EXHIBIT 99.1
News Release
Pioneer Natural Resources Reports First Quarter 2016
Financial and Operating Results
Dallas, Texas, April 25, 2016 - Pioneer Natural Resources Company (NYSE:PXD) (“Pioneer” or “the Company”) today reported financial and operating results for the quarter ended March 31, 2016.
Pioneer reported a first quarter net loss attributable to common stockholders of $267 million, or $1.65 per diluted share. Without the effect of noncash mark-to-market derivative losses and other unusual items, adjusted results for the first quarter were a net loss of $104 million after tax, or $0.64 per diluted share.
First quarter and other recent highlights included:
• | producing 222 thousand barrels oil equivalent per day (MBOEPD), of which 55% was oil; production grew by 7 MBOEPD, or 3%, compared to the fourth quarter of 2015, and was significantly above Pioneer’s first quarter production guidance range of 211 MBOEPD to 216 MBOEPD; oil production grew 10 thousand barrels oil per day during the quarter, or 9%, compared to the fourth quarter; first quarter production growth was driven by the Company’s Spraberry/Wolfcamp horizontal drilling program; Pioneer’s Spraberry/Wolfcamp gross production exceeded 200 MBOEPD for the first time in the Company’s history and total daily production for the Spraberry/Wolfcamp field has now surpassed one million barrels oil equivalent (MMBOE); |
• | placing 55 horizontal wells on production in the Spraberry/Wolfcamp during the first quarter with all wells benefiting from Pioneer’s completion optimization program; |
• | 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 combined production cost and G&A expense per barrel oil equivalent (BOE) by 15% compared to the fourth quarter of 2015; |
• | starting up the new Targa-operated Spraberry/Wolfcamp gas processing plant, which has a capacity of 200 million cubic feet per day (MMCFPD); and |
• | increasing oil and gas derivative coverage for 2017. |
Pioneer’s latest plans for 2016 are summarized below:
• | planning to maintain 12 horizontal rigs in the northern Spraberry/Wolfcamp based on favorable well returns in this area; the Company is currently operating 12 horizontal rigs in the northern Spraberry/Wolfcamp and two horizontal rigs in the southern Wolfcamp joint venture area (both southern Wolfcamp rigs are expected to be terminated by the end of June); the northern rig activity level will allow the Company to continue to progress its completion optimization program; |
• | expecting to deliver production growth of 12%+ in 2016 compared to the Company’s previous production growth target of 10%; the higher forecasted growth rate reflects improving Spraberry/Wolfcamp well productivity; |
• | maintaining capital expenditures for 2016 of $2.0 billion, of which $1.85 billion is for drilling and completions (includes tank batteries, saltwater disposal facilities and gas processing facilities) and $150 million is for vertical integration, systems upgrades and field facilities; |
• | expecting to add five to ten horizontal drilling rigs when the price of oil recovers to approximately $50 per barrel and the outlook for oil supply/demand fundamentals is positive; |
• | protecting the Company’s cash flow through strong commodity derivative positions, with (i) oil derivative coverage of approximately 85% for 2016 and 50% for 2017 (up from 20% earlier this year) and (ii) gas derivative coverage of approximately 70% for 2016 and 25% for 2017 (up from no coverage earlier this year); and |
• | maintaining a strong investment grade balance sheet, with financial resources that are expected to enable the Company to grow production and fund its expected capital program through 2017 without increasing debt; financial resources include forecasted cash flow, cash on hand and liquid investments at the end of the first quarter of $2.5 billion (of which $940 million will be used to fund the Company’s July 2016 and March 2017 senior note maturities) and an additional $0.5 billion to be received in July 2016 from the sale of the Eagle Ford Shale midstream business; this results in an end of the first quarter pro forma net debt-to-2016 operating cash flow of 0.4 times and net-debt-to-book capitalization of 10% (pro forma net debt is net debt as of March 31, 2016, less the remaining $500 million of proceeds from the Eagle Ford Shale midstream business sale that will be received in July 2016). |
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 have the financial flexibility to prudently manage through the current commodity price downturn and quickly ramp up drilling activity when prices improve. We expect to add five to ten horizontal rigs when the price of oil recovers to approximately $50 per barrel and when our outlook for oil supply/demand fundamentals is positive.”
Mark-to-Market Derivative Gains and Unusual Items Included in First Quarter 2016 Earnings
Pioneer’s first quarter earnings included noncash mark-to-market losses on derivatives of $111 million after tax, or $0.69 per diluted share.
First quarter earnings also included a net loss of $52 million after tax, or $0.32 per diluted share, related to the following unusual items:
• | a noncash charge of $20 million after tax, or $0.13 per diluted share, associated with the impairment of proved properties in the West Panhandle field in Texas; |
• | a noncash charge of $20 million after tax, or $0.12 per diluted share, associated with the impairment of unproved royalty acreage in Alaska; |
• | a charge of $10 million after tax, or $0.06 per diluted share, associated with the early termination of horizontal drilling rig contracts; and |
• | a restructuring charge of $2 million after tax, or $0.01 per diluted share, related to the relocation of two pressure pumping fleets from the Eagle Ford Shale to the Spraberry/Wolfcamp. |
Spraberry/Wolfcamp Operations Update and 2016 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 55 horizontal wells on production in the Spraberry/Wolfcamp during the first quarter of 2016, of which 42 wells were in the northern portion of the play and 13 wells were in the southern Wolfcamp joint venture area. Of the 55 wells, 37 wells were in the Wolfcamp B interval, nine wells were in
the Wolfcamp A interval, eight wells were in the Lower Spraberry Shale interval and one well was in the Middle Spraberry Shale interval. The Wolfcamp A, Lower Spraberry Shale and Middle Spraberry Shale wells were all in the north, while 24 of the Wolfcamp B interval wells were in the north and the remaining 13 Wolfcamp B interval wells were in the southern Wolfcamp joint venture area. All of the Spraberry/Wolfcamp wells placed on production in the first quarter benefited from Pioneer’s completion optimization program.
The Company’s completion optimization program is continuing to deliver strong well performance. In the northern Spraberry/Wolfcamp, 97 wells have been completed under this program since mid-2015. These wells (68 wells in the Wolfcamp B interval, 13 wells in the Wolfcamp A interval and 16 wells in the Lower Spraberry Shale interval), are delivering productivity improvements based on early production rates ranging from 10% to 35% above a 1 MMBOE estimated ultimate recovery (EUR) type curve. The 1 MMBOE EUR type curve reflects the average performance of the horizontal Wolfcamp A and Wolfcamp B interval wells drilled by Pioneer across the Company’s northern acreage before the completion optimization program was initiated. Horizontal wells in the southern Wolfcamp joint venture area are also benefiting from the completion optimization program, with 22 wells having been completed under the program. Of the 22 wells, 21 wells were in the Wolfcamp B interval and are delivering a productivity improvement based on early production rates averaging 25% above a 1 MMBOE EUR type curve. Early production from the remaining Wolfcamp A interval well is delivering an average productivity improvement of 25% compared to an 800 thousand barrel oil equivalent EUR type curve.
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 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. The current fracture stimulation design, which reflects the 97 wells in the northern Spraberry/Wolfcamp that have been successfully optimized to date, consists 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 current design increased the cost of a completion by approximately $500 thousand per well. Over the remainder of 2016, Pioneer plans to test further enhanced completion designs on approximately 80 wells. This will include larger proppant concentrations up to 1,700 pounds per foot, larger fluid concentrations up to 50 barrels per foot, tighter cluster spacing of 15 feet and shorter stage spacing of 100 feet. The cost of this testing adds $500 thousand to $1 million per well compared to the current design.
Pioneer’s contiguous acreage position allows for decades of drilling horizontal wells with perforated lateral lengths ranging from 7,500 feet to 13,000 feet, resulting in improved capital efficiency. Pioneer recently placed its two longest lateral length wells to date on production in the northern Spraberry/Wolfcamp - the Sale Ranch 14C 3H and the Sale Ranch 14B 2H. These wells had an average lateral length of approximately 12,000 feet and were completed in the Wolfcamp B interval. Both wells benefited from completion optimization and delivered an average peak 24-hour initial production rate of 3,050 barrels oil equivalent per day (BOEPD) with an oil content of 80%. Both wells have been on production for approximately 30 days. Early results indicate that these wells are outperforming the previous 36 horizontal Wolfcamp B wells completed on the Sale Ranch lease that had lateral lengths greater than 7,000 feet. Of the 36 wells, 23 wells had an average lateral length of 9,500 feet, an average peak 24-hour initial production rate of 2,500 BOEPD and 81% oil content. The remaining 13 wells had an average lateral length of approximately 7,000 feet, an average peak 24-hour initial production rate of 2,100 BOEPD and 80% oil content. The Company plans to drill 10 to 15 horizontal wells in 2016 with lateral lengths greater than 10,000 feet.
The drilling and completion cost per perforated lateral foot for all horizontal Wolfcamp B interval wells placed on production (includes completion optimized wells and non-optimized wells) in the northern
Spraberry/Wolfcamp area averaged $890 per foot in the first quarter, a decrease of 32% from the fourth quarter of 2014. This reflects service cost reduction initiatives and efficiency gains.
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 interval, 25% in the Wolfcamp A interval and 15% in the Lower Spraberry Shale interval. The current cost to drill and complete a horizontal well is approximately $7.5 million to $8.0 million, assuming average perforated lateral lengths of approximately 9,000 feet and utilization of the 2015 optimized completion design as the standard design for 2016. Production costs for Pioneer’s horizontal Spraberry/Wolfcamp wells range from $5.00 to $7.00 per BOE per well (includes lease operating expenses ranging from $3.00 to $5.00 per BOE and production and ad valorem taxes of $2.00 per BOE).
Despite the weak commodity price environment, the 2016 drilling program in the northern Spraberry/Wolfcamp area is expected to continue to deliver favorable internal rates of return, with returns of approximately 30% expected at current strip commodity prices. 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 12 MBOEPD, or 9%, in the first quarter of 2016 compared to the fourth quarter of 2015. Oil production grew 11% in the first quarter and represented 69% of first quarter production on a BOE basis. Horizontal production grew to 63% of total Spraberry/Wolfcamp production, with vertical production declining to 37%. First 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 first quarter due to weak market conditions, which negatively impacted production by approximately 4 MBOEPD.
Pioneer is increasing its forecasted 2016 growth rate for the Spraberry/Wolfcamp from 30%+ to 33%+ as a result of improving well productivity. Oil production is also expected to increase from 30%+ to 33%+ this year. The Company also assumes it will continue to reject approximately 4 MBOEPD of ethane over the remainder of 2016 based on weak market conditions. Total Spraberry/Wolfcamp production is expected to increase sequentially throughout the year.
For the second quarter of 2016, the Company expects to place approximately 60 horizontal wells on production. It will also begin choke management in selected areas to optimize water disposal infrastructure.
2016 Capital Program
The Company’s capital budget for 2016 continues to be $2.0 billion (excluding acquisitions, asset retirement obligations, capitalized interest and geological and geophysical G&A). The budget includes $1.85 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 - $1,710 million (includes $1,440 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 2016 capital budget is expected to be funded from forecasted operating cash flow of $1.4 billion (an increase of $0.1 billion over the Company’s previous estimate and based on assumed average 2016 estimated prices of $40.00 per barrel for oil and $2.20 per thousand cubic feet (MCF) for gas), cash on hand and the remaining $500 million of proceeds from the Eagle Ford Shale midstream business sale, which will be received in July 2016.
The Company expects to deliver production growth of 12%+ in 2016 compared to 2015 based on the above capital program. This growth reflects Spraberry/Wolfcamp area production growing by 33%+, partially offset by declines of approximately 25% in the Eagle Ford Shale and 10% across Pioneer’s other assets.
First Quarter 2016 Financial Review
Sales volumes for the first quarter of 2016 averaged 222 MBOEPD. Oil sales averaged 123 thousand barrels per day (MBPD), NGL sales averaged 39 MBPD and gas sales averaged 359 MMCFPD.
The average realized price for oil was $28.09 per barrel. The average realized price for NGLs was $10.33 per barrel, and the average realized price for gas was $1.79 per MCF. These prices exclude the effects of derivatives.
Production costs averaged $9.17 per BOE. Depreciation, depletion and amortization (DD&A) expense averaged $17.49 per BOE. Exploration and abandonment costs were $59 million, including $40 million of drilling, acreage and other abandonments (primarily comprised of a noncash impairment charge of $32 million related to unproved royalty acreage in Alaska), $3 million of seismic data and $16 million of personnel costs. General and administrative expense totaled $74 million and interest expense was $55 million. Other expense was $87 million, including (i) $24 million of charges associated with excess firm gathering and transportation commitments, (ii) $21 million of stacked drilling rig charges, (iii) $15 million of fees associated with the early termination of drilling rig contracts, (iv) $13 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 (v) $3 million of restructuring charges associated with relocating two Pioneer pressure pumping fleets from the Eagle Ford Shale to the Spraberry/Wolfcamp.
Second Quarter 2016 Financial Outlook
The Company’s second quarter 2016 outlook for certain operating and financial items is provided below.
Production is forecasted to average 224 MBOEPD to 229 MBOEPD.
Production costs are expected to average $9.00 per BOE to $11.00 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 $75 million to $80 million, interest expense is expected to be $55 million to $60 million and other expense is expected to be $65 million to $75 million. Other expense includes (i) $25 million to $30 million of expected charges associated with excess firm gathering and transportation commitments, (ii) $15 million to $20 million of expected charges for stacked drilling rigs and (iii) $10 million to $15 million of estimated 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 $1 million to $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 Tuesday, April 26, 2016, at 9:00 a.m. CT, Pioneer will discuss its financial and operating results for the quarter ended March 31, 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 (800) 723-6604 and confirmation code 4959541 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 May 21, 2016, by dialing (888) 203-1112 and confirmation code 4959541.
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, uncertainties about estimates of reserves and resource potential and the ability to add proved reserves in the future, the assumptions underlying production forecasts, quality of technical data, 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)
March 31, 2016 | December 31, 2015 | |||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 1,612 | $ | 1,391 | ||||
Short-term investments | 893 | — | ||||||
Accounts receivable, net | 351 | 385 | ||||||
Income taxes receivable | 3 | 43 | ||||||
Inventories | 153 | 155 | ||||||
Prepaid expenses | 20 | 17 | ||||||
Notes receivable | 500 | 498 | ||||||
Derivatives | 540 | 694 | ||||||
Other | 9 | 11 | ||||||
Total current assets | 4,081 | 3,194 | ||||||
Property, plant and equipment, at cost: | ||||||||
Oil and gas properties, using the successful efforts method of accounting | 17,256 | 16,800 | ||||||
Accumulated depletion, depreciation and amortization | (7,118 | ) | (6,778 | ) | ||||
Total property, plant and equipment | 10,138 | 10,022 | ||||||
Long-term investments | 21 | — | ||||||
Goodwill | 272 | 272 | ||||||
Other property and equipment, net | 1,527 | 1,523 | ||||||
Derivatives | 50 | 64 | ||||||
Other assets, net | 82 | 79 | ||||||
$ | 16,171 | $ | 15,154 | |||||
LIABILITIES AND EQUITY | ||||||||
Current liabilities: | ||||||||
Accounts payable | $ | 728 | $ | 883 | ||||
Interest payable | 49 | 65 | ||||||
Income taxes payable | 2 | 2 | ||||||
Current portion of long-term debt | 936 | 448 | ||||||
Derivatives | 2 | — | ||||||
Other | 66 | 64 | ||||||
Total current liabilities | 1,783 | 1,462 | ||||||
Long-term debt | 2,724 | 3,207 | ||||||
Derivatives | 6 | 1 | ||||||
Deferred income taxes | 1,635 | 1,776 | ||||||
Other liabilities | 328 | 333 | ||||||
Equity | 9,695 | 8,375 | ||||||
$ | 16,171 | $ | 15,154 | |||||
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per share data)
Three Months Ended March 31, | ||||||||
2016 | 2015 | |||||||
Revenues and other income: | ||||||||
Oil and gas | $ | 409 | $ | 517 | ||||
Sales of purchased oil and gas | 223 | 103 | ||||||
Interest and other | 8 | 7 | ||||||
Derivative gains, net | 43 | 241 | ||||||
Gain on disposition of assets, net | 2 | 1 | ||||||
685 | 869 | |||||||
Costs and expenses: | ||||||||
Oil and gas production | 156 | 180 | ||||||
Production and ad valorem taxes | 29 | 39 | ||||||
Depletion, depreciation and amortization | 353 | 310 | ||||||
Purchased oil and gas | 243 | 108 | ||||||
Impairment of oil and gas properties | 32 | 138 | ||||||
Exploration and abandonments | 59 | 25 | ||||||
General and administrative | 74 | 82 | ||||||
Accretion of discount on asset retirement obligations | 5 | 3 | ||||||
Interest | 55 | 46 | ||||||
Other | 87 | 49 | ||||||
1,093 | 980 | |||||||
Loss from continuing operations before income taxes | (408 | ) | (111 | ) | ||||
Income tax benefit | 141 | 37 | ||||||
Loss from continuing operations | (267 | ) | (74 | ) | ||||
Loss from discontinued operations, net of tax | — | (4 | ) | |||||
Net loss attributable to common stockholders | $ | (267 | ) | $ | (78 | ) | ||
Basic and diluted earnings per share attributable to common stockholders: | ||||||||
Loss from continuing operations | $ | (1.65 | ) | $ | (0.50 | ) | ||
Loss from discontinued operations | — | (0.02 | ) | |||||
Net loss | $ | (1.65 | ) | $ | (0.52 | ) | ||
Weighted average shares outstanding: | ||||||||
Basic | 162 | 149 | ||||||
Diluted | 162 | 149 | ||||||
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
Three Months Ended March 31, | ||||||||
2016 | 2015 | |||||||
Cash flows from operating activities: | ||||||||
Net loss | $ | (267 | ) | $ | (78 | ) | ||
Adjustments to reconcile net loss to net cash provided by operating activities: | ||||||||
Depletion, depreciation and amortization | 353 | 310 | ||||||
Impairment of oil and gas properties | 32 | 138 | ||||||
Impairment of inventory and other property and equipment | 4 | 6 | ||||||
Exploration expenses, including dry holes | 40 | 5 | ||||||
Deferred income taxes | (141 | ) | (37 | ) | ||||
Gain on disposition of assets, net | (2 | ) | (1 | ) | ||||
Accretion of discount on asset retirement obligations | 5 | 3 | ||||||
Discontinued operations | — | (3 | ) | |||||
Interest expense | 5 | 5 | ||||||
Derivative related activity | 175 | (35 | ) | |||||
Amortization of stock-based compensation | 21 | 22 | ||||||
Other | 18 | (1 | ) | |||||
Change in operating assets and liabilities: | ||||||||
Accounts receivable, net | 33 | 96 | ||||||
Income taxes receivable | 40 | 1 | ||||||
Inventories | — | (34 | ) | |||||
Prepaid expenses | (3 | ) | (5 | ) | ||||
Other current assets | — | (7 | ) | |||||
Accounts payable | (169 | ) | (250 | ) | ||||
Interest payable | (16 | ) | (20 | ) | ||||
Other current liabilities | (17 | ) | (11 | ) | ||||
Net cash provided by operating activities | 111 | 104 | ||||||
Net cash used in investing activities | (1,463 | ) | (717 | ) | ||||
Net cash provided by (used in) financing activities | 1,573 | (29 | ) | |||||
Net increase (decrease) in cash and cash equivalents | 221 | (642 | ) | |||||
Cash and cash equivalents, beginning of period | 1,391 | 1,025 | ||||||
Cash and cash equivalents, end of period | $ | 1,612 | $ | 383 | ||||
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUMMARY PRODUCTION AND PRICE DATA
Three Months Ended March 31, | ||||||||
2016 | 2015 | |||||||
Average Daily Sales Volumes: | ||||||||
Oil (Bbls) | 122,802 | 98,554 | ||||||
Natural gas liquids ("NGL") (Bbls) | 39,232 | 35,364 | ||||||
Gas (Mcfs) | 358,651 | 359,428 | ||||||
Total (BOEs) | 221,809 | 193,823 | ||||||
Average Prices: | ||||||||
Oil (per Bbl) | $ | 28.09 | $ | 43.02 | ||||
NGL (per Bbl) | $ | 10.33 | $ | 15.00 | ||||
Gas (per Mcf) | $ | 1.79 | $ | 2.70 | ||||
Total (BOE) | $ | 20.28 | $ | 29.63 | ||||
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 months ended March 31, 2016 and 2015:
Three Months Ended March 31, | ||||||||
2016 | 2015 | |||||||
(in millions) | ||||||||
Net loss attributable to common stockholders | $ | (267 | ) | $ | (78 | ) | ||
Participating basic earnings | — | — | ||||||
Basic and diluted net loss attributable to common stockholders | $ | (267 | ) | $ | (78 | ) | ||
Basic and diluted weighted average common shares outstanding were 162 million for the three months ended March 31, 2016 and 149 million for the three months ended March 31, 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 March 31, | ||||||||
2016 | 2015 | |||||||
Net loss | $ | (267 | ) | $ | (78 | ) | ||
Depletion, depreciation and amortization | 353 | 310 | ||||||
Exploration and abandonments | 59 | 25 | ||||||
Impairment of oil and gas properties | 32 | 138 | ||||||
Impairment of inventory and other property and equipment | 4 | 6 | ||||||
Accretion of discount on asset retirement obligations | 5 | 3 | ||||||
Interest expense | 55 | 46 | ||||||
Income tax benefit | (141 | ) | (37 | ) | ||||
Gain on disposition of assets, net | (2 | ) | (1 | ) | ||||
Loss from discontinued operations, net of tax | — | 4 | ||||||
Derivative related activity | 175 | (35 | ) | |||||
Amortization of stock-based compensation | 21 | 22 | ||||||
Other | 18 | (1 | ) | |||||
EBITDAX (a) | 312 | 402 | ||||||
Cash interest expense | (50 | ) | (41 | ) | ||||
Discretionary cash flow (b) | 262 | 361 | ||||||
Discontinued operations cash activity | — | (7 | ) | |||||
Cash exploration expense | (19 | ) | (20 | ) | ||||
Changes in operating assets and liabilities | (132 | ) | (230 | ) | ||||
Net cash provided by operating activities | $ | 111 | $ | 104 | ||||
_______________
(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, and adjusted loss excluding noncash MTM derivative losses and unusual items, as presented in this press release, are presented and reconciled to Pioneer's net loss attributable to common stockholders (determined in accordance with GAAP) because Pioneer believes that these non-GAAP financial measures reflect an additional way of viewing aspects of Pioneer's business that, when viewed together with its financial results computed in accordance with GAAP, provides a more complete understanding of factors and trends affecting its historical financial performance and future operating results, greater transparency of underlying trends and greater comparability of results across periods. In addition, management believes that these non-GAAP measures may enhance investors' ability to assess Pioneer's historical and future financial performance. These non-GAAP financial measures are not intended to be substitutes for the comparable GAAP measure and should be read only in conjunction with Pioneer's consolidated financial statements prepared in accordance with GAAP. Noncash MTM derivative gains and losses and unusual items will recur in future periods; however, the amount and frequency can vary significantly from period to period. The table below reconciles Pioneer's net loss attributable to common stockholders for the three months ended March 31, 2016, as determined in accordance with GAAP, to adjusted loss excluding noncash MTM derivative losses and adjusted loss excluding noncash MTM derivative losses and unusual items for that quarter.
After-tax Amounts | Amounts Per Share | ||||||
Net loss attributable to common stockholders | $ | (267 | ) | $ | (1.65 | ) | |
Noncash MTM derivative losses | 111 | 0.69 | |||||
Adjusted loss excluding noncash MTM derivative losses | (156 | ) | (0.96 | ) | |||
Noncash charge for impairment of West Panhandle proved properties | 20 | 0.13 | |||||
Noncash charge for impairment of Alaska unproved royalty acreage | 20 | 0.12 | |||||
Fees associated with early termination of drilling rig contracts | 10 | 0.06 | |||||
Eagle Ford pressure pumping services restructuring charge | 2 | 0.01 | |||||
Adjusted loss excluding noncash MTM derivative losses and unusual items | $ | (104 | ) | $ | (0.64 | ) | |
PIONEER NATURAL RESOURCES COMPANY
SUPPLEMENTAL INFORMATION
Open Commodity Derivative Positions as of April 20, 2016
(Volumes are average daily amounts)
2016 | Year Ending December 31, | |||||||||||||||||||
Second Quarter | Third Quarter | Fourth Quarter | 2017 | 2018 | ||||||||||||||||
Average Daily Oil Production Associated with Derivatives (Bbl): | ||||||||||||||||||||
Swap contracts: | ||||||||||||||||||||
Volume | 60,000 | — | — | — | — | |||||||||||||||
NYMEX price | $ | 53.08 | $ | — | $ | — | $ | — | $ | — | ||||||||||
Collar contracts with short puts: | ||||||||||||||||||||
Volume | 43,000 | 112,000 | 112,000 | 73,000 | — | |||||||||||||||
NYMEX price: | ||||||||||||||||||||
Ceiling | $ | 73.26 | $ | 75.94 | $ | 75.94 | $ | 61.11 | $ | — | ||||||||||
Floor | $ | 63.29 | $ | 65.41 | $ | 65.41 | $ | 50.92 | $ | — | ||||||||||
Short put | $ | 40.00 | $ | 47.03 | $ | 47.03 | $ | 42.04 | $ | — | ||||||||||
Average Daily NGL Production Associated with Derivatives (Bbl): | ||||||||||||||||||||
Propane swap contracts (a): | ||||||||||||||||||||
Volume | 7,500 | 7,500 | 7,500 | — | — | |||||||||||||||
Price | $ | 21.57 | $ | 21.57 | $ | 21.57 | $ | — | $ | — | ||||||||||
Ethane collar contracts (b): | ||||||||||||||||||||
Volume | — | — | — | 2,000 | — | |||||||||||||||
Price: | ||||||||||||||||||||
Ceiling | $ | — | $ | — | $ | — | $ | 11.66 | $ | — | ||||||||||
Floor | $ | — | $ | — | $ | — | $ | 8.40 | $ | — | ||||||||||
Average Daily Gas Production Associated with Derivatives (MMBtu): | ||||||||||||||||||||
Swap contracts: | ||||||||||||||||||||
Volume | 70,000 | 70,000 | 70,000 | — | — | |||||||||||||||
NYMEX price | $ | 4.06 | $ | 4.06 | $ | 4.06 | $ | — | $ | — | ||||||||||
Collar contracts with short puts: | ||||||||||||||||||||
Volume | 180,000 | 180,000 | 180,000 | 80,000 | 50,000 | |||||||||||||||
NYMEX price: | ||||||||||||||||||||
Ceiling | $ | 4.01 | $ | 4.01 | $ | 4.01 | $ | 3.15 | $ | 3.40 | ||||||||||
Floor | $ | 3.24 | $ | 3.24 | $ | 3.24 | $ | 2.75 | $ | 2.75 | ||||||||||
Short put | $ | 2.78 | $ | 2.78 | $ | 2.78 | $ | 2.35 | $ | 2.25 | ||||||||||
Basis swap contracts: | ||||||||||||||||||||
Gulf Coast index swap volume (c) | 10,000 | 10,000 | 10,000 | — | — | |||||||||||||||
Price differential ($/MMBtu) | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||
Mid-Continent index swap volume (c) | 15,000 | 15,000 | 15,000 | 45,000 | — | |||||||||||||||
Price differential ($/MMBtu) | $ | (0.32 | ) | $ | (0.32 | ) | $ | (0.32 | ) | $ | (0.32 | ) | $ | — | ||||||
Permian Basin index swap volume (d) | — | — | 34,946 | 9,863 | — | |||||||||||||||
Price differential ($/MMBtu) | $ | — | $ | — | $ | 0.41 | $ | 0.37 | $ | — | ||||||||||
_______________
(a) | Represent swaps that reduce the price volatility of forecasted propane sales 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 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 Henry Hub index price used in gas swap and collar contracts with short puts. |
(d) | 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 April 20, 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 1.98 percent on a notional amount of $200 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 April 20, 2016, the Company did not have any marketing derivatives outstanding.
Derivative Gains, Net
(in millions)
The following table summarizes net derivative gains and losses that the Company recorded in earnings for the three months ended March 31, 2016:
Three Months Ended March 31, 2016 | ||||
Noncash changes in fair value: | ||||
Oil derivative losses | $ | (155 | ) | |
NGL derivative losses | (9 | ) | ||
Gas derivative losses | (9 | ) | ||
Interest rate derivative losses | (2 | ) | ||
Total noncash derivative losses, net | (175 | ) | ||
Net cash receipts on settled derivative instruments: | ||||
Oil derivative receipts | 194 | |||
NGL derivative receipts | 4 | |||
Gas derivative receipts | 20 | |||
Total cash derivative receipts, net | 218 | |||
Total derivative gains, net | $ | 43 | ||