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| 8-K - 8-K - PIONEER NATURAL RESOURCES CO | form8-kxpxdq32016earningsr.htm |
News Release
Pioneer Natural Resources Reports Third Quarter 2016
Financial and Operating Results
Dallas, Texas, November 1, 2016 - Pioneer Natural Resources Company (NYSE:PXD) (“Pioneer” or “the Company”) today reported financial and operating results for the quarter ended September 30, 2016.
Pioneer reported third quarter net income attributable to common stockholders of $22 million, or $0.13 per diluted share. Noncash mark-to-market derivative losses were offset by an income tax benefit attributable to tax credits for research and experimental expenditures related to horizontal drilling and completions innovations, resulting in adjusted income (income after noncash mark-to-market derivative losses and unusual items) also being $22 million after tax, or $0.13 per diluted share.
Third quarter and other recent highlights included:
• | producing 239 thousand barrels oil equivalent per day (MBOEPD), of which 56% was oil; quarterly production grew by 6 MBOEPD, or 3%, compared to the second quarter of 2016, and was above Pioneer’s second quarter production guidance range of 232 MBOEPD to 237 MBOEPD; third quarter production growth was driven by the Company’s Spraberry/Wolfcamp horizontal drilling and completion optimization program; unplanned downtime at the Fain gas processing plant negatively impacted production in the West Panhandle field by approximately 2 MBOEPD; |
• | placing 46 horizontal wells on production in the Spraberry/Wolfcamp during the third quarter, as expected, with continuing strong performance; 28 wells benefited from Pioneer’s Version 3.0 completion optimization program; Version 3.0 wells are on average outperforming earlier wells that utilized Version 2.0 completion optimization; as a result, the Version 3.0 testing program for 2016 has been increased from 80 wells to approximately 100 wells; |
• | 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 6% from the second quarter of 2016 and 32% compared to the third quarter of 2015; |
• | enhancing Pioneer’s Martin County acreage position in the Midland Basin by completing the acquisition of approximately 28,000 net acres from Devon Energy for $429 million; |
• | selling Pioneer’s first two Permian oil cargoes for export to Europe during the third quarter, totaling 610 thousand barrels in aggregate; |
• | repaying a mid-July debt maturity of $455 million with cash on hand; and |
• | increasing 2017 derivatives coverage to 75% for oil and 55% for gas. |
Pioneer’s latest outlook is summarized below:
• | increasing the Company’s horizontal rig count from 12 rigs to 17 rigs in the northern Spraberry/Wolfcamp during the second half of 2016; three rigs were added during September and October, as planned, with two additional rigs expected in November; |
• | maintaining the 2016 capital budget at $2.1 billion; |
• | increasing the Company’s 2016 production growth forecast from 13%+ to 14%+ 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 for the 2017 capital program is expected to be provided by forecasted cash flow (assuming late-October strip prices), a strong derivatives position and a strong investment grade balance sheet. |
Chairman and CEO Scott D. Sheffield stated, “The Company delivered another great quarter, with solid earnings, production above the top end of our third-quarter guidance range and continued impressive horizontal well performance in the Spraberry/Wolfcamp. Our strong financial position and improving capital efficiency are allowing us to continue to drill high-return wells, grow production and bring forward the inherent net asset value associated with this world class asset during a period of relatively low commodity prices. We are on a trajectory to deliver compound annual production and cash flow growth through 2020 of approximately 15% and 25%, respectively, while maintaining a net debt-to-operating cash flow ratio below 1.0 times assuming late-October strip prices. We also expect to spend within cash flow in 2018, assuming an oil price of approximately $55 per barrel.”
“As was announced previously, I will be retiring as the CEO of Pioneer at the end of this year. I am proud and honored to have led a Company that has become the premier oil shale resource company in the United States with excellent assets, a strong balance sheet and an outstanding management team. I want to personally thank all of our employees for their hard work and dedication in building this great Company that is well-positioned for the future.”
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 placed 46 horizontal wells on production in the Spraberry/Wolfcamp during the third quarter of 2016, as expected. Of the 46 wells, 40 wells were in the northern portion of the play (19 Wolfcamp B, 10 Wolfcamp A, 10 Lower Spraberry Shale and one Jo Mill Shale) and six wells were in the southern Wolfcamp joint venture area (all Wolfcamp B wells). Twenty-eight 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 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 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 number of wells testing Version 3.0 completions during 2016 has been increased from 80 wells to approximately 100 wells based on the success of the 70 Version 3.0 completion wells that have been placed on production during the first nine months of 2016.
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 sixty-one wells have been placed on production since the middle of 2015 utilizing the Version 2.0 design. Of the 161 wells, 115 wells were in the Wolfcamp B and are delivering productivity improvements ranging from an average of 25% in the southern Wolfcamp joint venture area (24 wells) to an average of 35% in the northern area (91 wells) above a one million barrels oil equivalent (MMBOE) estimated ultimate recovery (EUR) type curve. In the Wolfcamp A, 13 wells have been placed on production using the Version 2.0 design since the middle of 2015. In the northern area, 12 Wolfcamp A wells are delivering productivity improvements that are 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 above a 1 MMBOE EUR type curve. Thirty-three Lower Spraberry Shale wells have been placed on production in the northern area using the Version 2.0 design and show an average 10% productivity improvement above a 1 MMBOE EUR type curve.
The Company initiated a program in early 2016 to test the larger Version 3.0 completion design. Seventy wells were placed on production during the first nine months of the year, of which 52 wells were in the Wolfcamp B (29 wells in the northern area and 23 wells in the southern Wolfcamp joint venture area) and 18 wells were in the Wolfcamp A (all in the northern area). Early production rates from these 70 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 optimize the use of existing water disposal infrastructure. The remaining 30 wells in the Version 3.0 test program are expected to be placed on production during the fourth quarter 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 $840 per foot in the third quarter of 2016, a decrease of 35% from the fourth quarter of 2014. This decrease reflects service cost reduction initiatives and efficiency gains, and includes the use of more expensive Version 2.0 and Version 3.0 completion designs over the past 15 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 third quarter, Pioneer’s horizontal drilling and completion costs averaged $8.0 million for Wolfcamp B interval wells, $5.8 million for Wolfcamp A interval wells and $6.5 million for Lower Spraberry Shale interval wells. These wells had average perforated lateral lengths ranging from 7,100 feet to 9,500 feet.
Production data from IHS Performance Evaluator (a third-party source) continues to show that Pioneer is consistently drilling the most productive horizontal wells in the Midland Basin. For the period from September 2015 through June 2016, Pioneer’s three-month cumulative oil production averaged approximately 55,000 barrels per well from the approximately 150 wells reported for Pioneer. For the same period, the average three-month cumulative oil production for 14 peers operating in the Midland Basin ranged from approximately 25,000 barrels per well to 50,000 barrels per well. These peers also drilled fewer than half the number of wells that Pioneer did during this period. Pioneer’s leading well productivity in the Midland Basin highlights the Company’s core acreage position, contiguous leasehold that allows for drilling longer laterals, scale of operations, repeatability of well performance and the benefits being delivered by the completion optimization program.
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 are averaging $4.00 per BOE per well (including lease operating expenses of
approximately $2.00 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 50% to 65%, assuming late-October strip commodity prices and a combination of Version 2.0 and Version 3.0 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 production growing by 12 MBOEPD, or 7%, in the third quarter of 2016 compared to the second quarter of 2016. Oil production grew 3% in the third quarter and represented 67% of third quarter Spraberry/Wolfcamp production on a BOE basis. Horizontal production grew to 72% of total Spraberry/Wolfcamp production, with vertical production declining to 28%. The Company continued to reject ethane during the third 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 34%+ to 36%+ as a result of improving well productivity. Oil production growth is also expected to increase from 34%+ to 38%+ 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 fourth quarter of 2016, Pioneer expects to place approximately 60 horizontal wells on production, up from the 46 wells placed on production in the third quarter. The timing of these wells being placed on production is expected to be weighted toward the second half of the quarter. The Company also expects to continue to place wells on production utilizing choke management in order to optimize the use of water disposal infrastructure.
West Panhandle Operations
Production in the West Panhandle field was 7 MBOEPD in the third quarter, approximately 2 MBOEPD below the expected level for this period. Production was negatively impacted beginning in late August by unplanned downtime at Pioneer’s Fain gas processing plant resulting from mechanical problems. Repairs to the facility are ongoing with the expectation that the plant will be brought back to its full production rate of approximately 9 MBOEPD later in the fourth quarter.
2016 Capital Program
The Company has maintained its capital budget for 2016 at $2.1 billion (excluding acquisitions, asset retirement obligations, capitalized interest and geological and geophysical G&A). 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. |
In addition, the Company completed its previously announced acquisition of 28,000 net acres in the Midland Basin from Devon for $429 million during the third quarter.
The 2016 capital activities are expected to be funded from forecasted operating cash flow of $1.5 billion and cash on hand (including investments). Pioneer had a net debt-to-forecasted 2016 operating cash flow at the end of the third quarter of 0.2 times, and net debt-to-book capitalization was 3%.
The Company now expects to deliver production growth of 14%+ in 2016 compared to 2015 based on the above capital program. This growth reflects Spraberry/Wolfcamp area production growing by 36%+, partially offset by declines of approximately 25% in the Eagle Ford Shale and 10% across Pioneer’s other assets.
Third Quarter 2016 Financial Review
Sales volumes for the third quarter of 2016 averaged 239 MBOEPD. Oil sales averaged 134 thousand barrels per day (MBPD), NGL sales averaged 49 MBPD and gas sales averaged 332 million cubic feet per day (MCF).
The average realized price for oil was $41.44 per barrel. The average realized price for NGLs was $12.46 per barrel, and the average realized price for gas was $2.43 per MCF. These prices exclude the effects of derivatives.
Production costs averaged $7.85 per BOE. Depreciation, depletion and amortization (DD&A) expense averaged $17.54 per BOE. Exploration and abandonment costs were $19 million, including $1 million of drilling, acreage and other abandonments, $1 million for seismic and $17 million of personnel costs. General and administrative expense totaled $82 million and interest expense was $50 million. Other expense was $69 million, including (i) $27 million of charges associated with excess firm gathering and transportation commitments, (ii) $17 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) $10 million of stacked drilling rig charges.
The Company recognized an income tax benefit of $78 million during the third quarter, which includes a $59 million income tax benefit associated with the recognition of research and experimental tax credits related to horizontal drilling and completions innovations during the 2012 to 2015 tax periods.
Fourth Quarter 2016 Financial Outlook
The Company’s fourth quarter 2016 outlook for certain operating and financial items is provided below.
Production is forecasted to average 237 MBOEPD to 242 MBOEPD.
Production costs are expected to average $7.75 per BOE to $9.75 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. 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) $5 million to $10 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 Wednesday, November 2, 2016, at 9:00 a.m. Central Time, Pioneer will discuss its financial and operating results for the quarter ended September 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) 339-3466 and use confirmation code 3130339 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 November 27, 2016. Click here to register for the call-in audio replay, and enter confirmation code 3130339.
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, 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 Contacts:
Investors
Frank Hopkins - 972-969-4065
Michael Bandy - 972-969-4513
Trey Muir - 972-969-3674
Media and Public Affairs
Tadd Owens - 972-969-5760
Robert Bobo - 972-969-4020
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions)
September 30, 2016 | December 31, 2015 | |||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 891 | $ | 1,391 | ||||
Short-term investments | 1,733 | — | ||||||
Accounts receivable, net | 447 | 385 | ||||||
Income taxes receivable | 26 | 43 | ||||||
Inventories | 159 | 155 | ||||||
Prepaid expenses | 21 | 17 | ||||||
Notes receivable | — | 498 | ||||||
Derivatives | 172 | 694 | ||||||
Other | 5 | 11 | ||||||
Total current assets | 3,454 | 3,194 | ||||||
Property, plant and equipment, at cost: | ||||||||
Oil and gas properties, using the successful efforts method of accounting | 18,535 | 16,800 | ||||||
Accumulated depletion, depreciation and amortization | (7,866 | ) | (6,778 | ) | ||||
Total property, plant and equipment | 10,669 | 10,022 | ||||||
Long-term investments | 319 | — | ||||||
Goodwill | 272 | 272 | ||||||
Other property and equipment, net | 1,514 | 1,523 | ||||||
Derivatives | 8 | 64 | ||||||
Other assets, net | 89 | 79 | ||||||
$ | 16,325 | $ | 15,154 | |||||
LIABILITIES AND EQUITY | ||||||||
Current liabilities: | ||||||||
Accounts payable | $ | 783 | $ | 883 | ||||
Interest payable | 39 | 65 | ||||||
Income taxes payable | — | 2 | ||||||
Current portion of long-term debt | 485 | 448 | ||||||
Derivatives | 7 | — | ||||||
Other | 63 | 64 | ||||||
Total current liabilities | 1,377 | 1,462 | ||||||
Long-term debt | 2,726 | 3,207 | ||||||
Derivatives | 20 | 1 | ||||||
Deferred income taxes | 1,437 | 1,776 | ||||||
Other liabilities | 334 | 333 | ||||||
Equity | 10,431 | 8,375 | ||||||
$ | 16,325 | $ | 15,154 | |||||
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per share data)
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
Revenues and other income: | ||||||||||||||||
Oil and gas | $ | 643 | $ | 557 | $ | 1,665 | $ | 1,670 | ||||||||
Sales of purchased oil and gas | 444 | 326 | 1,062 | 665 | ||||||||||||
Interest and other | 7 | 2 | 21 | 16 | ||||||||||||
Derivative gains (losses), net | 91 | 573 | (95 | ) | 617 | |||||||||||
Gain on disposition of assets, net | 1 | 779 | 4 | 782 | ||||||||||||
1,186 | 2,237 | 2,657 | 3,750 | |||||||||||||
Costs and expenses: | ||||||||||||||||
Oil and gas production | 141 | 189 | 438 | 532 | ||||||||||||
Production and ad valorem taxes | 32 | 36 | 97 | 112 | ||||||||||||
Depletion, depreciation and amortization | 386 | 364 | 1,123 | 1,003 | ||||||||||||
Purchased oil and gas | 458 | 339 | 1,113 | 684 | ||||||||||||
Impairment of oil and gas properties | — | 72 | 32 | 210 | ||||||||||||
Exploration and abandonments | 19 | 25 | 96 | 79 | ||||||||||||
General and administrative | 82 | 81 | 235 | 246 | ||||||||||||
Accretion of discount on asset retirement obligations | 5 | 3 | 14 | 9 | ||||||||||||
Interest | 50 | 46 | 161 | 138 | ||||||||||||
Other | 69 | 79 | 223 | 186 | ||||||||||||
1,242 | 1,234 | 3,532 | 3,199 | |||||||||||||
Income (loss) from continuing operations before income taxes | (56 | ) | 1,003 | (875 | ) | 551 | ||||||||||
Income tax benefit (provision) | 78 | (355 | ) | 362 | (195 | ) | ||||||||||
Income (loss) from continuing operations | 22 | 648 | (513 | ) | 356 | |||||||||||
Loss from discontinued operations, net of tax | — | (2 | ) | — | (6 | ) | ||||||||||
Net income (loss) attributable to common stockholders | $ | 22 | $ | 646 | $ | (513 | ) | $ | 350 | |||||||
Basic and diluted earnings per share attributable to common stockholders: | ||||||||||||||||
Income (loss) from continuing operations | $ | 0.13 | $ | 4.29 | $ | (3.10 | ) | $ | 2.36 | |||||||
Loss from discontinued operations | — | (0.01 | ) | — | (0.04 | ) | ||||||||||
Net income (loss) | $ | 0.13 | $ | 4.28 | $ | (3.10 | ) | $ | 2.32 | |||||||
Diluted earnings per share attributable to common stockholders: | ||||||||||||||||
Income (loss) from continuing operations | $ | 0.13 | $ | 4.28 | $ | (3.10 | ) | $ | 2.36 | |||||||
Loss from discontinued operations | — | (0.01 | ) | — | (0.04 | ) | ||||||||||
Net income (loss) | $ | 0.13 | $ | 4.27 | $ | (3.10 | ) | $ | 2.32 | |||||||
Weighted average shares outstanding: | ||||||||||||||||
Basic | 170 | 149 | 165 | 149 | ||||||||||||
Diluted | 170 | 150 | 165 | 149 | ||||||||||||
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
Cash flows from operating activities: | ||||||||||||||||
Net income (loss) | $ | 22 | $ | 646 | $ | (513 | ) | $ | 350 | |||||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||||||||
Depletion, depreciation and amortization | 386 | 364 | 1,123 | 1,003 | ||||||||||||
Impairment of oil and gas properties | — | 72 | 32 | 210 | ||||||||||||
Impairment of inventory and other property and equipment | 1 | 12 | 6 | 21 | ||||||||||||
Exploration expenses, including dry holes | 1 | 7 | 41 | 22 | ||||||||||||
Deferred income taxes | (56 | ) | 307 | (340 | ) | 146 | ||||||||||
Gain on disposition of assets, net | (1 | ) | (779 | ) | (4 | ) | (782 | ) | ||||||||
Accretion of discount on asset retirement obligations | 5 | 3 | 14 | 9 | ||||||||||||
Discontinued operations | — | (1 | ) | — | (4 | ) | ||||||||||
Interest expense | 2 | 5 | 11 | 14 | ||||||||||||
Derivative related activity | 93 | (334 | ) | 628 | (22 | ) | ||||||||||
Amortization of stock-based compensation | 22 | 23 | 66 | 70 | ||||||||||||
Other | 17 | 20 | 51 | 13 | ||||||||||||
Change in operating assets and liabilities: | ||||||||||||||||
Accounts receivable, net | (13 | ) | (23 | ) | (64 | ) | 26 | |||||||||
Income taxes receivable | (22 | ) | 22 | 17 | 23 | |||||||||||
Inventories | 5 | 15 | (7 | ) | (29 | ) | ||||||||||
Prepaid expenses | (3 | ) | (2 | ) | (4 | ) | (3 | ) | ||||||||
Derivatives | (12 | ) | — | (24 | ) | — | ||||||||||
Other current assets | — | 2 | 1 | (6 | ) | |||||||||||
Accounts payable | 52 | 9 | (8 | ) | (266 | ) | ||||||||||
Interest payable | (46 | ) | (26 | ) | (26 | ) | (4 | ) | ||||||||
Income taxes payable | — | 27 | (2 | ) | 26 | |||||||||||
Other current liabilities | (12 | ) | (11 | ) | (38 | ) | (28 | ) | ||||||||
Net cash provided by operating activities | 441 | 358 | 960 | 789 | ||||||||||||
Net cash used in investing activities | (926 | ) | (2 | ) | (3,514 | ) | (1,208 | ) | ||||||||
Net cash provided by (used in) financing activities | (449 | ) | 6 | 2,054 | (25 | ) | ||||||||||
Net increase (decrease) in cash and cash equivalents | (934 | ) | 362 | (500 | ) | (444 | ) | |||||||||
Cash and cash equivalents, beginning of period | 1,825 | 219 | 1,391 | 1,025 | ||||||||||||
Cash and cash equivalents, end of period | $ | 891 | $ | 581 | $ | 891 | $ | 581 | ||||||||
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUMMARY PRODUCTION, PRICE AND MARGIN DATA
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
Average Daily Sales Volumes: | ||||||||||||||||
Oil (Bbls) | 134,240 | 109,101 | 130,602 | 102,780 | ||||||||||||
Natural gas liquids ("NGL") (Bbls) | 49,235 | 41,617 | 43,252 | 37,903 | ||||||||||||
Gas (Mcfs) | 332,415 | 359,957 | 343,828 | 358,594 | ||||||||||||
Total (BOEs) | 238,878 | 210,711 | 231,158 | 200,448 | ||||||||||||
Average Prices: | ||||||||||||||||
Oil (per Bbl) | $ | 41.44 | $ | 42.46 | $ | 37.27 | $ | 45.63 | ||||||||
NGL (per Bbl) | $ | 12.46 | $ | 12.39 | $ | 12.37 | $ | 13.72 | ||||||||
Gas (per Mcf) | $ | 2.43 | $ | 2.53 | $ | 1.96 | $ | 2.53 | ||||||||
Total (BOE) | $ | 29.24 | $ | 28.75 | $ | 26.29 | $ | 30.52 | ||||||||
Three Months Ended September 30, 2016 | ||||||||||||||||||||
Permian Horizontals | Permian Verticals | Eagle Ford | Other Assets | Total | ||||||||||||||||
($ per BOE) | ||||||||||||||||||||
Margin Data: | ||||||||||||||||||||
Average prices | $ | 33.20 | $ | 30.24 | $ | 22.78 | $ | 16.35 | $ | 29.24 | ||||||||||
Production costs | (2.15 | ) | (12.27 | ) | (9.86 | ) | (11.90 | ) | (6.42 | ) | ||||||||||
Production and ad valorem taxes | (1.87 | ) | (1.40 | ) | (0.39 | ) | (0.55 | ) | (1.43 | ) | ||||||||||
$ | 29.18 | $ | 16.57 | $ | 12.53 | $ | 3.90 | $ | 21.39 | |||||||||||
% Oil | 70 | % | 60 | % | 33 | % | 11 | % | 56 | % | ||||||||||
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY EARNINGS PER SHARE INFORMATION
The Company uses the two-class method of calculating basic and diluted earnings per share. Under the two-class method of calculating earnings per share, generally acceptable accounting principles ("GAAP") provide that share-based awards with guaranteed dividend or distribution participation rights qualify as "participating securities" during their vesting periods. The Company's basic net income (loss) per share attributable to common stockholders is computed as (i) net income (loss) attributable to common stockholders, (ii) less participating share-based basic earnings (iii) divided by weighted average basic shares outstanding. The Company's diluted net income (loss) per share attributable to common stockholders is computed as (i) basic net income (loss) attributable to common stockholders, (ii) plus the reallocation of participating earnings, if any, (iii) divided by weighted average diluted shares outstanding. During periods in which the Company realizes a loss from continuing operations attributable to common stockholders, securities or other contracts to issue common stock would 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 income (loss) attributable to common stockholders to basic and diluted net income (loss) attributable to common stockholders for the three and nine months ended September 30, 2016 and 2015:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
(in millions) | ||||||||||||||||
Net income (loss) attributable to common stockholders | $ | 22 | $ | 646 | $ | (513 | ) | $ | 350 | |||||||
Participating basic earnings | — | (6 | ) | — | (3 | ) | ||||||||||
Basic and diluted net income (loss) attributable to common stockholders | $ | 22 | $ | 640 | $ | (513 | ) | $ | 347 | |||||||
Basic and diluted weighted average common shares outstanding were 170 million and 165 million for the three and nine months ended September 30, 2016, respectively. Basic weighted average common shares outstanding were 149 million for both the three and nine months ended September 30, 2015 and diluted weighted average common shares outstanding were 150 million and 149 million for the three and nine months ended September 30, 2015, respectively.
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES
(in millions)
EBITDAX and discretionary cash flow ("DCF") (as defined below) are presented herein, and reconciled to the GAAP measures of net income (loss) and net cash provided by operating activities, because of their wide acceptance by the investment community as financial indicators of a company's ability to internally fund exploration and development activities and to service or incur debt. The Company also views the non-GAAP measures of EBITDAX and DCF as useful tools for comparisons of the Company's financial indicators with those of peer companies that follow the full cost method of accounting. EBITDAX and DCF should not be considered as alternatives to net income (loss) or net cash provided by operating activities, as defined by GAAP.
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
Net income (loss) | $ | 22 | $ | 646 | $ | (513 | ) | $ | 350 | |||||||
Depletion, depreciation and amortization | 386 | 364 | 1,123 | 1,003 | ||||||||||||
Exploration and abandonments | 19 | 25 | 96 | 79 | ||||||||||||
Impairment of oil and gas properties | — | 72 | 32 | 210 | ||||||||||||
Impairment of inventory and other property and equipment | 1 | 12 | 6 | 21 | ||||||||||||
Accretion of discount on asset retirement obligations | 5 | 3 | 14 | 9 | ||||||||||||
Interest expense | 50 | 46 | 161 | 138 | ||||||||||||
Income tax (benefit) provision | (78 | ) | 355 | (362 | ) | 195 | ||||||||||
Gain on disposition of assets, net | (1 | ) | (779 | ) | (4 | ) | (782 | ) | ||||||||
Loss from discontinued operations, net of tax | — | 2 | — | 6 | ||||||||||||
Derivative related activity | 93 | (334 | ) | 628 | (22 | ) | ||||||||||
Amortization of stock-based compensation | 22 | 23 | 66 | 70 | ||||||||||||
Other | 17 | 20 | 51 | 13 | ||||||||||||
EBITDAX (a) | 536 | 455 | 1,298 | 1,290 | ||||||||||||
Cash interest expense | (48 | ) | (41 | ) | (150 | ) | (124 | ) | ||||||||
Current income tax (provision) benefit | 22 | (48 | ) | 22 | (49 | ) | ||||||||||
Discretionary cash flow (b) | 510 | 366 | 1,170 | 1,117 | ||||||||||||
Discontinued operations cash activity | — | (3 | ) | — | (10 | ) | ||||||||||
Cash exploration expense | (18 | ) | (18 | ) | (55 | ) | (57 | ) | ||||||||
Changes in operating assets and liabilities | (51 | ) | 13 | (155 | ) | (261 | ) | |||||||||
Net cash provided by operating activities | $ | 441 | $ | 358 | $ | 960 | $ | 789 | ||||||||
_______________
(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 income adjusted for noncash mark-to-market ("MTM") derivative losses, as presented in this press release, is presented and reconciled to Pioneer's net income 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 income attributable to common stockholders for the three months ended September 30, 2016, as determined in accordance with GAAP, to adjusted income excluding noncash MTM derivative losses and unusual items for that quarter.
After-tax Amounts | Amounts Per Share | ||||||
Net income attributable to common stockholders | $ | 22 | $ | 0.13 | |||
Noncash MTM derivative losses | 59 | 0.35 | |||||
Adjusted income excluding noncash MTM derivative losses | 81 | 0.48 | |||||
Tax credit for research and experimental expenditures (a) | (59 | ) | (0.35 | ) | |||
Adjusted income excluding noncash MTM derivative losses and unusual items | $ | 22 | $ | 0.13 | |||
_______________
(a) | Deferred tax benefit resulting from research and experimental expenditures related to drilling and completion innovations on horizontal wells for tax years 2012 through 2015. |
PIONEER NATURAL RESOURCES COMPANY
SUPPLEMENTAL INFORMATION
Open Commodity Derivative Positions as of October 28, 2016
(Volumes are average daily amounts)
2016 | Year Ending December 31, | ||||||||||||
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 | 121,022 | 20,000 | ||||||||||
NYMEX price: | |||||||||||||
Ceiling | $ | 75.94 | $ | 61.87 | $ | 65.14 | |||||||
Floor | $ | 65.41 | $ | 49.15 | $ | 50.00 | |||||||
Short put | $ | 47.03 | $ | 40.93 | $ | 40.00 | |||||||
Basis swap contracts (a): | |||||||||||||
Midland-Cushing index swap volume | 6,630 | — | — | ||||||||||
Price differential ($/Bbl) | $ | (0.80 | ) | $ | — | $ | — | ||||||
Average Daily NGL Production Associated with Derivatives (Bbl): | |||||||||||||
Propane swap contracts (b): | |||||||||||||
Volume | 6,000 | — | — | ||||||||||
Price | $ | 21.51 | $ | — | $ | — | |||||||
Ethane collar contracts (c): | |||||||||||||
Volume | — | 3,000 | — | ||||||||||
Price: | |||||||||||||
Ceiling | $ | — | $ | 11.83 | $ | — | |||||||
Floor | $ | — | $ | 8.68 | $ | — | |||||||
Ethane basis swap contracts (d): | |||||||||||||
Volume (MMBtu) | 2,768 | — | — | ||||||||||
Price differential | $ | 0.91 | $ | — | $ | — | |||||||
Average Daily Gas Production Associated with Derivatives (MMBtu): | |||||||||||||
Swap contracts: | |||||||||||||
Volume | 70,000 | — | — | ||||||||||
NYMEX price | $ | 4.06 | $ | — | $ | — | |||||||
Collar contracts with short puts: | |||||||||||||
Volume | 180,000 | 180,000 | 50,000 | ||||||||||
NYMEX price: | |||||||||||||
Ceiling | $ | 4.01 | $ | 3.49 | $ | 3.40 | |||||||
Floor | $ | 3.24 | $ | 2.91 | $ | 2.75 | |||||||
Short put | $ | 2.78 | $ | 2.43 | $ | 2.25 | |||||||
Basis swap contracts: | |||||||||||||
Gulf Coast index swap volume (e) | 10,000 | — | — | ||||||||||
Price differential ($/MMBtu) | $ | — | $ | — | $ | — | |||||||
Mid-Continent index swap volume (e) | 15,000 | 45,000 | — | ||||||||||
Price differential ($/MMBtu) | $ | (0.32 | ) | $ | (0.32 | ) | $ | — | |||||
Permian Basin index swap volume (f) | 34,946 | 9,863 | — | ||||||||||
Price differential ($/MMBtu) | $ | 0.41 | $ | 0.37 | $ | — | |||||||
_______________
(a) | Represent swaps that fix the basis differential between Midland oil prices and Cushing WTI. |
(b) | Represent swap contracts that reduce the price volatility of propane forecasted for sale by the Company at Mont Belvieu, Texas and Conway, Kansas 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 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. |
(e) | 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. |
(f) | 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. |
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 October 28, 2016, 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 its drilling rigs and fracture stimulation fleet equipment. As of October 28, 2016, the Company was party to diesel derivative swap contracts for 1,000 Bbls per day for 2017 at an average per Bbl fixed price of $60.48.
Interest rate derivatives. As of October 28, 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.
Derivative Gains (Losses), Net
(in millions)
The following table summarizes net derivative losses that the Company recorded in earnings for the three and nine months ended September 30, 2016:
Three Months Ended September 30, 2016 | Nine Months Ended September 30, 2016 | |||||||
Noncash changes in fair value: | ||||||||
Oil derivative losses | $ | (92 | ) | $ | (549 | ) | ||
NGL derivative gains (losses) | 2 | (15 | ) | |||||
Gas derivative losses | (5 | ) | (58 | ) | ||||
Diesel derivative gains | 2 | 2 | ||||||
Interest rate derivative gains (losses) | — | (8 | ) | |||||
Total noncash derivative losses, net | (93 | ) | (628 | ) | ||||
Net cash receipts on settled derivative instruments: | ||||||||
Oil derivative receipts | 168 | 471 | ||||||
NGL derivative receipts | 2 | 6 | ||||||
Gas derivative receipts | 14 | 56 | ||||||
Total cash derivative receipts, net | 184 | 533 | ||||||
Total derivative gains (losses), net | $ | 91 | $ | (95 | ) | |||