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Pioneer Natural Resources Reports Second Quarter 2016 Financial and Operating Results

DALLAS--(BUSINESS WIRE)--Jul. 27, 2016-- Pioneer Natural Resources Company (NYSE:PXD) (“Pioneer” or “the Company”) today reported financial and operating results for the quarter ended June 30, 2016.

Pioneer reported a second quarter net loss attributable to common stockholders of $268 million, or $1.63 per diluted share. Without the effect of noncash mark-to-market derivative losses, adjusted results for the second quarter were a net loss of $37 million after tax, or $0.22 per diluted share.

Second quarter and other recent highlights included:

  • producing 233 thousand barrels oil equivalent per day (MBOEPD), of which 58% was oil; production grew by 11 MBOEPD, or 5%, compared to the first quarter of 2016, and was significantly above Pioneer’s second quarter production guidance range of 224 MBOEPD to 229 MBOEPD; oil production grew by 12 thousand barrels oil per day, or 10%, compared to the first quarter of 2016; second quarter production growth was driven by the Company’s Spraberry/Wolfcamp horizontal drilling program;
  • placing 69 horizontal wells on production in the Spraberry/Wolfcamp during the second quarter, with 37 wells benefiting from Pioneer’s Version 3.0 completion optimization program; early production results from the Version 3.0 wells are encouraging;
  • continuing to realize significant capital efficiency gains in the Spraberry/Wolfcamp where the Company’s completion optimization program and the extension of lateral lengths are enhancing well productivity, while drilling and completion efficiency gains and cost reduction initiatives are driving down the cost per lateral foot to drill and complete wells;
  • reducing production cost per barrel oil equivalent (BOE) by 26% from the first six months of 2015 to the first six months of 2016; and
  • signing a purchase agreement to acquire approximately 28,000 net acres in the Midland Basin from Devon for $435 million; substantially all of this acreage is in the core of the Midland Basin with approximately 15,000 net acres located in the prolific Sale Ranch area in Martin County and northern Midland County; the closing of this transaction is expected during the third quarter of 2016.

Pioneer’s latest outlook is summarized below:

  • planning to increase the Company’s horizontal rig count from 12 rigs to 17 rigs in the northern Spraberry/Wolfcamp during the second half of 2016; the first rig is expected to be added in September followed by two rigs in October and two rigs in November; three of the additional rigs will be dedicated to drill locations being acquired in the Sale Ranch area once well locations are permitted;
  • increasing the 2016 capital budget from $2.0 billion to $2.1 billion to cover the cost of the five horizontal drilling rigs being added during the second half of the year;
  • increasing the Company’s 2016 production growth forecast from 12%+ to 13%+ to reflect improving Spraberry/Wolfcamp well productivity; no incremental production is expected until 2017 from the five additional rigs being added during the second half of 2016;
  • expecting 17 rigs to deliver production growth ranging from 13% to 17% in 2017; and
  • funding the 2017 capital program with a strong investment grade balance sheet, a strong derivatives position and forecasted cash flow assuming mid-July strip prices.

Chairman and CEO Scott D. Sheffield stated, “The performance from our Spraberry/Wolfcamp horizontal drilling program continues to be outstanding. Our strong balance sheet, derivatives position and improving capital efficiency are allowing us to continue to grow and bring forward the inherent net asset value associated with this world class asset during a period of low commodity prices. We are on a trajectory to deliver compound annual production growth of approximately 15% while maintaining a net debt-to-operating cash flow ratio below 1.0 times through 2020 at mid-July strip prices. We also expect to spend within cash flow in 2018 assuming an oil price of approximately $55 per barrel.”

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 13,000 feet.

The Company placed 69 horizontal wells on production in the Spraberry/Wolfcamp during the second quarter of 2016, nine wells above the forecasted level for the second quarter. Of the 69 wells, 49 wells were in the northern portion of the play (33 Wolfcamp B, seven Wolfcamp A, eight Lower Spraberry Shale and one Jo Mill Shale) and 20 wells were in the southern Wolfcamp joint venture area (20 Wolfcamp B). Thirty-seven wells benefited from Pioneer’s Version 3.0 completion optimization program.

The completion optimization program combines longer laterals with optimized stage length, 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 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 second quarter of 2016, Pioneer commenced testing further enhanced completion designs (Version 3.0), which includes 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 adds $500 thousand to $1 million per well compared to Version 2.0. The initial Version 3.0 program is expected to test approximately 80 wells during 2016. The 37 Version 3.0 wells placed on production in the second quarter were the first wells in Pioneer’s completion optimization program to test Version 3.0 completions.

Pioneer’s completion optimization program is continuing to deliver strong well performance across the Company’s northern acreage and in the southern Wolfcamp joint venture area. One hundred and fifty wells have been placed on production since the middle of 2015 utilizing the Version 2.0 design. Of the 150 wells, 110 wells were in the Wolfcamp B and are delivering a productivity improvement averaging 35% above a 1 million barrels oil equivalent (MMBOE) estimated ultimate recovery (EUR) type curve in the northern area (87 wells) and 25% above a 1 MMBOE EUR type curve in the southern Wolfcamp joint venture area (23 wells). In the Wolfcamp A, 16 wells have been placed on production using the Version 2.0 design since the middle of 2015. In the northern area, 15 Wolfcamp A wells are delivering a productivity improvement averaging 25% above a 1 MMBOE EUR type curve. One Wolfcamp A well has been placed on production in the southern Wolfcamp joint venture area, with production from this well tracking a 1 MMBOE EUR type curve until recently when it began to outperform the curve. Twenty-four Lower Spraberry Shale wells have been placed on production in the northern area using the Version 2.0 design and have shown an average 10% productivity improvement above a 1 MMBOE EUR type curve.

The Company initiated an 80-well program in the second quarter to test the larger Version 3.0 completion design. Thirty-seven wells were placed on production during the second quarter, of which 32 wells were in the Wolfcamp B (14 wells in the northern area and 18 wells in the southern Wolfcamp joint venture area) and five wells were in the Wolfcamp A (all in the northern area). Early production rates from these 37 wells are exceeding Version 2.0 wells after the chokes on the wells were fully opened. Choke management is being utilized on these wells and most Version 2.0 wells to minimize the capital spent on water disposal infrastructure. The remaining 43 wells in the Version 3.0 test program are expected to be placed on production during the second half of 2016.

The drilling and completion cost per perforated lateral foot for all horizontal Wolfcamp B wells placed on production (includes completion optimized wells and non-optimized wells) in the northern Spraberry/Wolfcamp area averaged $850 per foot in the second quarter of 2016, a decrease of 35% from the fourth quarter of 2014. This decrease reflects service cost reduction initiatives and efficiency gains, especially when considering the use of the more expensive Version 2.0 and Version 3.0 completion designs over the past 12 months (incremental $0.5 million per well and incremental $1.0 million to $1.5 million per well, respectively, compared to Version 1.0 completions). During the second quarter, Pioneer’s horizontal drilling and completion costs averaged $7.2 million for Wolfcamp B interval wells, $6.7 million for Wolfcamp A interval wells and $6.9 million for Lower Spraberry Shale interval wells. These wells had average lateral lengths ranging from 8,500 feet to 9,200 feet.

Pioneer continues to expect to place approximately 230 horizontal wells on production in the Spraberry/Wolfcamp area during 2016. Of these wells, approximately 190 wells will be in the northern area and 40 wells will be in the southern Wolfcamp joint venture area. Approximately 60% of the wells will be drilled in the Wolfcamp B, 25% in the Wolfcamp A and 15% in the Lower Spraberry Shale. The current cost to drill and complete a horizontal well has been reduced to approximately $7.0 million on average for all intervals, reflecting average perforated lateral lengths of approximately 9,000 feet and utilization of a combination of Version 3.0 and Version 2.0 optimized completion designs. Production costs for Pioneer’s horizontal Spraberry/Wolfcamp wells have been reduced to $4.00 to $6.00 per BOE per well (includes lease operating expenses ranging from $2.00 to $4.00 per BOE and production and ad valorem taxes of approximately $2.00 per BOE). The reduction in drilling and completion costs and production costs is a result of Pioneer’s ongoing efficiency gains and cost reduction initiatives.

The drilling program in the northern Spraberry/Wolfcamp area is expected to continue to deliver internal rates of return ranging from 45% to 60% assuming mid-July strip commodity prices and Version 2.0 completions. These returns, which include tank battery and saltwater disposal facility costs, are benefiting from ongoing cost reduction efforts, drilling and completion efficiency gains and well productivity improvements.

The Company’s horizontal drilling program continues to drive production growth, with total Spraberry/Wolfcamp area production growing by 18 MBOEPD, or 12%, in the second quarter of 2016 compared to the first quarter of 2016. Oil production grew 15% in the second quarter and represented 70% of second quarter Spraberry/Wolfcamp production on a BOE basis. Horizontal production grew to 69% of total Spraberry/Wolfcamp production, with vertical production declining to 31%. Second quarter production benefited from the completion optimization program and the timing of wells placed on production due to efficiency gains. The Company continued to reject ethane during the second quarter due to weak market conditions, which negatively impacted production by approximately 5 MBOEPD.

Pioneer is increasing its forecasted 2016 growth rate for the Spraberry/Wolfcamp from 33%+ to 34%+ as a result of improving well productivity. Oil production growth is also expected to increase from 33%+ to 34%+ this year. The Company assumes that it will continue to reject approximately 5 MBOEPD of ethane over the remainder of 2016 based on weak market conditions.

For the third quarter of 2016, the Company expects to place approximately 50 horizontal wells on production, down from the 69 wells placed on production in the second quarter. It also expects to place more wells on production utilizing choke management in order to minimize the capital spent on water disposal infrastructure. Additionally, the Company expects shut-in volumes associated with offset fracture stimulations to be approximately 35% greater in the third quarter than the second quarter.

2016 Capital Program

The Company’s capital budget for 2016 was increased from $2.0 billion to $2.1 billion during the second quarter (excluding acquisitions, asset retirement obligations, capitalized interest and geological and geophysical G&A) to reflect the cost of adding five rigs in the northern Spraberry/Wolfcamp during the second half of the year. The budget includes $1.95 billion for drilling-and-completions-related activities, including tank batteries/saltwater disposal facilities and gas processing facilities, and $150 million for vertical integration, systems upgrades and field facilities.

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

  • Northern Spraberry/Wolfcamp – $1,810 million (includes $1,540 million for the horizontal drilling program, $160 million for tank batteries/saltwater disposal facilities, $45 million for gas processing facilities and $65 million for land, science and other);
  • Southern Wolfcamp joint venture area (net of carry) – $60 million (includes $45 million for the horizontal drilling program, $10 million for tank batteries/saltwater disposal facilities and $5 million for land and other);
  • Eagle Ford Shale$60 million (includes $30 million for the horizontal drilling program and $30 million for compression, land and other); and
  • Other assets – $20 million.

The Company also signed a purchase agreement to acquire approximately 28,000 net acres in the Midland Basin from Devon for $435 million. Substantially all of the acquired acreage is in the core of the Midland Basin with approximately 15,000 net acres located in the prolific Sale Ranch area in Martin County and northern Midland County. Closing of this transaction is expected during the third quarter of 2016.

The 2016 capital budget and acquisition are expected to be funded from forecasted operating cash flow of $1.5 billion based on average 2016 estimated prices of $43.50 per barrel for oil and $2.45 per thousand cubic feet (MCF) for gas, cash on hand at the end of the second quarter and the final cash payment of $500 million that was received in early July from the sale of the Eagle Ford Shale midstream business in 2015. Pioneer had a net debt-to-forecasted 2016 operating cash flow at the end of the second quarter of 0.2 times and net debt-to-book capitalization was 3%.

The Company now expects to deliver production growth of 13%+ in 2016 compared to 2015 based on the above capital program. This growth reflects Spraberry/Wolfcamp area production growing by 34%+, partially offset by declines of approximately 25% in the Eagle Ford Shale and 10% across Pioneer’s other assets.

Second Quarter 2016 Financial Review

Sales volumes for the second quarter of 2016 averaged 233 MBOEPD. Oil sales averaged 135 thousand barrels per day (MBPD), NGL sales averaged 41 MBPD and gas sales averaged 341 million cubic feet per day.

The average realized price for oil was $41.43 per barrel. The average realized price for NGLs was $14.21 per barrel, and the average realized price for gas was $1.67 per MCF. These prices exclude the effects of derivatives.

Production costs averaged $8.36 per BOE. Depreciation, depletion and amortization (DD&A) expense averaged $18.14 per BOE. Exploration and abandonment costs were $18 million, including $1 million of drilling, acreage and other abandonments and $17 million of personnel costs. General and administrative expense totaled $80 million and interest expense was $56 million. Other expense was $67 million, including (i) $25 million of charges associated with excess firm gathering and transportation commitments, (ii) $16 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 and (iii) $11 million of stacked drilling rig charges.

Third Quarter 2016 Financial Outlook

The Company’s third quarter 2016 outlook for certain operating and financial items is provided below.

Production is forecasted to average 232 MBOEPD to 237 MBOEPD.

Production costs are expected to average $8.25 per BOE to $10.25 per BOE. DD&A expense is expected to average $17.50 per BOE to $19.50 per BOE. Total exploration and abandonment expense is forecasted to be $20 million to $30 million.

General and administrative expense is expected to be $78 million to $83 million. Interest expense is expected to be $45 million to $50 million, reflecting the repayment of $455 million of senior notes that matured in mid-July. Other expense is forecasted to be $65 million to $75 million and is expected to include (i) $28 million to $33 million of charges associated with excess firm gathering and transportation commitments, (ii) $15 million to $20 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 and (iii) $7 million to $12 million of charges for stacked drilling rigs. 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, July 28, 2016, at 9:00 a.m. Central Time, Pioneer will discuss its financial and operating results for the quarter ended June 30, 2016, with an accompanying presentation. Instructions for listening to the call and viewing the accompanying presentation are shown below.

Website: www.pxd.com
Select “Investors,” then “Earnings & Webcasts” to listen to the discussion, view the presentation and see other related material.

Telephone: Dial (888) 378-4361 and use confirmation code 4953729 five minutes before the call. View the presentation via Pioneer’s website address above.

A replay of the webcast will be archived on Pioneer’s website. A telephone replay will be available through August 22, 2016, at https://jsp.premiereglobal.com/webrsvp/. Enter confirmation code 4953729.

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 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 acquisitions, 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, derivative contracts and the purchasers of Pioneer’s oil, NGL 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 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 COMPANY
 
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions)
 
   

June 30,
2016

   

December 31,
2015

ASSETS
Current assets:
Cash and cash equivalents $ 1,825 $ 1,391
Short-term investments 1,473
Accounts receivable, net 434 385
Income taxes receivable 4 43
Inventories 165 155
Prepaid expenses 18 17
Notes receivable 501 498
Derivatives 273 694
Other   6     11  
Total current assets   4,699     3,194  
 
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting 17,683 16,800
Accumulated depletion, depreciation and amortization   (7,491 )   (6,778 )
Total property, plant and equipment   10,192     10,022  
 
Long-term investments 23
Goodwill 272 272
Other property and equipment, net 1,525 1,523
Derivatives 12 64
Other assets, net   85     79  
 
$ 16,808   $ 15,154  
 
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable $ 741 $ 883
Interest payable 84 65
Income taxes payable 2
Current portion of long-term debt 939 448
Derivatives 8
Other   59     64  
Total current liabilities   1,831     1,462  
 
Long-term debt 2,725 3,207
Derivatives 43 1
Deferred income taxes 1,494 1,776
Other liabilities 329 333
Equity   10,386     8,375  
 
$ 16,808   $ 15,154  
 
 
PIONEER NATURAL RESOURCES COMPANY
 
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per share data)
 
   

Three Months Ended
June 30,

   

Six Months Ended
June 30,

  2016         2015     2016         2015  
Revenues and other income:
Oil and gas $ 613 $ 596 $ 1,022 $ 1,113
Sales of purchased oil and gas 395 236 618 339
Interest and other 6 7 13 14
Derivative gains (losses), net (229 ) (197 ) (186 ) 44
Gain on disposition of assets, net   1     2     3     3  
  786     644     1,470     1,513  
Costs and expenses:
Oil and gas production 141 163 297 343
Production and ad valorem taxes 36 37 65 76
Depletion, depreciation and amortization 384 329 737 639
Purchased oil and gas 410 237 653 345
Impairment of oil and gas properties 32 138
Exploration and abandonments 18 28 77 54
General and administrative 80 83 154 165
Accretion of discount on asset retirement obligations 5 3 9 6
Interest 56 46 111 92
Other   67     58     154     107  
  1,197     984     2,289     1,965  
 
Loss from continuing operations before income taxes (411 ) (340 ) (819 ) (452 )
Income tax benefit   143     123     284     160  
Loss from continuing operations (268 ) (217 ) (535 ) (292 )
Loss from discontinued operations, net of tax       (1 )       (4 )
Net loss attributable to common stockholders $ (268 ) $ (218 ) $ (535 ) $ (296 )
 
Basic and diluted earnings per share attributable to common stockholders:
Loss from continuing operations $ (1.63 ) $ (1.45 ) $ (3.28 ) $ (1.95 )
Loss from discontinued operations       (0.01 )       (0.03 )
Net loss $ (1.63 ) $ (1.46 ) $ (3.28 ) $ (1.98 )
 
Basic and diluted weighted average shares outstanding   164     149     163     149  
 
 
PIONEER NATURAL RESOURCES COMPANY
 
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
 
    Three Months Ended
June 30,
    Six Months Ended
June 30,
  2016         2015     2016         2015  
Cash flows from operating activities:
Net loss $ (268 ) $ (218 ) $ (535 ) $ (296 )
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and amortization 384 329 737 639
Impairment of oil and gas properties 32 138
Impairment of inventory and other property and equipment 1 3 5 9
Exploration expenses, including dry holes 10 40 15
Deferred income taxes (143 ) (124 ) (284 ) (161 )
Gain on disposition of assets, net (1 ) (2 ) (3 ) (3 )
Accretion of discount on asset retirement obligations 5 3 9 6
Discontinued operations (3 )
Interest expense 5 4 9 9
Derivative related activity 361 347 535 312
Amortization of stock-based compensation 23 25 44 47
Other 14 (6 ) 36 (6 )
Change in operating assets and liabilities:
Accounts receivable, net (84 ) (47 ) (51 ) 49
Income taxes receivable (1 ) 39 1
Inventories (12 ) (10 ) (12 ) (44 )
Prepaid expenses 2 4 (1 ) (1 )
Derivatives (12 ) (12 )
Other current assets 1 (1 ) 1 (8 )
Accounts payable 109 (25 ) (60 ) (275 )
Interest payable 36 42 20 22
Income taxes payable (2 ) (1 ) (2 ) (1 )
Other current liabilities   (9 )   (6 )   (26 )   (17 )
Net cash provided by operating activities 409 327 521 432
Net cash used in investing activities (1,125 ) (489 ) (2,589 ) (1,206 )
Net cash provided by (used in) financing activities   929     (2 )   2,502     (32 )
Net increase (decrease) in cash and cash equivalents 213 (164 ) 434 (806 )
Cash and cash equivalents, beginning of period   1,612     383     1,391     1,025  
Cash and cash equivalents, end of period $ 1,825   $ 219   $ 1,825   $ 219  
 
 
PIONEER NATURAL RESOURCES COMPANY
 
UNAUDITED SUMMARY PRODUCTION, PRICE AND MARGIN DATA
 
    Three Months Ended
June 30,
    Six Months Ended
June 30,
2016     2015 2016     2015
Average Daily Sales Volumes:
Oil (Bbls) 134,723 100,569 128,762 99,567
Natural gas liquids ("NGL") (Bbls) 41,223 36,659 40,227 36,015
Gas (Mcfs) 340,542 356,391 349,597 357,901
Total (BOEs) 232,703 196,626 227,256 195,232
 
Average Prices:
Oil (per Bbl) $ 41.43 $ 51.64 $ 35.07 $ 47.40
NGL (per Bbl) $ 14.21 $ 14.03 $ 12.32 $ 14.50
Gas (per Mcf) $ 1.67 $ 2.37 $ 1.73 $ 2.53
Total (BOE) $ 28.95 $ 33.32 $ 24.72 $ 31.50
 
 
    Three Months Ended June 30, 2016

Permian
Horizontals

   

Permian
Verticals

    Eagle Ford     Other Assets     Total
($ per BOE)

Margin Data:

Average prices $ 34.34 $ 29.73 $ 22.67 $ 14.02 $ 28.95
Production costs (2.25 ) (12.35 ) (9.80 ) (10.19 ) (6.66 )
Production and ad valorem taxes   (1.88 )   (2.27 )   (1.21 )   (0.62 )   (1.70 )
$ 30.21   $ 15.11   $ 11.66   $ 3.21   $ 20.59  
% Oil 74 % 62 % 35 % 16 % 58 %
 
 

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 loss per share attributable to common stockholders is computed as (i) net 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 loss per share attributable to common stockholders is computed as (i) basic net 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 not 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 and six months ended June 30, 2016 and 2015:

       
Three Months Ended
June 30,
Six Months Ended
June 30,
  2016         2015     2016         2015  
(in millions)
 
Net loss attributable to common stockholders $ (268 ) $ (218 ) $ (535 ) $ (296 )
Participating basic earnings                
Basic and diluted net loss attributable to common stockholders $ (268 ) $ (218 ) $ (535 ) $ (296 )
 

Basic and diluted weighted average common shares outstanding were 164 million and 163 million for the three and six months ended June 30, 2016, respectively, and 149 million for both the three and six months ended June 30, 2015.

 
 

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
June 30,
Six Months Ended
June 30,
  2016         2015     2016         2015  
 
Net loss $ (268 ) $ (218 ) $ (535 ) $ (296 )
Depletion, depreciation and amortization 384 329 737 639
Exploration and abandonments 18 28 77 54
Impairment of oil and gas properties 32 138
Impairment of inventory and other property and equipment 1 3 5 9
Accretion of discount on asset retirement obligations 5 3 9 6
Interest expense 56 46 111 92
Income tax benefit (143 ) (123 ) (284 ) (160 )
Gain on disposition of assets, net (1 ) (2 ) (3 ) (3 )
Loss from discontinued operations, net of tax 1 4
Derivative related activity 361 347 535 312
Amortization of stock-based compensation 23 25 44 47
Other   14     (6 )   36     (6 )
 
EBITDAX (a) 450 433 764 836
 
Cash interest expense (51 ) (42 ) (102 ) (83 )
Current income tax provision       (1 )       (1 )
 
Discretionary cash flow (b) 399 390 662 752
 
Discontinued operations cash activity (1 ) (7 )
Cash exploration expense (18 ) (18 ) (37 ) (39 )
Changes in operating assets and liabilities   28     (44 )   (104 )   (274 )
Net cash provided by operating activities $ 409   $ 327   $ 521   $ 432  

_____________

(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 noncash 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 losses, as presented in this press release, is presented and reconciled to Pioneer's net loss attributable to common stockholders (determined in accordance with GAAP) because Pioneer believes that this non-GAAP financial measure reflects an additional way of viewing aspects of Pioneer's business that, when viewed together with its financial results computed in accordance with GAAP, provides a more complete understanding of factors and trends affecting its historical financial performance and future operating results, greater transparency of underlying trends and greater comparability of results across periods. In addition, management believes that this non-GAAP measure may enhance investors' ability to assess Pioneer's historical and future financial performance. This non-GAAP financial measure is not intended to be a substitute for the comparable GAAP measure and should be read only in conjunction with Pioneer's consolidated financial statements prepared in accordance with GAAP. Noncash MTM derivative gains or losses will recur in future periods; however, the amount and frequency can vary significantly from period to period. The table below reconciles Pioneer's net loss attributable to common stockholders for the three months ended June 30, 2016, as determined in accordance with GAAP, to adjusted loss excluding noncash MTM derivative losses for that quarter.

       

After-tax
Amounts

Amounts
Per Share

 
Net loss attributable to common stockholders $ (268 ) $ (1.63 )
Noncash MTM derivative losses   231     1.41  
Adjusted loss excluding noncash MTM derivative losses $ (37 ) $ (0.22 )
 
 
PIONEER NATURAL RESOURCES COMPANY
 
SUPPLEMENTAL INFORMATION
 
Open Commodity Derivative Positions as of July 26, 2016
(Volumes are average daily amounts)
 
    2016     Year Ending December 31,

Third
Quarter

   

Fourth
Quarter

2017     2018
 
Average Daily Oil Production Associated with Derivatives (Bbl):
Collar contracts:
Volume 6,000
NYMEX price:
Ceiling $ $ $ 70.40 $
Floor $ $ $ 50.00 $
Collar contracts with short puts:
Volume 112,000 112,000 75,000
NYMEX price:
Ceiling $ 75.94 $ 75.94 $ 62.54 $
Floor $ 65.41 $ 65.41 $ 49.62 $
Short put $ 47.03 $ 47.03 $ 41.73 $
Average Daily NGL Production Associated with Derivatives (Bbl):
Propane swap contracts (a):
Volume 7,000 6,000
Price $ 21.56 $ 21.51 $ $
Ethane collar contracts (b):
Volume 3,000
Price:
Ceiling $ $ $ 11.83 $
Floor $ $ $ 8.68 $
Ethane basis swap contracts (c):
Volume (MMBtu) 2,768 2,768
Price differential $ 0.91 $ 0.91 $ $
Average Daily Gas Production Associated with Derivatives (MMBtu):
Swap contracts:
Volume 70,000 70,000
NYMEX price $ 4.06 $ 4.06 $ $
Collar contracts with short puts:
Volume 180,000 180,000 130,000 50,000
NYMEX price:
Ceiling $ 4.01 $ 4.01 $ 3.39 $ 3.40
Floor $ 3.24 $ 3.24 $ 2.85 $ 2.75
Short put $ 2.78 $ 2.78 $ 2.41 $ 2.25
Basis swap contracts:
Gulf Coast index swap volume (d) 10,000 10,000
Price differential ($/MMBtu) $ $ $ $
Mid-Continent index swap volume (d) 15,000 15,000 45,000
Price differential ($/MMBtu) $ (0.32 ) $ (0.32 ) $ (0.32 ) $
Permian Basin index swap volume (e) 34,946 9,863
Price differential ($/MMBtu) $ $ 0.41 $ 0.37 $

_____________

(a)   Represent derivative contracts that reduce the price volatility of propane forecasted for sale by the Company at Mont Belvieu, Texas and Conway, Kansas-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 swaps fix the basis differential on a NYMEX Henry Hub (NYMEX HH) MMBtu equivalent basis. The Company will receive the NYMEX HH price plus the price differential on 2,768 MMBtu per day, which is equivalent to 1,000 Bbls per day of ethane.
(d) Represent swaps that fix the basis differentials between the index prices at which the Company sells its Gulf Coast and Mid-Continent gas, respectively, and the NYMEX HH index price used in gas swap and collar contracts with short puts.
(e) Represent swaps that fix the basis differentials between Permian Basin index prices and southern California index prices for Permian Basin gas forecasted for sale in southern California.
 

Interest rate derivatives. As of July 26, 2016, 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 1.94 percent on a notional amount of $250 million on December 15, 2017.

Marketing and basis derivative activities. 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 July 26, 2016, the Company did not have any marketing derivatives outstanding.

 
 

Derivative Losses, Net

(in millions)

The following table summarizes net derivative losses that the Company recorded in earnings for the three and six months ended June 30, 2016:

       

Three Months Ended
June 30, 2016

Six Months Ended
June 30, 2016

Noncash changes in fair value:
Oil derivative losses $ (302 ) $ (456 )
NGL derivative losses (8 ) (17 )
Gas derivative losses (44 ) (53 )
Interest rate derivative losses   (7 )   (9 )
Total noncash derivative losses, net   (361 )   (535 )
 
Net cash receipts on settled derivative instruments:
Oil derivative receipts 110 303
NGL derivative receipts 1 5
Gas derivative receipts   21     41  
Total cash derivative receipts, net   132     349  
Total derivative losses, net $ (229 ) $ (186 )
 

Source: Pioneer Natural Resources Company

Pioneer Natural Resources
Investors
Frank Hopkins, 972-969-4065
or
Michael Bandy, 972-969-4513
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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