale and Alaska assets, (ii) fair value adjustments to reduce the carrying value of the Barnett Shale and Hugoton assets to their sales price, and (iii) miscellaneous adjustments related to accounting for the final sale of the Barnett Shale and Hugoton assets.

PIONEER NATURAL RESOURCES COMPANY

SUPPLEMENTAL INFORMATION

Open Commodity Derivative Positions as of October 30, 2014

(Volumes are average daily amounts)

	Three Months Ending December 31,			Year Ending December 31,
	2014			2015			2016
Average Daily Oil Production Associated with Derivatives (Bbl):
Collar contracts with short puts:
Volume (a)	69,000			95,767			70,000
NYMEX price:
Ceiling	$	114.05		$	99.36		$	96.86
Floor	$	93.70		$	87.98		$	85.62
Short put	$	77.61		$	73.54		$	74.45
Swap contracts:
Volume	15,000			—			—
NYMEX price	$	96.31		$	—		$	—
Rollfactor swap contracts:
Volume	6,630			17,000			—
NYMEX roll price (b)	$	1.10		$	0.28		$	—
Average Daily NGL Production Associated with Derivatives (Bbl):
Natural gasoline collar contracts with short puts (c):
Volume	3,500			—			—
Index price:
Ceiling	$	97.93		$	—		$	—
Floor	$	90.14		$	—		$	—
Short put	$	81.36		$	—		$	—
Ethane collar contracts (c):
Volume	3,000			—			—
Index price:
Ceiling	$	13.72		$	—		$	—
Floor	$	10.78		$	—		$	—
Ethane swap contracts (c):
Volume	—			—			4,000
Index price	$	—		$	—		$	12.29
Propane swap contracts (c):
Volume	1,674			—			—
Index price	$	47.95		$	—		$	—
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
Swap contracts:
Volume	195,000			20,000			70,000
NYMEX price	$	4.04		$	4.31		$	4.06
Basis swap contracts:
Mid-Continent index swap volume (d)	120,000			95,000			—
Price differential ($/MMBtu)	$	(0.22	)	$	(0.24	)	$	—
Permian Basin index swap volume (d)	10,000			10,000			—
Price differential ($/MMBtu)	$	(0.15	)	$	(0.13	)	$	—
Permian Basin index swap volume (e)	16,630			—			—
Price differential ($/MMBtu)	0.34			—			—

_______________

(a)	Counterparties have the option to extend 5,000 BBLs per day of 2015 collar contracts with short puts for an additional year with a ceiling price of $100.08 per BBL, a floor price of $90.00 per BBL and a short put price of $80.00 per BBL. The option to extend is exercisable by the counterparties on December 31, 2015.
(b)	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.
(c)	Represent derivative contracts that reduce the price volatility of forecasted natural gasoline, ethane and propane sales by the Company at Mont Belvieu, Texas-posted prices.
(d)	Represent swaps that fix the basis differentials between the index prices at which the Company sells its Mid-Continent and Permian Basin gas, respectively, and the NYMEX Henry Hub index price used in gas swap and collar contracts.
(e)	Represent swaps that fix the basis differentials between Permian Basin index prices and southern California index prices for Permian Basin gas forecasted for sale in southern California.

Interest rate derivatives. Subsequent to September 30, 2014, the Company entered into interest rate derivative contracts that expire on June 30, 2015 for a notional amount of $200 million. The Company will pay an average fixed rate of 2.43 percent in exchange for receiving the 10-year Treasury rate as of the expiration date.

Marketing and basis transfer derivatives. Periodically, the Company enters into buy and sell marketing arrangements to fulfill firm pipeline transportation commitments. Associated with these marketing arrangements, the Company may enter into index swaps to mitigate price risk. As of October 30, 2014, the Company had (i) marketing gas index swap contracts for 40,000 MMBTU per day for the remainder of 2014 with a price differential of $0.31 per MMBTU between Permian Basin index prices and southern California index prices and (ii) marketing oil index swap contracts for 10,000 BBL per day for the remainder of 2014 with a price differential of $2.81 per BBL between Cushing WTI and Louisiana Light Sweet crude ("LLS") and 10,000 BBL per day for 2015 with a price differential of $2.99 per BBL between Cushing WTI and LLS.

Derivative Gains, Net

(in millions)

The following table summarizes net derivative gains and losses that the Company has recorded in earnings for the three and nine months ended September 30, 2014:

	Three Months Ended September 30, 2014		Nine Months Ended September 30, 2014
Noncash changes in fair value:
Oil derivative gains	$	307	$	28
NGL derivative gains	2		1
Gas derivative gains	29		10
Total noncash derivative gains, net	338		39
Net cash receipts (payments) on settled derivative instruments:
Oil derivative receipts (payments)	1		(13		)
NGL derivative receipts	2		3
Gas derivative payments	—		(29		)
Marketing derivative receipts	—		1
Interest rate derivative receipts	—		18
Total cash derivative receipts (payments), net	3		(20		)
Total derivative gains, net	$	341	$	19