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Pioneer Natural Resources Company Reports Second Quarter 2017 Financial and Operating Results

DALLAS--(BUSINESS WIRE)--Aug. 1, 2017-- Pioneer Natural Resources Company (NYSE:PXD) (“Pioneer” or “the Company”) today reported financial and operating results for the quarter ended June 30, 2017.

Pioneer reported second quarter net income attributable to common stockholders of $233 million, or $1.36 per diluted share. Without the effect of noncash mark-to-market derivative gains and the gain from the sale of acreage in Martin County, Texas, adjusted results for the second quarter were earnings of $38 million after tax, or $0.21 per diluted share.

Second quarter 2017 and other recent highlights included:

  • producing 259 thousand barrels oil equivalent per day (MBOEPD), of which 57% was oil; quarterly production grew by 10 MBOEPD, or 4%, compared to the first quarter of 2017, and was at the top end of Pioneer’s second quarter production guidance range of 254 MBOEPD to 259 MBOEPD; this was the ninth consecutive quarter of production growth since the oil price collapse in late 2014; second quarter production growth was driven by the Company’s Spraberry/Wolfcamp horizontal drilling program; total Spraberry/Wolfcamp production increased 12 MBOEPD, or 6%, compared to the first quarter of 2017; internal rates of return (IRRs) on Spraberry/Wolfcamp drilling continue to be strong;
  • reducing production costs (excluding taxes) to $6.19 per barrel oil equivalent (BOE) in the second quarter compared to $6.31 per BOE in the first quarter of 2017 and $6.79 per BOE in 2016; production costs benefited from continuing low horizontal Spraberry/Wolfcamp production costs of $2.23 per BOE for the quarter;
  • adding 51 thousand barrels oil per day (MBOPD) of oil derivatives for 2018; Pioneer’s derivative positions now cover approximately 90% of forecasted oil production and 80% of forecasted gas production for the remainder of 2017, 50% of forecasted oil production for 2018 and 15% of forecasted gas production for 2018;
  • maintaining a strong balance sheet with cash on hand at the end of the second quarter of $2.4 billion (includes liquid investments); net debt to forecasted 2017 operating cash flow was 0.2 times at the end of the second quarter, and net debt to book capitalization was 3%;
  • placing 61 horizontal wells on production in the Spraberry/Wolfcamp during the second quarter; nine wells utilized higher intensity completions compared to Version 3.0 wells (referred to as Version 3.0+ completions), with encouraging early results; four wells were completed in the Jo Mill interval that continue to support the successful appraisal of this zone; the remaining 48 wells were Version 3.0 completions that continue to outperform Version 2.0 completions;
  • placing four wells on production in the Eagle Ford Shale that were drilled, but not completed in early 2016, utilizing higher intensity completions; these wells are outperforming nearby wells with less intense completions by more than 20% after approximately 50 days of production; and
  • exporting approximately one million barrels of Pioneer’s Permian oil during the second quarter to Europe; the Company expects to export another one million barrels to Europe and Asia during the third quarter.

Pioneer’s updated 2017 outlook is summarized below:

  • operating 18 horizontal rigs in the Spraberry/Wolfcamp; of these, 14 rigs are in the northern area and four rigs are focused in the northern portion of the southern Wolfcamp joint venture area (Pioneer has a 60% working interest in the joint venture); both areas are utilizing Version 3.0 completions, with some wells testing larger completions during the year; IRRs on this year’s 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).
  • maintaining efficient operations in the Spraberry/Wolfcamp by not accelerating activity over the remainder of 2017 to catch up on completions that were delayed due to unforeseen drilling delays, especially in light of the current commodity price environment; the Company now expects to place approximately 230 wells on production during 2017 compared to a plan of approximately 260 wells, with associated capital spending expected to be reduced from $2.4 billion to $2.3 billion;
  • producing increased gas and natural gas liquids (NGLs) from horizontal proved developed producing (PDP) wells as of year-end 2016 due to higher average gas-oil ratios (GORs) than forecasted based on current type curves; the increased gas and NGL production is expected to result in higher estimated ultimate well recoveries (EURs), positive reserve revisions and enhanced returns;
  • continuing to meet type curve expectations for Spraberry/Wolfcamp oil production for horizontal PDP wells and 2017 new drills; oil content from new drills in the Spraberry/Wolfcamp continues to average 70% to 80% as expected; cumulative oil content for all Spraberry/Wolfcamp horizontal wells placed on production since 2011 is approximately 70%;
  • drilling and completing 11 new wells and completing nine drilled but uncompleted wells in the Eagle Ford Shale during 2017 (Pioneer has a 46% working interest); the objective of the 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 35% to 45% assuming an oil price of $50 per barrel and a gas price of $3 per MCF; and
  • expecting 2017 production growth for the Company to be 15% to 16%, the low end of the Company’s forecasted 15% to 18% targeted growth range; reflects the lost production from the deferral of 30 Spraberry/Wolfcamp completions to 2018, offset by the benefit of increased gas and NGL production from higher GORs; the Company’s oil growth rate is also being reduced to a range of 17% to 18% as a result of the completion deferrals; oil content for 2017 is expected to average approximately 58%.

President and CEO Timothy L. Dove stated, “The Company delivered another strong quarter, with solid earnings, production at the top end of our second quarter guidance range, continued impressive horizontal well performance in the Spraberry/Wolfcamp and reduced production costs. We are drilling high-return and highly productive wells primarily as a result of our successful completion optimization program. In particular, we are seeing encouraging results from the larger Version 3.0+ completions in the Midland Basin.”

“Operationally, we fell behind on our completions due to unforeseen drilling delays. To maintain efficient operations, we have chosen not to accelerate activity in order to catch up in the second half, especially in light of the current commodity price environment. Our current rig count remains the same, but we are deferring 30 Spraberry/Wolfcamp completions that were planned for this year into 2018. This will result in a reduction in 2017 capital spending of approximately $100 million and production growth closer to the low end of our guidance range of 15% to 18% for 2017. This decision is consistent with our longer-term objective to grow production efficiently by maintaining a steady pace of activity, spending within cash flow, maintaining a strong balance sheet and improving corporate returns.”

Mark-to-Market Derivative Gains and Unusual Items Included in Second Quarter 2017 Earnings

Pioneer’s second quarter earnings included a noncash mark-to-market gain on derivatives of $71 million after tax, or $0.42 per diluted share. Earnings also included a gain of $124 million after tax, or $0.73 per diluted share, from the sale of acreage in Martin County, Texas.

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 2017 plan assumed that approximately 260 horizontal wells would be placed on production during the year, weighted heavily to the second half of the year (approximately 150 of these wells). Due to unforeseen drilling delays in the first half of the year, 11 wells were not placed on production as planned, and many of the wells during this period were placed on production later than expected. Moreover, approximately one-third of the 99 wells that were placed on production in the first half of the year occurred in June. This resulted in significant lost production days. The impact of these delays is a reduction to the full-year Spraberry/Wolfcamp horizontal oil growth forecast of approximately 8 MBOPD.

The Company is producing increased gas and NGLs from its 770 horizontal PDP wells (as of year-end 2016) due to higher GORs than forecasted based on current type curves. As a result, gas and NGL production is above the Company’s 2017 plan forecast, while the Company’s oil production from these wells is meeting the plan forecast. The increased gas and NGL production is expected to result in higher EURs, positive reserve revisions and enhanced returns.

Gradually increasing GORs over the life of a well has been observed in the Spraberry/Wolfcamp since the 1950s. It is normal for reservoirs driven by solution gas to experience increasing GORs over time. Increasing GORs on horizontal wells is consistent with the long-dated history of increasing GORs on vertical wells in the Spraberry/Wolfcamp. However, because horizontal wells contact more surface area and draw down pressures faster, the GORs on these wells are increasing somewhat faster than the increase experienced on vertical wells.

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. The Version 2.0 design increased the cost of a completion by approximately $500 thousand per well. 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 cost of this design added $500 thousand to $1 million per well compared to Version 2.0. The Company placed 48 Version 3.0 wells on production in the second quarter. These wells and the 154 Version 3.0 wells that were placed on production prior to the second quarter of 2017 are continuing to outperform Version 2.0 completions.

In addition to the 48 Version 3.0 wells that were placed on production during the second quarter, Pioneer placed nine wells on production that utilized higher intensity completions compared to Version 3.0 wells. These are being referred to as Version 3.0+ completions. Six 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 six additional 3.0+ wells over the remainder of the year.

The Company placed four Jo Mill wells on production during the second quarter. Nine wells have now been tested as part of the Jo Mill appraisal program since the fourth quarter of 2014. Of the four second quarter wells, performance from three of the wells that have at least 60 days of production is encouraging. The fourth well is currently flowing back. The Jo Mill wells placed on production to date cover a large cross section of Pioneer’s acreage. The Company plans to place two additional Jo Mill wells on production in the third quarter. The cost of the Jo Mill wells in the 2017 program is approximately $7 million per well for an average lateral length of 10,000 feet.

The expected 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. 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.

As a result of the increased EURs associated with the higher GORs that are being experienced on horizontal PDP wells, the Company is increasing the EURs for Wolfcamp interval wells. For the 2017 drilling program, the Wolfcamp B EUR is being increased from 1.5 million barrels oil equivalent (MMBOE) to 1.7 MMBOE and the Wolfcamp A EUR is being increased from 1.2 MMBOE to 1.3 MMBOE. The EUR for Lower Spraberry Shale wells remains at 1.0 MMBOE since higher GORs than forecasted have not been experienced in this shallower interval.

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 and the benefit of higher EURs attributable to Wolfcamp interval wells as a result of the increased GORs.

The Company’s Spraberry/Wolfcamp horizontal drilling program continues to drive production growth, with total Spraberry/Wolfcamp production growing by 12 MBOEPD, or 6%, in the second quarter of 2017 compared to the first 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. The Company also plans to commence a limited appraisal program for the Clearfork and Wolfcamp D intervals late this year.

In the third quarter, the Company expects to place 55 to 60 wells on production, which are expected to be weighted evenly across the quarter. The Company assumes that it will continue to reject ethane throughout 2017, based on continuing weak market conditions.

Spraberry/Wolfcamp Oil Pipeline Commitments

Pioneer is currently delivering 60 MBOPD of Spraberry/Wolfcamp oil to the Gulf Coast under firm pipeline contracts. These contracts provide domestic and export delivery capability to Corpus Christi, Houston and Nederland. There is currently approximately seven million barrels per day of refinery capacity in the Gulf Coast market, with approximately two million barrels per day of oil export capability.

The Company is finalizing agreements with several midstream companies that will expand current oil transport commitments to meet the Company’s expected Spraberry/Wolfcamp volume growth. The Company has a longer-term target to move 70% to 80% of forecasted net oil production under firm pipeline contracts to the Gulf Coast in order to increase its access to international markets and the U.S. refinery market.

Eagle Ford Shale Operations

In the liquids-rich area of the Eagle Ford Shale play in South Texas, Pioneer has commenced a limited horizontal drilling and completion program that is focused in Karnes, DeWitt and Live Oak counties. The 2017 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 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 $8.5 million per well. The Company expects EURs averaging 1.3 MMBOE for the new wells with IRRs ranging from 35% to 45%, 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. Four of the drilled but uncompleted wells (DUCs) were also fracture stimulated and placed on production during the second quarter. After approximately 50 days of production, the wells are exhibiting a productivity improvement of more than 20% above nearby wells with less intense completions. Completion of the remaining 16 wells (5 DUCs and 11 new drills) is expected by early in the fourth quarter.

Pioneer’s production from the Eagle Ford Shale averaged 19 MBOEPD in the second quarter, of which 32% was condensate, 34% was NGLs and 34% 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 40%, while the decline from the fourth quarter of 2016 to the fourth quarter of 2017 is expected to be shallower at 20% since the production from the 2017 program is heavily weighted to the second half of the year.

2017 Capital Program

The Company’s capital budget for 2017 is being reduced from $2.8 billion to $2.7 billion (excluding acquisitions, asset retirement obligations, capitalized interest, geological and geophysical G&A and IT system upgrades). The reduction reflects the decision to defer 30 Spraberry/Wolfcamp completions to 2018. The budget includes $2.4 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 – $2.3 billion (includes $1.8 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$95 million (includes $65 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 the second half of 2017 of $47.50 per barrel for oil and $3.00 per MCF for gas) and cash on hand (including liquid investments). Net debt to 2017 operating cash flow is forecasted to remain below 1.0 times.

Second Quarter 2017 Financial Review

Sales volumes for the second quarter of 2017 averaged 259 MBOEPD. Oil sales averaged 147 thousand barrels per day (MBPD), NGL sales averaged 53 MBPD and gas sales averaged 354 million cubic feet per day.

The average realized price for oil was $45.00 per barrel. The average realized price for NGLs was $16.91 per barrel, and the average realized price for gas was $2.62 per MCF. These prices exclude the effects of derivatives.

Production costs including taxes averaged $8.38 per BOE. Depreciation, depletion and amortization (DD&A) expense averaged $14.46 per BOE. Exploration and abandonment costs were $26 million, including $8 million for drilling, acreage and other abandonments, $2 million for seismic purchases and $16 million for personnel costs. General and administrative expense totaled $81 million. Interest expense was $35 million. Other expense was $59 million, including (i) $43 million of charges associated with excess firm gathering and transportation commitments and (ii) $5 million of losses (principally noncash) associated with the portion of vertical integration services provided to nonaffiliated working interest owners, including joint venture partners, in wells operated by the Company.

Third Quarter 2017 Financial Outlook

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

Production is forecasted to average 274 MBOEPD to 279 MBOEPD.

Production costs are expected to average $7.75 per BOE to $9.75 per BOE. DD&A expense is expected to average $14.00 per BOE to $16.00 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 $33 million to $38 million. Other expense is forecasted to be $60 million to $70 million and is expected to include (i) $45 million to $50 million of charges associated with excess firm gathering and transportation commitments and (ii) $5 million to $10 million of losses (principally noncash) associated with the portion of vertical integration services provided to nonaffiliated working interest owners, including joint venture partners, in wells operated by the Company. 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 Wednesday, August 2, 2017, at 9:00 a.m. Central Time, Pioneer will discuss its financial and operating results for the quarter ended June 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) 312-3046 and confirmation code 5070224 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 August 26, 2017. Click here to register for the call-in audio replay, and enter confirmation code 5070224.

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 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, investment instruments and derivative contracts and purchasers of Pioneer’s oil, natural gas liquids 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
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions)
 
    June 30, 2017     December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents $ 660 $ 1,118
Short-term investments 1,539 1,441
Accounts receivable, net 491 518
Income taxes receivable 1 3
Inventories 192 181
Derivatives 156 14
Other   25     23  
Total current assets   3,064     3,298  
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting 19,501 19,052
Accumulated depletion, depreciation and amortization   (8,505 )   (8,211 )
Total property, plant and equipment   10,996     10,841  
Long-term investments 187 420
Goodwill 270 272
Other property and equipment, net 1,622 1,529
Derivatives 29
Other assets, net   103     99  
$ 16,271   $ 16,459  
 
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable $ 944 $ 875
Interest payable 59 68
Current portion of long-term debt 449 485
Derivatives 3 77
Other   103     61  
Total current liabilities   1,558     1,566  
Long-term debt 2,281 2,728
Derivatives 1 7
Deferred income taxes 1,487 1,397
Other liabilities 342 350
Equity   10,602     10,411  
$ 16,271   $ 16,459  
 
 
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per share data)
 
    Three Months Ended     Six Months Ended
June 30, June 30,
  2017         2016     2017         2016  
Revenues and other income:
Oil and gas $ 768 $ 613 $ 1,577 $ 1,022
Sales of purchased oil and gas 517 395 1,001 618
Interest and other 16 6 30 13
Derivative gains (losses), net 135 (229 ) 286 (186 )
Gain on disposition of assets, net   194     1     205     3  
  1,630     786     3,099     1,470  
Costs and expenses:
Oil and gas production 147 141 288 297
Production and ad valorem taxes 51 36 99 65
Depletion, depreciation and amortization 341 384 678 737
Purchased oil and gas 531 410 1,034 653
Impairment of oil and gas properties 285 32
Exploration and abandonments 26 18 59 77
General and administrative 81 80 165 154
Accretion of discount on asset retirement obligations 5 5 10 9
Interest 35 56 81 111
Other   59     67     119     154  
  1,276     1,197     2,818     2,289  
 
Income (loss) before income taxes 354 (411 ) 281 (819 )
Income tax benefit (provision)   (121 )   143     (90 )   284  
Net income (loss) attributable to common stockholders $ 233   $ (268 ) $ 191   $ (535 )
 
Basic and diluted net income (loss) per share attributable to common stockholders $ 1.36   $ (1.63 ) $ 1.11   $ (3.28 )
 
Basic and diluted weighted average shares outstanding   170     164     170     163  
 
 
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
 
    Three Months Ended     Six Months Ended
June 30, June 30,
  2017         2016     2017         2016  
Cash flows from operating activities:
Net income (loss) $ 233 $ (268 ) $ 191 $ (535 )
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization 341 384 678 737
Impairment of oil and gas properties 285 32
Impairment of inventory and other property and equipment 1 1 1 5
Exploration expenses, including dry holes 8 18 40
Deferred income taxes 121 (143 ) 90 (284 )
Gain on disposition of assets, net (194 ) (1 ) (205 ) (3 )
Accretion of discount on asset retirement obligations 5 5 10 9
Interest expense 1 5 2 9
Derivative related activity (111 ) 361 (251 ) 535
Amortization of stock-based compensation 21 23 43 44
Other noncash items 10 13 34 34
Change in operating assets and liabilities:
Accounts receivable, net (65 ) (84 ) 27 (51 )
Income taxes receivable 2 (1 ) 2 39
Inventories 8 (12 ) (11 ) (12 )
Derivatives (12 ) (12 )
Investments (1 ) 3
Other current assets 7 3 1
Accounts payable 111 109 (42 ) (60 )
Interest payable 20 36 (9 ) 20
Income taxes payable (2 ) (2 )
Other current liabilities   (39 )   (9 )   (24 )   (26 )
Net cash provided by operating activities 479 408 843 519
Net cash used in investing activities (475 ) (1,125 ) (773 ) (2,589 )
Net cash provided by (used in) financing activities   (7 )   930     (528 )   2,504  
Net increase (decrease) in cash and cash equivalents (3 ) 213 (458 ) 434
Cash and cash equivalents, beginning of period   663     1,612     1,118     1,391  
Cash and cash equivalents, end of period $ 660   $ 1,825   $ 660   $ 1,825  
 
 
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUMMARY PRODUCTION, PRICE AND MARGIN DATA
 
    Three Months Ended     Six Months Ended
June 30, June 30,
2017     2016 2017     2016
Average Daily Sales Volumes:
Oil (Bbls) 146,884 134,723 146,255 128,762
Natural gas liquids ("NGL") (Bbls) 53,268 41,223 50,066 40,227
Gas (Mcfs) 353,612 340,542 346,149 349,597
Total (BOE) 259,087 232,703 254,012 227,256
 
Average Prices:
Oil (per Bbl) $ 45.00 $ 41.43 $ 47.01 $ 35.07
NGL (per Bbl) $ 16.91 $ 14.21 $ 18.03 $ 12.32
Gas (per Mcf) $ 2.62 $ 1.67 $ 2.70 $ 1.73
Total (per BOE) $ 32.56 $ 28.95 $ 34.31 $ 24.72
    Three Months Ended June 30, 2017
Permian     Permian            
Horizontals Verticals Eagle Ford Other Assets Total
($ per BOE)
Margin Data:
Average prices $ 34.92 $ 33.39 $ 26.66 $ 20.86 $ 32.56
Production costs (2.23 ) (15.92 ) (12.30 ) (10.26 ) (6.19 )
Production and ad valorem taxes   (2.44 )   (2.41 )   (1.07 )   (1.01 )   (2.19 )
$ 30.25   $ 15.06   $ 13.29   $ 9.59   $ 24.18  
% Oil 66 % 61 % 32 % 12 % 57 %
 
 

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 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 six months ended June 30, 2017 and 2016:

    Three Months Ended     Six Months Ended
June 30, June 30,
  2017         2016     2017         2016  
(in millions)
 
Net income (loss) attributable to common stockholders $ 233 $ (268 ) $ 191 $ (535 )
Participating basic earnings   (2 )       (2 )    
Basic and diluted net income (loss) attributable to common stockholders $ 231   $ (268 ) $ 189   $ (535 )

Basic and diluted weighted average common shares outstanding were 170 million for the three and six months ended June 30, 2017, respectively, and 164 million and 163 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     Six Months Ended
June 30, June 30,
  2017         2016     2017         2016  
 
Net income (loss) $ 233 $ (268 ) $ 191 $ (535 )
Depletion, depreciation and amortization 341 384 678 737
Exploration and abandonments 26 18 59 77
Impairment of oil and gas properties 285 32
Impairment of inventory and other property and equipment 1 1 1 5
Accretion of discount on asset retirement obligations 5 5 10 9
Interest expense 35 56 81 111
Income tax (benefit) provision 121 (143 ) 90 (284 )
Gain on disposition of assets, net (194 ) (1 ) (205 ) (3 )
Derivative related activity (111 ) 361 (251 ) 535
Amortization of stock-based compensation 21 23 43 44
Other   10     13     34     34  
EBITDAX (a) 488 449 1,016 762
Cash interest expense   (34 )   (51 )   (79 )   (102 )
Discretionary cash flow (b) 454 398 937 660
Cash exploration expense (18 ) (18 ) (41 ) (37 )
Changes in operating assets and liabilities   43     28     (53 )   (104 )
Net cash provided by operating activities $ 479   $ 408   $ 843   $ 519  

_____________

(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 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 noncash MTM derivative gains and usual 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, provide 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 financial 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 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 income attributable to common stockholders for the three months ended June 30, 2017, as determined in accordance with GAAP, to adjusted income excluding 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 $ 233 $ 1.36
Noncash MTM derivative gains, net ($111 million pretax)   (71 )   (0.42 )

Adjusted income excluding noncash MTM derivative gains

162 0.94
Gain on sale of Martin County acreage ($194 million pretax)   (124 )   (0.73 )
Adjusted income excluding noncash MTM derivative gains and unusual items $ 38   $ 0.21  
 
 
PIONEER NATURAL RESOURCES COMPANY
SUPPLEMENTAL INFORMATION
 
Open Commodity Derivative Positions as of July 28, 2017
(Volumes are average daily amounts)
 
    2017     Year Ending December 31,
Third     Fourth    
Quarter Quarter 2018 2019
 
Average Daily Oil Production Associated with Derivatives (Bbl):
Collar contracts:
Volume 6,000 6,000
NYMEX price:
Ceiling $ 70.40 $ 70.40 $ $
Floor $ 50.00 $ 50.00 $ $
Collar contracts with short puts:
Volume 147,000 155,000 97,000
NYMEX price:
Ceiling $ 62.03 $ 62.12 $ 58.94 $
Floor $ 49.81 $ 49.82 $ 48.71 $
Short put $ 41.07 $ 41.02 $ 38.66 $
Average Daily NGL Production Associated with Derivatives:
Butane collar contracts with short puts (a):
Volume (Bbl) 2,000
Index price:
Ceiling $ 36.12 $ $ $
Floor $ 29.25 $ $ $
Short put $ 23.40 $ $ $
Ethane collar contracts (b):
Volume (Bbl) 3,000 3,000
Index price:
Ceiling $ 11.83 $ 11.83 $ $
Floor $ 8.68 $ 8.68 $ $
Ethane basis swap contracts (c):
Volume (MMBtu) 6,920 6,920 6,920 6,920
Price differential $ 1.60 $ 1.60 $ 1.60 $ 1.60
Average Daily Gas Production Associated with Derivatives (MMBtu):
Collar contracts with short puts:
Volume 290,000 300,000 62,329
NYMEX price:
Ceiling $ 3.57 $ 3.60 $ 3.56 $
Floor $ 2.95 $ 2.96 $ 2.91 $
Short put $ 2.47 $ 2.47 $ 2.37 $
Basis swap contracts:
Mid-Continent index swap volume (d) 45,000 45,000
Price differential ($/MMBtu) $ (0.32 ) $ (0.32 ) $ $
Permian Basin index swap volume (e) 6,739 26,522 51,671
Price differential ($/MMBtu) $ 0.26 $ 0.30 $ 0.30 $

_____________

(a)   Represent collar contracts with short puts that reduce the price volatility of butane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices.
(b) Represent collar contracts that reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices.
(c) 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.
(d) 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.
(e) 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.
 

Diesel derivatives. Periodically, the Company enters into diesel derivative swap contracts to mitigate fuel price risk. The diesel derivative swap contracts are priced at an index that is highly correlated to the prices that the Company incurs to fuel drilling rigs and its fracture stimulation fleet equipment. As of July 28, 2017, the Company was party to diesel derivative swap contracts for 1,000 Bbls per day for the remainder of July 2017 at an average per Bbl fixed price of $63.00. In July 2017, the Company terminated its diesel derivative swap contracts for August through December 2017 for cash proceeds of $321 thousand.

Interest rate derivatives. As of July 28, 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.

 
 

Derivative Gains, Net

(in millions)

The following table summarizes net derivative gains that the Company recorded in earnings for the three and six months ended June 30, 2017:

    Three Months Ended     Six Months Ended
June 30, 2017 June 30, 2017
Noncash changes in fair value:
Oil derivative gains $ 103 $ 220
NGL derivative gains 3
Gas derivative gains 10 29
Diesel derivative losses (1 )
Interest rate derivative losses   (1 )   (1 )
Total noncash derivative gains, net   111     251  
 
Net cash receipts on settled derivative instruments:
Oil derivative receipts 21 33
NGL derivative receipts 1 1
Gas derivative receipts 1
Diesel derivative receipts   1     1  
Total cash receipts on settled derivative instruments, net   24     35  
Total derivative gains, net $ 135   $ 286  

Source: Pioneer Natural Resources Company

Pioneer Natural Resources
Investors
Frank Hopkins, 972-969-4065
or
Trey Muir, 972-969-3674
or
Media and Public Affairs
Tadd Owens, 972-969-5760
or
Robert Bobo, 972-969-4020

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