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News Release

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

DALLAS--(BUSINESS WIRE)--May 3, 2017-- Pioneer Natural Resources Company (NYSE:PXD) (“Pioneer” or “the Company”) today reported financial and operating results for the quarter ended March 31, 2017.

Pioneer reported a first quarter net loss attributable to common stockholders of $42 million, or $0.25 per diluted share. Without the effect of noncash mark-to-market derivative gains and other unusual items, adjusted results for the first quarter were earnings of $42 million after tax, or $0.25 per diluted share.

First quarter 2017 and other recent highlights included:

  • producing 249 thousand barrels oil equivalent per day (MBOEPD), of which 59% was oil; quarterly production grew by 7 MBOEPD, or 3%, compared to the fourth quarter of 2016, and was above the top end of Pioneer’s first quarter production guidance range of 243 MBOEPD to 248 MBOEPD; the eighth consecutive quarter of production growth since the oil price collapse in late 2014; first quarter production growth was driven by the Company’s Spraberry/Wolfcamp horizontal drilling program; total Spraberry/Wolfcamp production increased 13 MBOEPD, or 7%, compared to the fourth quarter of 2016; first quarter oil production was in line with expectations while gas and NGL production was higher than expected due to lower line pressures across the field and improved NGL yields;
  • reducing production costs (excluding taxes) to $6.31 per barrel oil equivalent (BOE) in the first quarter compared to $6.42 per BOE in the fourth quarter of 2016; production costs benefited from continuing low horizontal Spraberry/Wolfcamp production costs of $2.33 per BOE for the quarter;
  • maintaining a strong balance sheet with cash on hand at the end of the first quarter of $2.4 billion (includes liquid investments); this strong cash position takes into account the repayment of a March debt maturity of $485 million from cash on hand; the Company was upgraded to mid-investment grade by all three rating agencies during the first quarter; net debt to forecasted 2017 operating cash flow was 0.2 times at the end of the first quarter and net debt to book capitalization was 3%;
  • adding derivative positions that cover approximately 85% of forecasted oil and gas production for the remainder of 2017; increasing 2018 derivative coverage to approximately 20% of forecasted oil production and 15% of forecasted gas production;
  • high-grading Pioneer’s Permian acreage position by closing the sales of approximately 5,600 net acres in Upton and Andrews counties during the first quarter for proceeds of $63 million and closing the sale of approximately 20,500 net acres in northeastern Martin County during April for proceeds of $266 million;
  • increasing the northern Spraberry/Wolfcamp horizontal rig count from 17 rigs to 18 rigs during the first quarter;
  • placing 38 horizontal wells on production in the Spraberry/Wolfcamp during the first quarter, with continuing strong performance; all of the wells benefited from Pioneer’s Version 3.0 completion optimization design; Version 3.0 wells are continuing to outperform earlier wells that utilized the Version 2.0 completion optimization design;
  • seeing encouraging results from the Jo Mill appraisal program in the Spraberry/Wolfcamp; and
  • exporting approximately one million barrels of Permian oil during the first quarter to Asia and Latin America; expect to export another one million barrels of Permian oil to Europe during the second quarter.

Pioneer’s full-year 2017 update is summarized below:

  • operating 18 horizontal rigs in the Spraberry/Wolfcamp during 2017; 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); completions in both areas will incorporate Version 3.0, with some wells testing larger completions during the year;
  • 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; the Company is currently operating two horizontal rigs and commenced completing the drilled but uncompleted wells during April;
  • transferring West Panhandle gas processing operations from the Company’s Fain plant to a third-party facility in late April;
  • forecasting production growth in 2017 ranging from 15% to 18% compared to 2016 (oil growth expected to increase 24% - 28%); Spraberry/Wolfcamp production growth is expected to be the primary contributor, with production growth ranging from 30% to 34% in 2017 compared to 2016 (Spraberry/Wolfcamp oil growth expected to increase 33% - 37%);
  • reducing the forecasted 2017 oil production percentage as a percent of total production from 62% to 60%; this reduction reflects (i) the loss of approximately 1,500 barrels oil equivalent per day (approximately 80% oil) from the aforementioned Martin County acreage sale, (ii) approximately one thousand barrels per day of light condensate production in the West Panhandle field being processed and therefore recognized as NGL production as a result of transferring the gas processing operations to a third-party facility and (iii) higher Spraberry/Wolfcamp gas and NGL recoveries;
  • expecting internal rates of return (IRRs) for the 2017 drilling program, including tank battery and saltwater disposal facility investments, ranging from 50% to 100% assuming an oil price of $55.00 per barrel and a gas price of $3.00 per thousand cubic feet (MCF);
  • maintaining capital expenditures for 2017 at $2.8 billion; capital expenditures include $2.5 billion for drilling and completion activities and $275 million for water infrastructure, vertical integration and field facilities; this capital program assumes that further efficiency gains will offset the Company’s estimated cost inflation of 5%; Pioneer’s vertical integration operations are expected to mitigate the impact of the 10% to 15% cost inflation forecasted for the industry in 2017;
  • funding the 2017 capital program from forecasted cash flow of $2.2 billion and cash on hand;
  • forecasting net debt to 2017 operating cash flow to remain below 1.0 times; and
  • evaluating offers to sell approximately 10,500 net acres in the Eagle Ford Shale.

President and CEO Timothy L. Dove stated, “Our continued focus on strong execution and efficiency gains resulted in the Company delivering another great quarter, with solid earnings, production above the top end of our first quarter guidance range, continued impressive horizontal well performance in the Spraberry/Wolfcamp and reduced production costs, excluding taxes. Oil growth in the Spraberry/Wolfcamp is on track, and we are benefiting from improved gas and NGL recoveries in the field. We are drilling high-return and highly productive wells that have us on a trajectory to deliver annual production growth ranging from 15% to 18% in 2017 and to be in a position to spend within cash flow in 2018. This assumes an oil price of $55.00 per barrel and a gas price of $3.00 per MCF.”

“We have received very positive feedback from our shareholders in response to the Company’s previously announced vision to organically grow production by 15%+ per year through 2026 and achieve a production rate of approximately one million barrels oil equivalent per day. In addition, we expect to maintain a strong balance sheet and improve corporate returns. Since innovation will be a key contributor to continuing to deliver efficiency gains, we are partnering with national labs and service companies on several technology initiatives.”

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

Pioneer’s first quarter earnings included noncash mark-to-market gains on derivatives of $90 million after tax, or $0.53 per diluted share.

First quarter earnings also included a net noncash loss of $174 million after tax, or $1.03 per diluted share, related to the following unusual items:

  • a noncash impairment charge of $182 million after tax, or $1.08 per diluted share, to reduce the carrying value of the Company’s Raton proved gas properties in southeastern Colorado as a result of the decline in long-term NYMEX strip gas prices; and
  • a deferred tax benefit of $8 million, or $0.05 per diluted share, attributable to the adoption of new accounting standards related to the vesting of long-term incentive plan awards.

Innovation

Innovation will be a key contributor to achieving Pioneer’s 10-year vision. The Company is already a technology leader in the E&P space and has been taking advantage of leading-edge technologies for many years. Examples of these technologies include:

  • geosteering;
  • oil, gas and water chemistry;
  • 3-D seismic attribute volumes;
  • microseismic;
  • mobile applications;
  • sliding sleeve completions;
  • route optimization;
  • laser-based methane leak detection; and
  • centralized field control centers (advanced SCADA systems and a field-wide water delivery system).

The Company is also focused on new technology initiatives that are expected to improve productivity. The Company is partnering with national labs and service companies to develop these solutions. Examples of these new technologies include:

  • machine learning and artificial intelligence;
  • predictive analytics;
  • automation;
  • 4-D fracture propagation modeling;
  • development and use of advanced materials (e.g., fluid end metallurgy);
  • dynamic drill string modeling;
  • real-time drilling prediction software;
  • state-of-the-art downhole tools;
  • advanced subsurface measurement (e.g., fiber optics); and
  • large-scale produced water recycling.

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. 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 38 horizontal wells on production in the Spraberry/Wolfcamp during the first quarter of 2017. All 38 wells utilized the Version 3.0 completion design. Pioneer has now placed a total of 154 Version 3.0 wells on production since early 2016 (80 Wolfcamp B wells, 57 Wolfcamp A wells and 17 Lower Spraberry Shale wells) compared to 188 wells that have been placed on production since mid-2015 utilizing the lower-intensity Version 2.0 completion design (131 Wolfcamp B wells, 20 Wolfcamp A wells and 37 Lower Spraberry Shale wells). Production from the Version 3.0 completion optimization wells is continuing to outperform the Version 2.0 wells. The incremental capital cost to complete the Version 3.0 wells of $500 thousand to $1 million per well is paying out in less than one year at current commodity prices. Of the 38 wells that were placed on production in the first quarter, 37 wells were in the northern area and one well was in the southern Wolfcamp joint venture area.

Pioneer continues to expect to place approximately 260 gross horizontal wells on production in the Spraberry/Wolfcamp during 2017. Of these wells, approximately 220 gross wells will be in the northern area and 40 gross wells will be in the southern Wolfcamp joint venture area (resulting in 244 net wells after recognizing Pioneer’s 60% interest in the wells 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 a limited appraisal program for the Clearfork, Jo Mill and Wolfcamp D intervals during 2017.

Specific to the Jo Mill appraisal program, Pioneer has been tracking the performance of five Jo Mill wells that were placed on production over the past two years in the Spraberry/Wolfcamp. The performance of these wells has been encouraging, with an average estimated ultimate recovery (EUR) of 900 thousand barrels oil equivalent for a 6,800-feet average lateral length. Six additional Jo Mill wells are planned to be placed on production during 2017 at a cost of approximately $6 million per well with an average lateral length of 10,000 feet.

As a result of the strong performance of Version 3.0 completions compared to Version 2.0 completions, the 2017 drilling program in the Spraberry/Wolfcamp is utilizing Version 3.0 completions. The Company expects EURs for the wells planned in the 2017 program to average 1.5 million barrels oil equivalent (MMBOE) for Wolfcamp B wells, 1.2 MMBOE for Wolfcamp A wells and 1.0 MMBOE for Lower Spraberry Shale wells. The expected costs to drill and complete these wells, which were confirmed by first quarter actual spending levels, are: Wolfcamp B – $8.5 million for a 10,000-foot lateral well; Wolfcamp A – $7.5 million for a 9,500-foot lateral well; and Lower Spraberry Shale$7.2 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.

The drilling program in the Spraberry/Wolfcamp is expected to deliver IRRs ranging from 50% to 100%, assuming Version 3.0 completions, an oil price of $55.00 per barrel and a gas price of $3.00 per MCF. These returns, which include tank battery and saltwater disposal facility costs, are benefiting from ongoing cost reduction initiatives, drilling and completion efficiency gains and well productivity improvements.

The Company’s Spraberry/Wolfcamp horizontal drilling program continues to drive production growth, with total Spraberry/Wolfcamp production growing by 13 MBOEPD, or 7%, in the first quarter of 2017 compared to the fourth quarter of 2016. First quarter oil production was in line with expectations while gas and NGL production was higher than expected due to lower line pressures across the field and improved NGL yields. The Company continued to reject ethane during the first quarter as a result of weak market conditions, which negatively impacted production by approximately 5 MBOEPD. Pioneer’s forecasted 2017 production growth rate for the Spraberry/Wolfcamp ranges from 30% to 34%, with oil production increasing 33% - 37%. This reflects the Company placing approximately 260 gross wells (244 net wells) on production in 2017. In the second quarter, the Company expects to place 60 to 65 wells on production, which will be weighted toward the second half of the quarter. The Company assumes that it will continue to reject ethane throughout 2017, based on continuing weak market conditions.

Spraberry/Wolfcamp Water Distribution System

Pioneer’s demand for water to support its fracture stimulation operations in the Permian Basin has more than doubled from approximately 150 thousand barrels per day (MBPD) in 2014 to approximately 350 MBPD in 2017. Water demand is expected to more than quadruple by 2026 in order to achieve the Company’s production target of one million barrels oil equivalent per day in that year. Pioneer plans to reduce its use of fresh water by utilizing additional brackish and effluent water as well as reusing produced water.

Pioneer is constructing an automated field-wide water transport system to support its growing water demand. The Company spent $300 million through 2016 for (i) partial completion of the 100-mile mainline, (ii) tie-in of the Odessa wastewater treatment system (approximately 120 MBPD), (iii) construction of subsystems/frac ponds and (iv) drilling and connecting brackish water wells near major drilling areas. Spending in 2017 is expected to be approximately $160 million, primarily for completion of the mainline and additional subsystems/frac ponds. This spending level also includes engineering capital for upgrading the Midland wastewater treatment plant. Pioneer expects to spend approximately $115 million over the 2017 through 2020 period for the Midland treatment plant upgrade. In return, the Company will receive approximately 240 MBPD of low-cost, effluent water to support its completion operations. Future development will be focused on subsystems/frac ponds, brackish water wells and the reuse of produced water. Ultimate savings for the implementation of this system is expected to be approximately $500 thousand per well.

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 will be 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 Company is currently operating two horizontal rigs and one third-party fracture stimulation fleet.

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 40% to 50%, assuming an oil price of $55.00 per barrel and a gas price of $3.00 per MCF.

Pioneer’s production from the Eagle Ford Shale averaged 22 MBOEPD in the first quarter, of which 35% was condensate, 31% 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. While the year-over-year decline is still forecasted to be approximately 40%, 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.

West Panhandle Operations

Production of 6 MBOEPD in the West Panhandle field during the first quarter reflected the impact of continuing mechanical problems at Pioneer’s Fain gas processing plant. The Company transferred its West Panhandle gas processing operations to a third-party facility in late April and is forecasting second quarter 2017 production of approximately 7 MBOEPD. As a result of this transfer, approximately 1,000 barrels per day of light condensate (oil) will be processed and therefore recognized as NGLs.

2017 Capital Program

The Company’s capital budget for 2017 remains at $2.8 billion (excluding acquisitions, asset retirement obligations, capitalized interest, geological and geophysical G&A and IT system upgrades). The budget includes $2.5 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 – $2.4 billion (includes $1.9 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.

The 2017 capital budget is expected to be funded from forecasted operating cash flow of $2.2 billion (assuming average 2017 estimated prices of $55.00 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.

First Quarter 2017 Financial Review

Sales volumes for the first quarter of 2017 averaged 249 MBOEPD. Oil sales averaged 146 MBPD, NGL sales averaged 47 MBPD and gas sales averaged 339 million cubic feet per day.

The average realized price for oil was $49.05 per barrel. The average realized price for NGLs was $19.33 per barrel, and the average realized price for gas was $2.79 per MCF. These prices exclude the effects of derivatives.

Production costs averaged $8.42 per BOE. Depreciation, depletion and amortization (DD&A) expense averaged $15.04 per BOE. Exploration and abandonment costs were $33 million, including $10 million of well costs (mechanical issues) and acreage abandonments, $6 million of seismic purchases and $17 million of personnel costs. General and administrative expense totaled $84 million. Interest expense was $46 million. Other expense was $60 million, including (i) $40 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.

Second Quarter 2017 Financial Outlook

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

Production is forecasted to average 254 MBOEPD to 259 MBOEPD.

Production costs are expected to average $7.75 per BOE to $9.75 per BOE. DD&A expense is expected to average $15.00 per BOE to $17.00 per BOE. Total exploration and abandonment expense is forecasted to be $20 million to $30 million.

General and administrative expense is expected to be $80 million to $85 million. Interest expense is expected to be $43 million to $48 million. Other expense is forecasted to be $60 million to $70 million and is expected to include (i) $40 million to $45 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 Thursday, May 4, 2017, at 9:00 a.m. Central Time, Pioneer will discuss its financial and operating results for the quarter ended March 31, 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 (877) 723-9522 and confirmation code 2536946 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 29, 2017. Click here to register for the call-in audio replay, and enter confirmation code 2536946.

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)
 
March 31, 2017 December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents $ 663 $ 1,118
Short-term investments 1,546

 

1,441
Accounts receivable, net 427 518
Income taxes receivable 3 3
Inventories 200 181
Derivatives 73 14
Other   28     23  
Total current assets   2,940     3,298  
 
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting 19,228 19,052
Accumulated depletion, depreciation and amortization   (8,546 )   (8,211 )
Total property, plant and equipment   10,682     10,841  
 
Long-term investments 168 420
Goodwill 272 272
Other property and equipment, net 1,577 1,529
Derivatives 9
Other assets, net   101     99  
 
$ 15,749   $ 16,459  
 
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable $ 802 $ 875
Interest payable 39 68
Current portion of long-term debt 485
Derivatives 9 77
Other   102     61  
Total current liabilities   952     1,566  
 
Long-term debt 2,729 2,728
Derivatives 2 7
Deferred income taxes 1,366 1,397
Other liabilities 352 350
Equity   10,348     10,411  
 
$ 15,749   $ 16,459  
 
PIONEER NATURAL RESOURCES COMPANY
 
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per share data)
 
Three Months Ended
March 31,
  2017       2016  
Revenues and other income:
Oil and gas $ 809 $ 409
Sales of purchased oil and gas 484 223
Interest and other 13 8
Derivative gains, net 151 43
Gain on disposition of assets, net   11     2  
  1,468     685  
Costs and expenses:
Oil and gas production 141 156
Production and ad valorem taxes 47 29
Depletion, depreciation and amortization 337 353
Purchased oil and gas 503 243
Impairment of oil and gas properties 285 32
Exploration and abandonments 33 59
General and administrative 84 74
Accretion of discount on asset retirement obligations 5 5
Interest 46 55
Other   60     87  
  1,541     1,093  
 
Loss before income taxes (73 ) (408 )
Income tax benefit   31     141  
Net loss attributable to common stockholders $ (42 ) $ (267 )
 
Basic and diluted net loss per share attributable to common stockholders $ (0.25 ) $ (1.65 )
Weighted average shares outstanding:
Basic   170     162  
Diluted   170     162  
 
PIONEER NATURAL RESOURCES COMPANY
 
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
 
Three Months Ended
March 31,
  2017       2016  
Cash flows from operating activities:
Net loss $ (42 ) $ (267 )
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and amortization 337 353
Impairment of oil and gas properties 285 32
Impairment of inventory and other property and equipment 4
Exploration expenses, including dry holes 10 40
Deferred income taxes (31 ) (141 )
Gain on disposition of assets, net (11 ) (2 )
Accretion of discount on asset retirement obligations 5 5
Interest expense 1 5
Derivative related activity (141 ) 175
Amortization of stock-based compensation 22 21
Other noncash items 25 17
Change in operating assets and liabilities:
Accounts receivable, net 92 33
Income taxes receivable 40
Inventories (19 )
Investments 4
Other current assets (6 ) (3 )
Accounts payable (153 ) (169 )
Interest payable (29 ) (16 )
Other current liabilities   15     (17 )
Net cash provided by operating activities 364 110
Net cash used in investing activities (298 ) (1,463 )
Net cash provided by (used in) financing activities   (521 )   1,574  
Net increase (decrease) in cash and cash equivalents (455 ) 221
Cash and cash equivalents, beginning of period   1,118     1,391  
Cash and cash equivalents, end of period $ 663   $ 1,612  
 
PIONEER NATURAL RESOURCES COMPANY
 
UNAUDITED SUMMARY PRODUCTION, PRICE AND MARGIN DATA
 
Three Months Ended
March 31,
2017     2016
Average Daily Sales Volumes:
Oil (Bbls) 145,619 122,802
Natural gas liquids ("NGL") (Bbls) 46,828 39,232
Gas (Mcfs) 338,602 358,651
Total (BOE) 248,881 221,809
 
Average Prices:
Oil (per Bbl) $ 49.05 $ 28.09
NGL (per Bbl) $ 19.33 $ 10.33
Gas (per Mcf) $ 2.79 $ 1.79
Total (per BOE) $ 36.14 $ 20.28
 
Three Months Ended March 31, 2017

Permian
Horizontals

 

Permian
Verticals

  Eagle Ford   Other Assets   Total
($ per BOE)
Margin Data:
Average prices $ 39.25 $ 37.18 $ 28.79 $ 22.13 $ 36.14
Production costs (2.33 ) (14.36 ) (10.71 ) (11.12 ) (6.31 )
Production and ad valorem taxes   (2.31 )   (2.57 )   (1.00 )   (1.09 )   (2.11 )
$ 34.61   $ 20.25   $ 17.08   $ 9.92   $ 27.72  
% Oil 69 % 62 % 35 % 12 % 59 %
 

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 loss attributable to common stockholders to basic and diluted net loss attributable to common stockholders for the three months ended March 31, 2017 and 2016:

 
Three Months Ended
March 31,
  2017       2016  
(in millions)
 
Net loss attributable to common stockholders $ (42 ) $ (267 )
Participating basic earnings        
Basic and diluted net loss attributable to common stockholders $ (42 ) $ (267 )
 

Basic and diluted weighted average common shares outstanding were 170 million for the three months ended March 31, 2017. Basic and diluted weighted average common shares outstanding were 162 million for the three months ended March 31, 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 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 loss or net cash provided by operating activities, as defined by GAAP.

 
Three Months Ended
March 31,
  2017       2016  
 
Net loss $ (42 ) $ (267 )
Depletion, depreciation and amortization 337 353
Exploration and abandonments 33 59
Impairment of oil and gas properties 285 32
Impairment of inventory and other property and equipment 4
Accretion of discount on asset retirement obligations 5 5
Interest expense 46 55
Income tax benefit (31 ) (141 )
Gain on disposition of assets, net (11 ) (2 )
Derivative related activity (141 ) 175
Amortization of stock-based compensation 22 21
Other   25     17  
 
EBITDAX (a) 528 311
 
Cash interest expense   (45 )   (50 )
 
Discretionary cash flow (b) 483 261
 
Cash exploration expense (23 ) (19 )
Changes in operating assets and liabilities   (96 )   (132 )
Net cash provided by operating activities $ 364   $ 110  

_____________

(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 loss 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 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, 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 loss attributable to common stockholders for the three months ended March 31, 2017, as determined in accordance with GAAP, to adjusted loss 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 loss attributable to common stockholders $ (42 ) $ (0.25 )
Noncash MTM derivative gains, net ($141 million pretax)   (90 )   (0.53 )
Adjusted loss excluding noncash MTM derivative gains (132 ) (0.78 )
 
Excess tax benefit from vesting of long-term incentive awards (8 ) (0.05 )
Noncash impairment of Raton proved properties ($285 million pretax)   182     1.08  
Adjusted income excluding noncash MTM derivative gains and unusual items $ 42   $ 0.25  
   
PIONEER NATURAL RESOURCES COMPANY
 
SUPPLEMENTAL INFORMATION
 
Open Commodity Derivative Positions as of May 1, 2017
(Volumes are average daily amounts)
 
2017   Year Ending December 31,

Second
Quarter

 

Third
Quarter

 

Fourth
Quarter

  2018     2019
 
Average Daily Oil Production Associated with Derivatives (Bbl):
Collar contracts:
Volume 6,000 6,000 6,000
NYMEX price:
Ceiling $ 70.40 $ 70.40 $ 70.40 $ $
Floor $ 50.00 $ 50.00 $ 50.00 $ $
Collar contracts with short puts:
Volume 129,000 147,000 155,000 46,000
NYMEX price:
Ceiling $ 61.19 $ 62.03 $ 62.12 $ 62.51 $
Floor $ 48.46 $ 49.81 $ 49.82 $ 50.11 $
Short put $ 40.45 $ 41.07 $ 41.02 $ 40.00 $
Rollfactor swap contracts (a):
Volume 20,000 20,000
NYMEX roll price $ (0.32 ) $ $ (0.32 ) $ $
Average Daily NGL Production Associated with Derivatives:
Butane collar contracts with short puts (b):
Volume (Bbl) 2,000 2,000
Index price:
Ceiling $ 36.12 $ 36.12 $ $ $
Floor $ 29.25 $ 29.25 $ $ $
Short put $ 23.40 $ 23.40 $ $ $
Ethane collar contracts (c):
Volume (Bbl) 3,000 3,000 3,000
Index price:
Ceiling $ 11.83 $ 11.83 $ 11.83 $ $
Floor $ 8.68 $ 8.68 $ 8.68 $ $
Ethane basis swap contracts (d):
Volume (MMBtu) 6,920 6,920 6,920 6,920 6,920
Price differential $ 1.60 $ 1.60 $ 1.60 $ 1.60 $ 1.60
Average Daily Gas Production Associated with Derivatives (MMBtu):
Collar contracts with short puts:
Volume 270,000 290,000 300,000 62,329
NYMEX price:
Ceiling $ 3.56 $ 3.57 $ 3.60 $ 3.56 $
Floor $ 2.95 $ 2.95 $ 2.96 $ 2.91 $
Short put $ 2.47 $ 2.47 $ 2.47 $ 2.37 $
Basis swap contracts:
Mid-Continent index swap volume (e) 45,000 45,000 45,000
Price differential ($/MMBtu) $ (0.32 ) $ (0.32 ) $ (0.32 ) $ $
Permian Basin index swap volume (f) 26,522 9,863
Price differential ($/MMBtu) $ $ $ 0.30 $ 0.30 $

_____________

(a) Represent swap contracts that fix the difference between (i) each day's price per Bbl of West Texas Intermediate oil ("WTI") for the first nearby NYMEX 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 NYMEX month less (iv) the price per Bbl of WTI for the third nearby NYMEX month, multiplied by .3333.
(b)

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.

(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 to mitigate price risk. As of May 1, 2017, the Company did not have any marketing derivatives outstanding.

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 March 31, 2017, the Company was party to diesel derivative swap contracts for 1,000 Bbls per day for the remainder of 2017 at an average per Bbl fixed price of $62.98. In early April 2017, the Company terminated its diesel derivative swap contracts that were held at March 31, 2017 for cash proceeds of $1 million. In late April 2017, the Company entered into diesel swap contracts for 1,000 Bbls per day for the remainder of 2017 at an average per Bbl fixed price of $63.00.

Interest rate derivatives. As of May 1, 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 months ended March 31, 2017:

 

Three Months Ended
March 31, 2017

Noncash changes in fair value:
Oil derivative gains $ 118
NGL derivative gains 3
Gas derivative gains 19
Diesel derivative gains   1  
Total noncash derivative gains, net   141  
 
Net cash receipts on settled derivative instruments:
Oil derivative receipts 11
Gas derivative payments   (1 )
Total cash derivative receipts, net   10  
Total derivative gains, net $ 151  

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