PIONEER NATURAL RESOURCES CO - FORM 8-K - EX-99.1 - PXD MAY 5, 2015 EARNINGS RELEASE 8-K EXHIBIT 99.1

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8-K - PXD MAY 5, 2015 EARNINGS RELEASE 8-K - PIONEER NATURAL RESOURCES CO	form8-kxpxdq12015earningsr.htm

EXHIBIT 99.1

News Release

Pioneer Natural Resources Reports

First Quarter 2015 Financial and Operating Results

Dallas, Texas, May 5, 2015 - Pioneer Natural Resources Company (NYSE:PXD) (“Pioneer” or “the Company”) today announced financial and operating results for the quarter ended March 31, 2015.

Pioneer reported a first quarter net loss attributable to common stockholders of $78 million, or $0.52 per diluted share. Without the effect of noncash derivative mark-to-market gains and other unusual items, adjusted income for the first quarter was a loss of $5 million after tax, or $0.03 per diluted share.

First quarter and other recent highlights included:

•

producing 194 thousand barrels oil equivalent per day (MBOEPD) in the first quarter, of which 51% was oil; first quarter production was impacted by a loss of approximately 3 MBOEPD due to downtime associated with severe winter weather in the Spraberry/Wolfcamp, a loss of approximately 5 MBOEPD due to ethane rejection in the Spraberry/Wolfcamp and Eagle Ford Shale beginning January 1, and the decision made in mid-February to exclusively utilize Pioneer Pumping Services to improve efficiencies, which had the effect of spreading horizontal completions in the Spraberry/Wolfcamp throughout the year;


•	continuing to protect the Company’s cash flow through the use of derivatives, including

(i) maintaining coverage for 2015 forecasted oil production at approximately 90% with most of the volumes protected by swaps at $71 per barrel (resulted in a $20 per barrel uplift in the first quarter), (ii) increasing Pioneer’s 2016 oil production covered by three-way collars by 10 thousand barrels per day (MBOPD) in recent weeks, providing attractive downside protection for 2016 and (iii) maintaining coverage for 2015 forecasted gas production at approximately 90% with three-way collars that provide attractive downside protection;


•	maintaining a strong balance sheet at the end of the first quarter with $383 million of cash on hand and net debt-to-book capitalization of 21%;


•	realizing a 15% decrease in drilling and completion capital compared to 2014 in response to cost reduction initiatives; expecting capital costs to decline by more than 20% by year-end 2015;


•	achieving significant drilling and completions efficiency gains;


•	announcing the closing of the Denver, Colorado, office and the streamlining of operations in the Raton Basin;


•	implementing high-graded horizontal drilling programs in the Spraberry/Wolfcamp and Eagle Ford Shale; currently running 16 horizontal rigs, with 10 rigs in the Spraberry/Wolfcamp and six rigs in the Eagle Ford Shale;


•	exporting 20 MBOPD gross (7 MBOPD net) of Eagle Ford Shale processed condensate in the first quarter with significantly improved pricing compared to domestic condensate sales; and


•	continuing education efforts on the benefits of lifting the U.S. oil export ban.

Pioneer’s updated outlook for 2015 includes:

•

spreading planned first quarter and early second quarter horizontal completions in the Spraberry/Wolfcamp over the remainder of 2015 to more efficiently utilize Pioneer Pumping Services, which continues to be cost competitive with third parties; results in shifting approximately 25 of the original 90 horizontal wells planned for completion in the first quarter and early in the second quarter to later

in the year by exclusively utilizing Pioneer Pumping Services and eliminating third-party service companies; the total number of wells placed on production during the year is not impacted; while this results in first-quarter and second-quarter production being lower than originally expected, production in the third quarter and fourth quarter of the year will be higher than originally expected; the Company is continuing to forecast full-year 2015 production growth of 10%+ compared to 2014;


•	increasing Pioneer’s Spraberry/Wolfcamp oil deliveries to the Gulf Coast from 15 MBOPD currently being shipped on the Longhorn Pipeline to 50 MBOPD by the end of the third quarter, with shipments commencing on the Cactus Pipeline in May and the Permian Express II Pipeline in July;


•	expecting to announce the sale of the Company’s Eagle Ford Shale Midstream business in May, which will further strengthen the balance sheet; and

•

expecting to add two horizontal rigs per month in the northern Spraberry/Wolfcamp beginning in July if the oil price outlook remains positive and an agreement is finalized to sell the Eagle Ford Shale Midstream business; these drilling rig additions are expected to have only a minimal impact on 2015 production due to timing of multi-well pad drilling, but provide production growth in 2016 compared to relatively flat production in 2016 if no rigs are added.

Scott D. Sheffield, Chairman and CEO, stated, “Pioneer has successfully implemented its high-graded horizontal drilling program and continues to deliver strong well results in the Spraberry/Wolfcamp and Eagle Ford Shale. We are also achieving significant cost reductions and efficiency gains, which are resulting in improved margins and returns.”

“Pioneer’s balance sheet remains strong and will become even stronger with the expected sale of the Eagle Ford Shale Midstream business. Our strong balance sheet, combined with a strong derivatives position, provide us with the financial firepower to ramp up drilling activity on high-return wells in the second half of this year. We plan to move forward with this rig ramp up once we have an agreement in place to sell the Eagle Ford Shale Midstream business and assuming the outlook for oil prices remains positive.”

Mark-To-Market Derivative Gains and Unusual Items Included in First Quarter 2015 Earnings

Pioneer’s first quarter earnings included noncash mark-to-market gains on derivatives of $22 million after tax, or $0.15 per diluted share.

First quarter earnings also included a net loss of $95 million after tax, or $0.64 per diluted share, related to the following unusual items:


•	a noncash charge of $87 million after tax, or $0.60 per diluted share, attributable to the impairment of proved properties in Pioneer’s West Panhandle field as a result of lower commodity prices;


•	a loss of $4 million after tax, or $0.02 per diluted share, from discontinued operations; and


•	a noncash charge of $4 million after tax, or $0.02 per diluted share, associated with the impairment of excess vertical well pipe inventory.

Optimizing Returns in a Lower Price Environment

Pioneer has been aggressively pursuing cost reduction initiatives. A 15% reduction in drilling and completion costs in 2015 compared to 2014 has already been realized. The most significant drilling and completion cost reductions to date have been for:


•	materials for drilling and fracture stimulation, such as drilling mud, chemicals, guar and water,


•	fuel charges,


•	labor and transportation,


•	rental equipment, such as blowout preventers and coil tubing, and


•	well services, such as wireline, directional and cementing services.

The Company expects drilling and completion cost reductions to be more than 20% by the end of 2015, with key additional contributors being casing and tubing, well stimulation and drilling rig costs.

By the end of 2015, costs to construct facilities, particularly horizontal tank batteries, and lease operating expenses (LOE) are also expected to be lower by 15% and 10%, respectively, compared to 2014. Savings of 10% are now being realized in the cost of constructing new horizontal tank batteries, with efforts underway to achieve further cost reductions.

Pioneer is currently realizing a 5% reduction in LOE compared to 2014, primarily due to decreases in rates for (i) labor associated with electrical, mechanical, pipeline and inspection services work, (ii) workover units and (iii) pumping unit repairs.

The Company is also achieving significant drilling and completion efficiency gains, including:


•	optimizing completions in the Spraberry/Wolfcamp, including testing various stage lengths, clusters per stage, fluid volumes, fluid chemistry and proppant concentrations, which continue to be encouraging;


•	expanding the use of a modified three-string casing design in the Spraberry/Wolfcamp, where drilling times are being reduced by 10 days to 15 days per well, with savings of $500 thousand to $1 million per well being achieved;


•	expanding the use of dissolvable plug technologies in the Eagle Ford Shale to eliminate coil tubing drillouts after fracture stimulations, where completion times are being reduced by three days, with savings of $300 thousand per well being achieved; testing of dissolvable plug technologies has now commenced in the Spraberry/Wolfcamp; and


•	testing fracture stimulation diversion technologies in the Spraberry/Wolfcamp and Eagle Ford Shale.

Spraberry/Wolfcamp Operations Update and 2015 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. The Company believes it has 10 billion barrels oil equivalent of net recoverable resource potential from horizontal drilling across its entire acreage position based on its extensive geologic data and successful drilling results to date.

In the northern Spraberry/Wolfcamp, the Company has successfully placed 63 horizontal Wolfcamp B interval wells and 25 horizontal Wolfcamp A interval wells on production since it commenced drilling horizontal wells in this area in 2013. The average production from all of these wells is tracking a type curve that is expected to deliver 1 million barrels oil equivalent (MMBOE) over the life of the well.

Pioneer’s horizontal rig count in the northern Spraberry/Wolfcamp was reduced to six rigs by the end of February. Drilling activity has been high-graded to the areas and intervals in the play with the highest estimated ultimate recoveries (EURs) and net revenue interests. Activity is also being focused in areas where horizontal tank batteries already exist. The Company plans to spud approximately 60 new wells in 2015 utilizing two-well and three-well pads. Approximately 90% of these new wells will be drilled in the Wolfcamp B interval and the remaining 10% in the Wolfcamp A interval.

As a result of the carryover drilling activity from 2014 (wells drilled, but not completed) in the northern Spraberry/Wolfcamp, Pioneer expects to place 85 to 90 horizontal wells on production during 2015 compared to 97 horizontal wells in 2014. Of these, 70% will be Wolfcamp B interval wells. The remainder will be split between Wolfcamp A, Wolfcamp D and Lower Spraberry Shale interval wells. The average cost to drill and complete a well in 2015 is expected to be approximately $9 million, assuming an average lateral length of 9,000 feet and an average 10% cost reduction compared to 2014. The 2015 drilling program is expected to generate EURs averaging approximately 1 MMBOE with before-tax internal rates of return (IRRs) up to 55% at current strip prices (assumes average oil price of $55 per barrel during 2015). The Company placed 15 horizontal wells on production in the first quarter, of which 10 were Wolfcamp B interval wells, two were Wolfcamp A interval wells and three were Lower Spraberry Shale wells. The

vertical drilling program was shut down by the end of February. Twenty-nine vertical wells were placed on production during the first quarter.

In the southern Wolfcamp joint venture area, Pioneer’s horizontal rig count was reduced to four rigs by the end of February. As in the northern Spraberry/Wolfcamp, drilling activity has been high-graded to the areas and intervals in the play with the highest EURs and net revenue interests. Activity is also being focused in areas where horizontal tank batteries already exist. The Company plans to spud approximately 45 new wells in 2015 utilizing two-well and three-well pads. More than 90% of these new wells will be drilled in the Wolfcamp B interval.

As a result of the carryover drilling activity from 2014 (wells drilled, but not completed) in the southern Wolfcamp joint venture area, Pioneer expects to place 75 to 80 horizontal wells on production during 2015 compared to 113 horizontal wells in 2014. Of these, 75% will be Wolfcamp B interval wells. The remainder will be split between Wolfcamp A and Wolfcamp D interval wells. The average cost to drill and complete a well in 2015 is expected to be approximately $8 million, assuming an average lateral length of 9,000 feet and an average 10% cost reduction compared to 2014. The 2015 drilling program is expected to generate EURs averaging approximately 750 thousand barrels oil equivalent (MBOE) with before-tax IRRs up to 55% at current strip prices (assumes average oil price of $55 per barrel during 2015). The Company placed 31 horizontal wells on production in the first quarter, including 22 Wolfcamp B interval wells and nine Wolfcamp A interval wells.

First quarter production from the Spraberry/Wolfcamp averaged 112 MBOEPD, of which 67% was oil. Horizontal production was 51 MBOEPD and vertical production was 61 MBOEPD. First quarter production was negatively impacted by approximately 3 MBOEPD due to downtime associated with severe winter weather in January and approximately 3 MBOEPD related to the Company’s decision to begin rejecting ethane on January 1 due to weak market conditions. The number of horizontal wells placed on production during the first quarter (46 wells) was lower than planned due to the decision to exclusively utilize Pioneer Pumping Services and thereby spreading completions throughout the year instead of weighting them more to the first half of the year.

Spraberry/Wolfcamp production is forecasted to increase by 20%+ in 2015 compared to 2014. Production in 2015, as compared to 2014, is expected to be negatively impacted by (i) 1 MBOEPD (annual impact) of weather-related production curtailments experienced during January in the Spraberry/Wolfcamp and (ii) 3 MBOEPD associated with rejecting ethane due to weak market conditions that are expected to continue throughout the year.

Spraberry/Wolfcamp Infrastructure Plans

Pioneer’s long-term growth plan is focused on optimizing the development of the Spraberry/Wolfcamp, which includes ensuring that future infrastructure requirements are constructed. These requirements include the build-out of horizontal tank batteries, construction of additional gas processing facilities, expansion of the Brady sand mine and construction of a field-wide water distribution network. In response to the recent reduction in horizontal drilling activity, spending for this infrastructure in the original 2015 capital budget was curtailed to $410 million.

Of this amount, $285 million is classified as drilling capital and includes:


•	$215 million for tank batteries and saltwater disposal facilities to support the high-graded drilling program and


•	$70 million for gas processing facilities, including Pioneer’s share of gathering system connections and early phase construction costs of a new 200 million cubic feet per day (MMCFPD) gas processing plant in Martin County (Buffalo plant) that Targa Resources remains committed to complete, but has deferred start-up from the third quarter of 2015 to 2016.

The remaining $125 million of other infrastructure capital is classified as property, plant and equipment and includes:


•	$25 million for the engineering and site preparation work related to the Brady sand mine expansion (capacity increase from 750 thousand tons per year to 2.1 million tons per year), which has been deferred until at least 2016, and


•	$100 million for engineering, right-of-way acquisition, pipeline installation and connecting a third-party Santa Rosa brackish water source to Pioneer’s water distribution system; the City of Odessa has agreed to allow Pioneer to defer offtake of effluent water for up to two years; discussions are continuing with the City of Midland to purchase effluent water when drilling activity increases.

If two horizontal rigs per month are added during the second half of 2015 in the northern Spraberry/Wolfcamp, less than $50 million of additional infrastructure capital will be required this year for tank batteries, saltwater disposal facilities and well connections as activity expands to new areas.

Eagle Ford Shale Operations Update and 2015 Outlook

In the liquids-rich area of the Eagle Ford Shale play in South Texas, Pioneer’s horizontal rig count was reduced to six rigs by the end of February. Drilling activity has been high-graded to Karnes and DeWitt counties where Pioneer has been drilling the most productive wells in the Eagle Ford Shale, with EURs averaging approximately 1.3 MMBOE. Pioneer expects to place 95 to 100 horizontal wells on production during 2015, split evenly between Upper targets and Lower targets.

The average drilling and completion cost for the 2015 program in the Eagle Ford Shale is expected to be $7.0 million to $8.0 million per well, reflecting an average lateral length of 5,000 feet and an assumed 10% cost reduction compared to 2014. The high-graded 2015 drilling program is expected to generate before-tax IRRs up to 70% at current strip prices (assumes average oil price of $55 per barrel during 2015).

Pioneer placed 16 horizontal wells on production in the first quarter of 2015. Of this total, nine wells were in Upper targets and seven wells were in Lower 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. Production results from these wells continue to be 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.

Pioneer’s first quarter production from the Eagle Ford Shale averaged 47 MBOEPD, of which 40% was condensate. Production was negatively impacted by approximately 2 MBOEPD during the quarter as a result of greater-than-anticipated shut-in production related to offset fracture stimulations on nearby wells. The Company also elected to begin rejecting ethane on January 1 due to weak market conditions, which reduced first quarter production by approximately 2 MBOEPD.

Eagle Ford Shale production is forecasted to increase by 9%+ in 2015 compared to 2014. Ethane rejection of approximately 2 MBOEPD is expected to continue throughout the year as a result of weak market conditions.

2015 Capital Budget

Pioneer’s capital program for 2015 of $1.85 billion (excludes acquisitions, asset retirement obligations, capitalized interest and geological and geophysical G&A) includes $1.60 billion for drilling and $0.25 billion related to the development of the Spraberry/Wolfcamp water infrastructure, vertical integration and facilities. This capital program excludes the additional capital that would be required if Pioneer adds drilling rigs over the second half of the year.

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


•	Northern Spraberry/Wolfcamp - $1,050 million (includes $735 million for the horizontal drilling program, $20 million for the vertical drilling program, $225 million for infrastructure additions and land and $70 million for gas processing facilities)


•	Southern Wolfcamp joint venture area (net of carry) - $120 million (includes $90 million for the horizontal drilling program and $30 million for infrastructure additions and land)


•	Eagle Ford Shale - $390 million (includes $335 million for the horizontal drilling program and $55 million for infrastructure additions and land)


•	Other Assets - $40 million

The 2015 capital budget is expected to be funded from forecasted operating cash flow of $1.6 billion (assuming commodity prices of $55.00 per barrel for oil and $3.00 per thousand cubic feet (MCF) for gas) and cash on the balance sheet.

Pioneer’s net debt at the end of the first quarter of 2015 was $2.3 billion with net debt-to-book capitalization of 21%. The Company will continue to target net debt-to-operating cash flow below 1.5 and a net debt-to-book capitalization below 35%.

The Company had $383 million of cash on hand at the end of the first quarter. This reflects a reduction of $642 million from the end of the fourth quarter of 2014 due to:


•	drilling, infrastructure and facilities expenditures of $720 million, which includes costs incurred from the fourth quarter of 2014 that were not invoiced until the first quarter;


•	a reduction in accounts payable of $250 million associated with reduced drilling activity;


•	partially offset by operating cash flow of $330 million before working capital changes.

First Quarter 2015 Financial Review

Sales volumes for the first quarter of 2015 averaged 194 MBOEPD. Oil sales averaged 99 thousand barrels per day (MBPD), natural gas liquids (NGLs) sales averaged 35 MBPD and gas sales averaged 359 MMCFPD.

The average realized price for oil was $43.02 per barrel. The average realized price for NGLs was $15.00 per barrel, and the average realized price for gas was $2.70 per MCF. These prices exclude the effects of derivatives.

Production costs averaged $12.56 per barrel oil equivalent (BOE). Depreciation, depletion and amortization (DD&A) expense averaged $17.77 per BOE. Exploration and abandonment costs were $25 million, principally comprised of $5 million for seismic data and $15 million for personnel costs. General and administrative expense totaled $82 million. Interest expense was $46 million, and other expense was $42 million (excluding unusual items), which included $23 million of stacked drilling rig charges.

Second Quarter 2015 Financial Outlook

The Company’s second quarter 2015 outlook for certain operating and financial items is provided below.

Production is forecasted to average 198 MBOEPD to 203 MBOEPD.

Production costs are expected to average $13.00 per BOE to $15.00 per BOE. DD&A expense is expected to average $16.00 per BOE to $18.00 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 $45 million to $50 million and other expense is expected to be $50 million to $60 million,

which includes $30 million to $35 million for stacked drilling rig charges. 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, May 6, 2015, at 9:00 a.m. Central Time, Pioneer will discuss its financial and operating results for the quarter ended March 31, 2015, 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) 339-3503 and confirmation code: 7269838 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 May 31, 2015, by dialing (888) 203-1112 and confirmation code: 7269838.

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, 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, and 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,” “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.

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

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions)



	March 31, 2015			December 31, 2014
ASSETS
Current assets:
Cash and cash equivalents	$	383		$	1,025
Accounts receivable, net	343			440
Income taxes receivable	22			23
Inventories	266			241
Prepaid expenses	20			15
Derivatives	624			578
Other	36			37
Total current assets	1,694			2,359

Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting	16,167			15,821
Accumulated depletion, depreciation and amortization	(5,727		)	(5,431		)
Total property, plant and equipment	10,440			10,390

Goodwill	272			272
Other property and equipment, net	1,406			1,391
Investment in unconsolidated affiliate	259			239
Derivatives	181			181
Other assets, net	95			94

	$	14,347		$	14,926

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	878		$	1,320
Interest payable	20			40
Income taxes payable	1			1
Deferred income taxes	185			161
Derivatives	16			3
Other	62			55
Total current liabilities	1,162			1,580

Long-term debt	2,668			2,665
Derivatives	—			2
Deferred income taxes	1,738			1,803
Other liabilities	280			287
Equity	8,499			8,589

	$	14,347		$	14,926

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per share data)



	Three Months Ended March 31,
	2015			2014
Revenues and other income:
Oil and gas	$	517		$	890
Sales of purchased oil and gas	103			147
Interest and other	6			5
Derivative gains (losses), net	241			(104		)
Gain on disposition of assets, net	1			6
	868			944
Costs and expenses:
Oil and gas production	180			158
Production and ad valorem taxes	39			55
Depletion, depreciation and amortization	310			217
Purchased oil and gas	108			143
Impairment of oil and gas properties	138			—
Exploration and abandonments	25			31
General and administrative	82			81
Accretion of discount on asset retirement obligations	3			3
Interest	46			45
Other	48			15
	979			748

Income (loss) from continuing operations before income taxes	(111		)	196
Income tax benefit (provision)	37			(51		)
Income (loss) from continuing operations	(74		)	145
Loss from discontinued operations, net of tax	(4		)	(22		)
Net income (loss) attributable to common stockholders	$	(78	)	$	123

Basic and diluted earnings per share attributable to common stockholders:
Income (loss) from continuing operations	$	(0.50	)	$	1.00
Loss from discontinued operations	(0.02		)	(0.15		)
Net income (loss)	$	(0.52	)	$	0.85

Basic and diluted weighted average shares outstanding	149			143

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)



	Three Months Ended March 31,
	2015			2014
Cash flows from operating activities:
Net income (loss)	$	(78	)	$	123
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization	310			217
Impairment of oil and gas properties	138			—
Impairment of inventory and other property and equipment	6			—
Exploration expenses, including dry holes	5			7
Deferred income taxes	(37		)	39
Gain on disposition of assets, net	(1		)	(6		)
Accretion of discount on asset retirement obligations	3			3
Discontinued operations	(3		)	103
Interest expense	5			4
Derivative related activity	(35		)	86
Amortization of stock-based compensation	22			22
Other	(1		)	7
Change in operating assets and liabilities:
Accounts receivable, net	96			(37		)
Income taxes receivable	1			5
Inventories	(34		)	(16		)
Prepaid expenses	(5		)	(1		)
Other current assets	(7		)	(3		)
Accounts payable	(250		)	(70		)
Interest payable	(20		)	(26		)
Income taxes payable	—			9
Other current liabilities	(11		)	—
Net cash provided by operating activities	104			466
Net cash used in investing activities	(717		)	(626		)
Net cash provided by (used in) financing activities	(29		)	24
Net decrease in cash and cash equivalents	(642		)	(136		)
Cash and cash equivalents, beginning of period	1,025			393
Cash and cash equivalents, end of period	$	383		$	257

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUMMARY PRODUCTION AND PRICE DATA



	Three Months Ended March 31,
	2015		2014
Average Daily Sales Volumes:
Oil (Bbls)	98,554		78,589
Natural gas liquids ("NGL") (Bbls)	35,364		33,497
Gas (Mcf)	359,428		321,402
Total (BOE)	193,823		165,653

Average Prices:
Oil (per Bbl)	$	43.02	$	92.38
NGL (per Bbl)	$	15.00	$	32.82
Gas (per Mcf)	$	2.70	$	4.75
Total (BOE)	$	29.63	$	59.68

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. The Company's basic net income (loss) per share attributable to common stockholders is computed as (i) net income (loss) attributable to common stockholders, (ii) less participating share-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 (loss) 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 (loss) attributable to common stockholders to basic and diluted net income (loss) attributable to common stockholders for the three months ended March 31, 2015 and 2014:



	Three Months Ended March 31,
	2015			2014
	(in millions)

Net income (loss) attributable to common stockholders	$	(78	)	$	123
Participating basic earnings	—			(1		)
Basic and diluted net income (loss) attributable to common stockholders	$	(78	)	$	122

Basic and diluted weighted average common shares outstanding were 149 million for the three months ended March 31, 2015 and 143 million for the three months ended March 31, 2014.

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 March 31,
	2015			2014

Net income (loss)	$	(78	)	$	123
Depletion, depreciation and amortization	310			217
Exploration and abandonments	25			31
Impairment of oil and gas properties	138			—
Impairment of inventory and other property and equipment	6			—
Accretion of discount on asset retirement obligations	3			3
Interest expense	46			45
Income tax (benefit) provision	(37		)	51
Gain on disposition of assets, net	(1		)	(6		)
Loss from discontinued operations, net of tax	4			22
Derivative related activity	(35		)	86
Amortization of stock-based compensation	22			22
Other	(1		)	7

EBITDAX (a)	402			601

Cash interest expense	(41		)	(41		)
Current income tax provision	—			(12		)

Discretionary cash flow (b)	361			548

Discontinued operations cash activity	(7		)	81
Cash exploration expense	(20		)	(24		)
Changes in operating assets and liabilities	(230		)	(139		)
Net cash provided by operating activities	$	104		$	466

_______________



(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; 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 loss adjusted for noncash mark-to-market ("MTM") derivative gains, and adjusted loss excluding noncash MTM derivative gains and unusual items, as presented in this press release, are presented and reconciled to Pioneer's net loss 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 loss attributable to common stockholders for the three months ended March 31, 2015, as determined in accordance with GAAP, to loss adjusted for noncash MTM derivative gains and adjusted loss excluding noncash MTM derivative gains and unusual items for that quarter.



	After-tax Amounts			Amounts Per Share

Net loss attributable to common stockholders	$	(78	)	$	(0.52	)
Noncash MTM derivative gains	(22		)	(0.15		)
Net loss adjusted for noncash MTM derivative gains	(100		)	(0.67		)

Impairment of West Panhandle proved properties	87			0.60
Loss from discontinued operations	4			0.02
Impairment of excess vertical well pipe inventory	4			0.02
Adjusted loss excluding noncash MTM derivative gains and unusual items	$	(5	)	$	(0.03	)

PIONEER NATURAL RESOURCES COMPANY

SUPPLEMENTAL INFORMATION

Open Commodity Derivative Positions as of May 4, 2015

(Volumes are average daily amounts)



	2015									Year Ending December 31,
	Second Quarter			Third Quarter			Fourth Quarter			2016			2017

Average Daily Oil Production Associated with Derivatives (Bbl):
Swap contracts:
Volume	82,000			82,000			82,000			—			—
NYMEX price	$	71.18		$	71.18		$	71.18		$	—		$	—
Collar contracts with short puts (a):
Volume (a)	15,000			15,000			15,000			83,000			—
NYMEX price:
Ceiling	$	97.69		$	97.69		$	97.69		$	78.47		$	—
Floor	$	82.97		$	82.97		$	82.97		$	68.38		$	—
Short put	$	69.67		$	69.67		$	69.67		$	47.38		$	—
Rollfactor swap contracts:
Volume	37,000			37,000			37,000			—			—
NYMEX roll price (b)	$	0.06		$	0.06		$	0.06		$	—		$	—
Average Daily NGL Production Associated with Derivatives (Bbl):
Ethane swap contracts:
Volume	6,000			6,000			6,000			4,000			—
Index price	$	7.80		$	7.80		$	7.80		$	12.29		$	—
Propane swap contracts:
Volume	11,000			11,000			11,000			2,000			—
Index price	$	21.62		$	21.62		$	21.62		$	21.63		$	—
Average Daily Gas Production Associated with Derivatives (MMBtu):
Swap contracts:
Volume	20,000			20,000			20,000			70,000			—
NYMEX price	$	4.31		$	4.31		$	4.31		$	4.06		$	—
Collar contracts with short puts:
Volume	285,000			285,000			285,000			20,000			—
NYMEX price:
Ceiling	$	5.07		$	5.07		$	5.07		$	5.36		$	—
Floor	$	4.00		$	4.00		$	4.00		$	4.00		$	—
Short put	$	3.00		$	3.00		$	3.00		$	3.00		$	—
Basis swap contracts (c):
Gulf Coast index swap volume	20,000			20,000			20,000			—			—
Price differential ($/MMBtu)	$	—		$	—		$	—		$	—		$	—
Mid-Continent index swap volume	95,000			95,000			95,000			15,000			45,000
Price differential ($/MMBtu)	$	(0.24	)	$	(0.24	)	$	(0.24	)	$	(0.32	)	$	(0.32	)
Permian Basin index swap volume	10,000			10,000			10,000			—			—
Price differential ($/MMBtu)	$	(0.13	)	$	(0.13	)	$	(0.13	)	$	—		$	—

_______________



(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 swaps that fix the basis differentials between the index prices at which the Company sells its Gulf Coast, Mid-Continent and Permian Basin gas, respectively, and the NYMEX Henry Hub index price used in gas swap and collar contracts.

Interest rate derivatives. As of May 4, 2015, the Company was a party to interest rate derivative contracts whereby the Company will receive the 10-year Treasury rate in exchange for paying the average fixed rates of 2.43 percent on a notional amount of $200 million on June 30, 2015 and 2.37 percent on a notional amount of $150 million on September 30, 2015.

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 May 4, 2015, the Company had oil index swap contracts totaling 10,655 BBL per day for the remainder of 2015 with a price differential of $3.16 per BBL between Cushing WTI and Louisiana Light Sweet oil.

Derivative Gains, Net

(in millions)

The following table summarizes net derivative gains and losses that the Company has recorded in earnings for the three months ended March 31, 2015:



	Three Months Ended March 31, 2015
Noncash changes in fair value:
Oil derivative gains	$	50
NGL derivative losses	(3		)
Gas derivative gains	4
Marketing derivative losses	(6		)
Interest rate derivative losses	(10		)
Total noncash derivative gains, net	35

None
Oil derivative receipts	181
NGL derivative payments	(1		)
Gas derivative receipts	26
Total cash derivative receipts, net	206
Total derivative gains, net	$	241

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