Exhibit 99.1

News Release

Pioneer Natural Resources Company Reports Third Quarter 2017

Financial and Operating Results

Dallas, Texas, November 1, 2017 - Pioneer Natural Resources Company (NYSE:PXD) (“Pioneer” or “the Company”) today reported financial and operating results for the quarter ended September 30, 2017.

Pioneer reported a third quarter net loss attributable to common stockholders of $23 million, or $0.13 per diluted share. Without the effect of noncash mark-to-market derivative losses of $103 million after tax, or $0.61 per diluted share, adjusted results for the third quarter were earnings of $80 million after tax, or $0.48 per diluted share.

Third quarter financial, production and other recent highlights included:

• producing 276 thousand barrels oil equivalent per day (MBOEPD), an increase of 17 MBOEPD, or 6%, compared to the second quarter of 2017; third quarter production was negatively impacted by 3,500 barrels oil equivalent per day (BOEPD) due to Hurricane Harvey and unplanned downtime at a third-party gas processing facility; production would have been at the top end of Pioneer’s third quarter guidance range of 274 MBOEPD to 279 MBOEPD without these negative impacts; third quarter production growth was driven by the Company’s Spraberry/Wolfcamp horizontal drilling program;

• producing 162 thousand barrels per day (MBPD) of oil, an increase of 15 MBPD, or 10%, compared to the second quarter of 2017;

• increasing Spraberry/Wolfcamp horizontal production by 22 MBOEPD, or 13%, compared to the second quarter of 2017; horizontal oil production increased by 17 MBPD, or 15% quarter over quarter; internal rates of return (IRRs) from the Spraberry/Wolfcamp drilling program continue to be strong;

• reducing production costs (excluding taxes) to $6.01 per barrel oil equivalent (BOE) compared to $6.19 per BOE in the second quarter of 2017 and $6.79 per BOE in 2016; third quarter production costs benefited from continuing low horizontal Spraberry/Wolfcamp production costs of $1.85 per BOE (excluding taxes);

• adding 2018 derivatives for 59 MBPD of oil and 83 million cubic feet per day (MMCFPD) of gas; Pioneer’s 2018 derivative positions now cover more than 80% of forecasted oil production and more than 35% of forecasted gas production;

• continuing to maintain a strong balance sheet with cash on hand at the end of the third quarter of $2.1 billion (includes liquid investments); net debt to forecasted 2017 operating cash flow was 0.3 times at the end of the third quarter and net debt-to-book capitalization was 5%; and

• exporting 1.4 million barrels of Pioneer’s Midland Basin oil production during the third quarter and expecting to export over 2.3 million barrels during the fourth quarter; customers are located in Asia and Europe.

Pioneer’s third quarter drilling update and other recent operations activity included:

• adding two rigs recently in the Spraberry/Wolfcamp to improve operational flexibility by increasing Pioneer’s inventory of wells that have been drilled and are awaiting completion (DUCs); once an

adequate DUC inventory is built in the second half of 2018, the Company expects to use these two rigs to achieve longer-term production growth targets, which is consistent with the Company’s previously discussed plans to add drilling rigs in the second half of 2018; the Company is now operating 20 rigs in the Spraberry/Wolfcamp, with 16 of these rigs in the northern area and 4 rigs in the southern Wolfcamp joint venture area where Pioneer holds a working interest of 60%; the 2017 capital budget is being increased by $50 million, primarily to reflect the capital associated with the two additional Spraberry/Wolfcamp rigs and higher than anticipated completion costs in the Eagle Ford Shale;

• utilizing four-string casing design successfully in areas of the Spraberry/Wolfcamp where this design is necessary;

• placing 61 horizontal wells on production in the Spraberry/Wolfcamp during the third quarter; 59 wells were Version 3.0 completions that continue to outperform Version 2.0 completions; two wells were completed in the Jo Mill interval; early production results from both Jo Mill wells continue to support the successful appraisal of this interval;

• continuing to see encouraging results from the 12 Spraberry/Wolfcamp wells that were placed on production in the second quarter of 2017 with higher intensity completions (referred to as Version 3.0+ completions);

• expecting to place approximately 70 wells on production in the Spraberry/Wolfcamp during the fourth quarter of 2017, resulting in approximately 230 wells being placed on production during 2017; IRRs for this year’s Spraberry/Wolfcamp drilling program are expected to range from 40% to 75% assuming an oil price of $50 per barrel and a gas price of $3 per thousand cubic feet (MCF);

• drilling and completing 11 new wells and completing nine DUC wells in the Eagle Ford Shale during 2017 (Pioneer has a 46% working interest); the objective of this limited new well drilling program is to test longer laterals with wider spacing and higher intensity completions; IRRs on this year’s drilling program are expected to range from 30% to 40% assuming an oil price of $50 per barrel and a gas price of $3 per MCF; two new drills and nine DUCs were placed on production in the Eagle Ford Shale during the second and third quarters; the average cumulative production per well from the new drills and DUCs after approximately 80 days and 140 days of production, respectively, is more than double the average cumulative production per well for the same time period from all wells placed on production during 2015 and 2016; two additional new drills were placed on production in early October; and

• resuming production (approximately 8 MBOEPD) in the West Panhandle field in late October after volumes were temporarily shut in due to a fire at a third-party gas processing facility in mid-September; downtime from the fire impacted third quarter production by approximately 1,300 BOEPD.

President and CEO Timothy L. Dove stated, “The Company delivered another excellent quarter, with solid earnings, significant oil production growth, strong horizontal well performance in the Spraberry/Wolfcamp and reduced production costs. Our world-class Spraberry/Wolfcamp asset is located in the Midland Basin, considered by many to be the top oil shale play in North America. We are drilling low-cost, highly productive wells that generate high returns and have industry-leading breakeven oil prices.”

“Despite the drilling delays that we experienced in the second quarter, our operations are back on track and we remain committed to our 10-year plan of drilling high-return wells that will deliver organic compound annual production growth of 15%+. Achieving this target will result in oil production of approximately 700 MBPD in 2026 and total production greater than 1 million barrels oil equivalent per day. This plan will allow us to maintain a steady pace of activity, spend within cash flow by 2020 at an oil price of $50 per barrel, maintain a strong balance sheet and improve corporate returns.”

Spraberry/Wolfcamp Operations Update and Outlook

Pioneer is the largest acreage holder in the Spraberry/Wolfcamp, with approximately 600,000 gross acres in the northern portion of the play and approximately 200,000 gross acres in the southern Wolfcamp joint

venture area. Pioneer’s contiguous acreage position and substantial resource potential allow for decades of drilling horizontal wells with lateral lengths ranging from 7,500 feet to 14,000 feet.

The Company implemented a completion optimization program during 2015 in the Spraberry/Wolfcamp that combines longer laterals with optimized stage lengths, clusters per stage, fluid volumes and proppant concentrations. The objective of the program is to improve well productivity by allowing more rock to be contacted closer to the horizontal wellbore. In 2013 and 2014, the Company’s initial fracture stimulation design (Version 1.0) consisted of proppant concentrations of 1,000 pounds per foot, fluid concentrations of 30 barrels per foot, cluster spacing of 60 feet and stage spacing of 240 feet. Beginning in mid-2015, the Company enhanced its fracture stimulation design (Version 2.0), which consisted of larger proppant concentrations of 1,400 pounds per foot, larger fluid concentrations of 36 barrels per foot, tighter cluster spacing of 30 feet and shorter stage spacing of 150 feet. Beginning in the first quarter of 2016, Pioneer commenced testing further-enhanced completion designs (Version 3.0), which included larger proppant concentrations up to 1,700 pounds per foot, larger fluid concentrations up to 50 barrels per foot, tighter cluster spacing down to 15 feet and shorter stage spacing down to 100 feet.

The Company placed 59 Version 3.0 wells on production in the third quarter. These wells and the more than 200 Version 3.0 wells that were placed on production prior to the third quarter of 2017 are continuing to outperform Version 2.0 completions.

Pioneer placed 12 wells on production during the second quarter that utilized higher intensity completions compared to Version 3.0 wells. These are referred to as Version 3.0+ completions. Nine of the Version 3.0+ wells utilized increased proppant and three utilized increased proppant and water compared to Version 3.0 wells. Early production results from all of these wells are outperforming nearby offset wells with less intense completions. The Company plans to test a minimum of three additional 3.0+ wells over the remainder of the year.

In addition to the 59 Version 3.0 wells that were placed on production during the third quarter, Pioneer placed two Jo Mill wells on production. Eleven wells have now been tested as part of the Jo Mill appraisal program since the fourth quarter of 2014. Performance from all of these wells is encouraging. The Jo Mill wells placed on production to date cover a large cross section of Pioneer’s acreage. The Company plans to drill additional Jo Mill wells during 2018. The cost of a Jo Mill well is approximately $7 million for a lateral length of 8,500 feet.

The budgeted costs to drill and complete Spraberry/Wolfcamp horizontal wells in 2017 are: Wolfcamp B - $8.8 million for a 10,000-foot lateral well; Wolfcamp A - $7.8 million for a 9,500-foot lateral well; and Lower Spraberry Shale - $7.5 million for a 9,500-foot lateral well. For the 2017 drilling program, the expected ultimate recoveries (EURs) by interval are: Wolfcamp B - 1.7 MMBOE, Wolfcamp A - 1.3 MMBOE and the Lower Spraberry Shale - 1.0 MMBOE.

Production costs (including production and ad valorem taxes) for Pioneer’s horizontal Spraberry/Wolfcamp wells are expected to continue to range from $4.00 per BOE to $5.00 per BOE.

The drilling program in the Spraberry/Wolfcamp is expected to deliver IRRs ranging from 40% to 75%, assuming Version 3.0 completions, an oil price of $50.00 per barrel and a gas price of $3.00 per MCF. These returns include tank battery and saltwater disposal facility costs.

The Company’s Spraberry/Wolfcamp horizontal drilling program continues to drive production growth, with Spraberry/Wolfcamp horizontal production growing by 22 MBOEPD, or 13%, in the third quarter of 2017 compared to the second quarter. Pioneer’s forecasted 2017 production growth rate for the Spraberry/Wolfcamp ranges from 30% to 32%. This reflects the Company placing approximately 230 wells on production in 2017. Of these wells, approximately 190 wells are expected to be in the northern area and 40 wells will be in the southern Wolfcamp joint venture area. Approximately 55% of the wells will be in the Wolfcamp B, 30% in the Wolfcamp A and 15% in the Lower Spraberry Shale.

In the fourth quarter, the Company expects to place approximately 70 wells on production, which are expected to be weighted evenly across the quarter.

Eagle Ford Shale Operations

In the liquids-rich area of the Eagle Ford Shale play in South Texas, Pioneer is completing a limited horizontal drilling and completion program during 2017 that is focused in Karnes, DeWitt and Live Oak counties. The program includes completing nine wells that were drilled in late 2015/early 2016 and drilling and completing 11 new wells.

The objective of this drilling and completion program is to test longer laterals with wider spacing and higher intensity completions in the new wells. Lateral lengths are being extended to 7,500 feet from the previous design of 5,200 feet, with cluster spacing being reduced from 50 feet to 30 feet. Proppant concentrations are being increased from 1,200 pounds per foot to 2,000 pounds per foot. The cost of drilling and completing the new wells is expected to be $9.6 million per well. The Company expects EURs averaging 1.3 MMBOE for the new wells with IRRs ranging from 30% to 40%, assuming an oil price of $50.00 per barrel and a gas price of $3.00 per MCF.

Drilling was completed on the 11 new wells during the second quarter. Two of these wells were placed on production during the third quarter. Of the remaining nine wells, two wells were placed on production in October and the remaining seven wells are expected to be placed on production in mid-November. The nine DUCs were placed on production during the second and third quarters. The average cumulative production per well from the new drills and DUCs after approximately 80 days and 140 days of production, respectively, is more than double the average cumulative production per well for the same time period from all wells placed on production during 2015 and 2016.

Pioneer’s production from the Eagle Ford Shale averaged 21 MBOEPD in the third quarter, of which 34% was condensate, 34% was NGLs and 32% was gas. The 2017 drilling program is expected to moderate the production decline Pioneer has experienced in the field since it stopped drilling operations in early 2016. The year-over-year decline is forecasted to be approximately 35%.

West Panhandle Operations

The West Panhandle field produced 4,500 BOEPD during the third quarter of 2017, reflecting the impact of multiple downtime events at the third-party gas processing plant where the liquids-rich gas from the field is processed into gas and NGLs.  Early in the third quarter, field production was shut in due to a planned turnaround at the third-party plant. In mid-September, the field had to be shut in again after the plant incurred significant damage due to a fire.  Repairs to the plant are underway, but it is expected to be several months before the plant can be placed back into service.  As a result, the third party and Pioneer have made modifications to their respective facilities to enable field production to resume, with the gas volumes being rerouted to another gas processing facility operated by the third party. Production from the field resumed in late October at approximately 8 MBOEPD. The impact to third quarter production from the unplanned downtime associated with the fire was approximately 1,300 BOEPD, with most of this loss being gas and NGLs. 

2017 Capital Program

The Company’s capital budget for 2017 is being increased from $2.7 billion to $2.75 billion (excluding acquisitions, asset retirement obligations, capitalized interest, geological and geophysical G&A and IT system upgrades). The increase reflects the recent decision to add two rigs in the Spraberry/Wolfcamp to improve operational flexibility by increasing Pioneer’s DUC inventory. Once an adequate DUC inventory is built in the second half of 2018, the Company expects to use these two rigs to achieve longer-term production growth targets, which is consistent with the Company’s previously discussed plans to add

drilling rigs in the second half of 2018 for this purpose. The increased capital spending also includes higher than anticipated completion costs in the Eagle Ford Shale.

The budget includes $2.475 billion for drilling and completion activities, including tank batteries/saltwater disposal facilities and gas processing facilities, and $275 million for water infrastructure, vertical integration and field facilities.

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

• Spraberry/Wolfcamp - $2.35 billion (includes $1.86 billion for the horizontal drilling and completion program, $265 million for tank batteries/saltwater disposal facilities, $115 million for gas processing facilities and $110 million for land, science and other expenditures);

• Eagle Ford Shale - $105 million (includes $75 million for the horizontal drilling and completion program and $30 million for compression, land and other expenditures); and

• Other assets - $20 million.

Capital spending for 2017 is expected to be funded from forecasted operating cash flow of $1.9 billion (assuming average estimated prices for 2017 of $49.50 per barrel for oil and $3.00 per MCF for gas) and cash on hand (including liquid investments).

Third Quarter 2017 Financial Review

Sales volumes for the third quarter of 2017 averaged 276 MBOEPD. Oil sales averaged 162 MBPD, NGL sales averaged 57 MBPD and gas sales averaged 340 MMCFPD.

The average realized price for oil was $45.35 per barrel. The average realized price for NGLs was $18.96 per barrel, and the average realized price for gas was $2.58 per MCF. These prices exclude the effects of derivatives.

Production costs, including taxes, averaged $8.11 per BOE. Depreciation, depletion and amortization (DD&A) expense averaged $14.01 per BOE. Exploration and abandonment costs were $18 million, including $3 million for seismic purchases and $15 million for personnel costs. General and administrative expense totaled $81 million. Interest expense was $37 million. Other expense was $58 million, including $45 million of charges associated with excess firm gathering and transportation commitments.

Fourth Quarter 2017 Financial Outlook

The Company’s fourth quarter 2017 outlook for certain operating and financial items is provided below.

Production is forecasted to average 292 MBOEPD to 302 MBOEPD.

Production costs are expected to average $7.50 per BOE to $9.50 per BOE. DD&A expense is expected to average $13.50 per BOE to $15.50 per BOE. Total exploration and abandonment expense is forecasted to be $20 million to $30 million.

General and administrative expense is expected to be $80 million to $85 million. Interest expense is expected to be $34 million to $39 million. Other expense is forecasted to be $60 million to $70 million and is expected to include $45 million to $55 million of charges associated with excess firm gathering and transportation commitments. Accretion of discount on asset retirement obligations is expected to be $4 million to $7 million.

The Company’s effective income tax rate is expected to range from 35% to 40%. Current income taxes are expected to be less than $5 million.

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

Earnings Conference Call

On Thursday, November 2, 2017, at 9:00 a.m. Central Time, Pioneer will discuss its financial and operating results for the quarter ended September 30, 2017, 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 (888) 539-3696 and confirmation code 3153325 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. This replay will be available through November 27, 2017. Click Here to register for the call-in audio replay, and you will receive the dial-in information.

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 www.pxd.com.

Except for historical information contained herein, the statements in this presentation 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, refining and export 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, investment instruments and derivative contracts and purchasers of Pioneer’s oil, natural gas liquid and gas production, uncertainties about estimates of reserves and resource potential, identification of drilling locations 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 Annual Report on Form 10-K for the year ended December 31, 2016, 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. Accordingly, no assurances can be given that the actual events and results will not be materially different than the anticipated results described in the forward-looking statements. 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 presentation, Pioneer includes estimates of quantities of oil and gas using certain terms, such as “resource potential,” “net recoverable resource potential,” “recoverable resource,” “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. 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 Company Contacts:

Investors

Frank Hopkins - 972-969-4065

Neal Shah - 972-969-3900

Trey Muir - 972-969-3674

Jerry Greer - 972-969-3597

Media and Public Affairs

Tadd Owens - 972-969-5760

Robert Bobo - 972-969-4020

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions)

	September 30, 2017			December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents	$	636		$	1,118
Short-term investments	1,357			1,441
Accounts receivable, net	649			518
Income taxes receivable	1			3
Inventories	187			181
Derivatives	43			14
Other	28			23
Total current assets	2,901			3,298
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting	20,188			19,052
Accumulated depletion, depreciation and amortization	(8,841		)	(8,211		)
Total property, plant and equipment	11,347			10,841
Long-term investments	151			420
Goodwill	270			272
Other property and equipment, net	1,683			1,529
Derivatives	7			—
Other assets, net	106			99
	$	16,465		$	16,459
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	1,105		$	875
Interest payable	38			68
Current portion of long-term debt	449			485
Derivatives	17			77
Other	106			61
Total current liabilities	1,715			1,566
Long-term debt	2,282			2,728
Derivatives	12			7
Deferred income taxes	1,475			1,397
Other liabilities	384			350
Equity	10,597			10,411
	$	16,465		$	16,459

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,
	2017			2016			2017			2016
Revenues and other income:
Oil and gas	$	855		$	643		$	2,433		$	1,665
Sales of purchased oil and gas	721			444			1,722			1,062
Interest and other	17			7			44			21
Derivative gains (losses), net	(133		)	91			153			(95		)
Gain on disposition of assets, net	—			1			205			4
	1,460			1,186			4,557			2,657
Costs and expenses:
Oil and gas production	152			141			440			438
Production and ad valorem taxes	53			32			152			97
Depletion, depreciation and amortization	355			386			1,033			1,123
Purchased oil and gas	735			458			1,769			1,113
Impairment of oil and gas properties	—			—			285			32
Exploration and abandonments	18			19			78			96
General and administrative	81			82			245			235
Accretion of discount on asset retirement obligations	5			5			14			14
Interest	37			50			118			161
Other	58			69			176			223
	1,494			1,242			4,310			3,532
Income (loss) before income taxes	(34		)	(56		)	247			(875		)
Income tax benefit (provision)	11			78			(79		)	362
Net income (loss) attributable to common stockholders	$	(23	)	$	22		$	168		$	(513	)
Basic and diluted net income (loss) per share attributable to common stockholders	$	(0.13	)	$	0.13		$	0.98		$	(3.10	)
Basic and diluted weighted average shares outstanding	170			170			170			165

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Cash flows from operating activities:
Net income (loss)	$	(23	)	$	22		$	168		$	(513	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization	355			386			1,033			1,123
Impairment of oil and gas properties	—			—			285			32
Impairment of inventory and other property and equipment	—			1			1			6
Exploration expenses, including dry holes	1			1			19			41
Deferred income taxes	(11		)	(56		)	79			(340		)
Gain on disposition of assets, net	—			(1		)	(205		)	(4		)
Accretion of discount on asset retirement obligations	5			5			14			14
Interest expense	1			2			4			11
Derivative related activity	161			93			(91		)	628
Amortization of stock-based compensation	18			22			61			66
Other noncash items	13			17			48			50
Change in operating assets and liabilities:
Accounts receivable, net	(158		)	(13		)	(131		)	(64		)
Income taxes receivable	—			(22		)	2			17
Inventories	2			5			(9		)	(7		)
Derivatives	—			(12		)	—			(24		)
Investments	2			—			5			—
Other current assets	(5		)	(3		)	(4		)	(3		)
Accounts payable	124			52			82			(8		)
Interest payable	(21		)	(46		)	(30		)	(26		)
Income taxes payable	—			—			—			(2		)
Other current liabilities	(9		)	(12		)	(33		)	(38		)
Net cash provided by operating activities	455			441			1,298			959
Net cash used in investing activities	(486		)	(926		)	(1,259		)	(3,514		)
Net cash provided by (used in) financing activities	7			(449		)	(521		)	2,055
Net decrease in cash and cash equivalents	(24		)	(934		)	(482		)	(500		)
Cash and cash equivalents, beginning of period	660			1,825			1,118			1,391
Cash and cash equivalents, end of period	$	636		$	891		$	636		$	891

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUMMARY PRODUCTION, PRICE AND MARGIN DATA

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Average Daily Sales Volumes:
Oil (Bbls)	161,634		134,240		151,438		130,602
Natural gas liquids ("NGL") (Bbls)	57,346		49,235		52,519		43,252
Gas (Mcfs)	340,384		332,415		344,206		343,828
Total (BOEs)	275,711		238,878		261,325		231,158
Average Prices:
Oil (per Bbl)	$	45.35	$	41.44	$	46.41	$	37.27
NGL (per Bbl)	$	18.96	$	12.46	$	18.38	$	12.37
Gas (per Mcf)	$	2.58	$	2.43	$	2.66	$	1.96
Total (per BOE)	$	33.72	$	29.24	$	34.10	$	26.29

	Three Months Ended September 30, 2017
	Permian Horizontals			Permian Verticals			Eagle Ford			Other Assets (a)			Total
	($ per BOE)
Margin Data:
Average prices	$	36.05		$	34.14		$	27.51		$	19.76		$	33.72
Production costs	(1.85		)	(18.08		)	(11.90		)	(12.87		)	(6.01		)
Production and ad valorem taxes	(2.32		)	(2.04		)	(1.30		)	(1.08		)	(2.10		)
	$	31.88		$	14.02		$	14.31		$	5.81		$	25.61
% Oil	67		%	61		%	34		%	10		%	59		%

__________

(a) Third quarter production was impacted by unplanned downtime at a third party gas processing plant, where the liquids-rich gas from Pioneer’s West Panhandle field in Texas is processed into gas and NGLs. The impact to third quarter production was approximately 1,300 BOEPD, with most of this loss being gas and NGLs.

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-based awards with guaranteed dividend or distribution participation rights qualify as "participating securities" during their vesting periods. During the periods in which the Company realizes net income attributable to common shareholders, 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-based basic earnings (iii) divided by weighted average basic shares outstanding and 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 net loss attributable to common stockholders, securities or other contracts to issue common stock would be dilutive to loss per share; therefore, conversion into common stock is assumed not to occur.

The following table is a reconciliation of the Company's net income (loss) attributable to common stockholders to basic and diluted net income (loss) attributable to common stockholders for the three and nine months ended September 30, 2017 and 2016:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2017			2016		2017			2016
	(in millions)
Net income (loss) attributable to common stockholders	$	(23	)	$	22	$	168		$	(513	)
Participating basic earnings	—			—		(1		)	—
Basic and diluted net income (loss) attributable to common stockholders	$	(23	)	$	22	$	167		$	(513	)

Both basic and diluted weighted average common shares outstanding were 170 million for the three and nine months ended September 30, 2017, respectively, and 170 million and 165 million for the same respective periods in 2016.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Net income (loss)	$	(23	)	$	22		$	168		$	(513	)
Depletion, depreciation and amortization	355			386			1,033			1,123
Exploration and abandonments	18			19			78			96
Impairment of oil and gas properties	—			—			285			32
Impairment of inventory and other property and equipment	—			1			1			6
Accretion of discount on asset retirement obligations	5			5			14			14
Interest expense	37			50			118			161
Income tax (benefit) provision	(11		)	(78		)	79			(362		)
Gain on disposition of assets, net	—			(1		)	(205		)	(4		)
Derivative related activity	161			93			(91		)	628
Amortization of stock-based compensation	18			22			61			66
Other	13			17			48			50
EBITDAX (a)	573			536			1,589			1,297
Cash interest expense	(36		)	(48		)	(114		)	(150		)
Current income tax benefit	—			22			—			22
Discretionary cash flow (b)	537			510			1,475			1,169
Cash exploration expense	(17		)	(18		)	(59		)	(55		)
Changes in operating assets and liabilities	(65		)	(51		)	(118		)	(155		)
Net cash provided by operating activities	$	455		$	441		$	1,298		$	959

_______________

(a)

“EBITDAX” represents earnings before depletion, depreciation and amortization expense; exploration and abandonments; impairment of oil and gas properties; impairment of inventory and other property and equipment; accretion of discount on asset retirement obligations; interest expense; income taxes; net gain on the disposition of assets; 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 exploration expense.

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES (continued)

(in millions, except per share data)

Income adjusted for noncash mark-to-market ("MTM") derivative losses, as presented in this press release, is presented and reconciled to Pioneer's net loss attributable to common stockholders (determined in accordance with GAAP) because Pioneer believes that this non-GAAP financial measure reflects 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 this non-GAAP financial measure may enhance investors' ability to assess Pioneer's historical and future financial performance. This non-GAAP financial measure is not intended to be a substitute 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 or losses will recur in future periods; however, the amount and frequency can vary significantly from period to period. The table below reconciles Pioneer's net loss attributable to common stockholders for the three months ended September 30, 2017, as determined in accordance with GAAP, to adjusted income excluding noncash MTM derivative losses.

	After-tax Amounts			Amounts Per Share
Net loss attributable to common stockholders	$	(23	)	$	(0.13	)
Noncash MTM derivative losses, net ($161 million pretax)	103			0.61
Adjusted income excluding noncash MTM derivative losses	$	80		$	0.48

PIONEER NATURAL RESOURCES COMPANY

SUPPLEMENTAL INFORMATION

Open Commodity Derivative Positions as of October 31, 2017

(Volumes are average daily amounts)

	2017				Year Ending December 31,
		Fourth Quarter			2018		2019
Average Daily Oil Production Associated with Derivatives (Bbl):
Collar contracts:
Volume		6,000			3,000		—
NYMEX price:
Ceiling		$	70.40		$	58.05	$	—
Floor		$	50.00		$	45.00	$	—
Collar contracts with short puts:
Volume		155,000			152,781		—
NYMEX price:
Ceiling		$	62.12		$	57.72	$	—
Floor		$	49.82		$	47.36	$	—
Short put		$	41.02		$	37.32	$	—
Basis swap contracts (a):
Midland-Cushing index swap volume		$	6,630		$	—	$	—
Price differential ($/Bbl)		$	(1.09	)	$	—	$	—
Average Daily NGL Production Associated with Derivatives:
Propane swap contracts (b):
Volume (Bbl)		$	1,658		$	—	$	—
Price		$	37.80		$	—	$	—
Ethane collar contracts (c):
Volume (Bbl)		3,000			—		—
Index price:
Ceiling		$	11.83		$	—	$	—
Floor		$	8.68		$	—	$	—
Ethane basis swap contracts (d):
Volume (MMBtu)		6,920			6,920		6,920
Price differential		$	1.60		$	1.60	$	1.60
Average Daily Gas Production Associated with Derivatives (MMBtu):
Swap contracts
Volume		—			82,740		—
NYMEX price		$	—		$	3.03	$	—
Collar contracts with short puts:
Volume		300,000			62,329		—
NYMEX price:
Ceiling		$	3.60		$	3.56	$	—
Floor		$	2.96		$	2.91	$	—
Short put		$	2.47		$	2.37	$	—
Basis swap contracts:
Mid-Continent index swap volume (e)		45,000			—		—
Price differential ($/MMBtu)		$	(0.32	)	$	—	$	—
Permian Basin index swap volume (f)		39,783			56,603		80,000
Price differential ($/MMBtu)		$	0.36		$	0.32	$	0.31

__________

(a) Represent swap contracts that fix the basis differential between Midland, Texas oil prices and West Texas Intermediate ("WTI") oil prices at Cushing, Oklahoma.

(b) Represent swap contracts that reduce the price volatility of propane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices.

(c) Represent collar contracts that reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices.

(d) Represent basis swap contracts that reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices. The basis swap contracts fix the basis differential on a NYMEX Henry Hub MMBtu equivalent basis. The Company will receive the Henry Hub price plus the price differential on 6,920 MMBtu per day, which is equivalent to 2,500 Bbls per day of ethane.

(e) Represent swap contracts that fix the basis differentials between the index price at which the Company sells its Mid-Continent gas and the NYMEX Henry Hub index price used in collar contracts with short puts.

(f) Represent swap contracts 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.

Marketing 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 that mitigate price risk. As of September 30, 2017, the Company was party to (i) oil index swap contracts for 10,000 Bbls per day of November and December 2017 transportation commitments with a price differential of $4.18 per Bbl between NYMEX WTI and Louisiana Light Sweet oil ("LLS") and (ii) oil index swap contracts for 10,000 Bbls per day of January through August 2018 transportation commitments with a price differential of $3.18 per Bbl between NYMEX WTI and LLS.

Interest rate derivatives. As of September 30, 2017, the Company was party to interest rate derivative contracts whereby the Company will receive the three-month LIBOR rate for the 10-year period from December 2017 through December 2027 in exchange for paying a fixed interest rate of 1.81 percent on a notional amount of $100 million on December 15, 2017. In October2017, the Company liquidated its interest rate derivative contracts for cash proceeds of $5 million.

PIONEER NATURAL RESOURCES COMPANY

SUPPLEMENTAL INFORMATION (continued)

Derivative Gains (Losses), Net

(in millions)

The following table summarizes net derivative gains (losses) that the Company recorded in earnings for the three and nine months ended September 30, 2017:

	Three Months Ended September 30, 2017			Nine Months Ended September 30, 2017
Noncash changes in fair value:
Oil derivative gains (losses)	$	(160	)	$	61
NGL derivative gains	—			2
Gas derivative gains (losses)	(1		)	29
Interest rate derivative losses	—			(1		)
Total noncash derivative gains (losses), net	(161		)	91
Net cash receipts on settled derivative instruments:
Oil derivative receipts	29			61
NGL derivative payments	(2		)	(1		)
Gas derivative receipts	1			1
Diesel derivative receipts	—			1
Total cash receipts on settled derivative instruments, net	28			62
Total derivative gains (losses), net	$	(133	)	$	153