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| 8-K - 8-K - PIONEER NATURAL RESOURCES CO | form8-kxpxdq22014earningsr.htm |
EXHIBIT 99.1
News Release
Pioneer Natural Resources Reports
Second Quarter 2014 Financial and Operating Results
Dallas, Texas, August 4, 2014 -- Pioneer Natural Resources Company (NYSE:PXD) (“Pioneer” or “the Company”) today announced financial and operating results for the quarter ended June 30, 2014.
Pioneer reported second quarter net income attributable to common stockholders of $1 million, or $0.01 per diluted share (see attached schedule for a description of the net income per diluted share calculation). Without the effect of noncash derivative mark-to-market losses and other unusual items, adjusted income for the second quarter was $195 million after tax, or $1.35 per diluted share.
Second quarter and other recent highlights included:
• | producing 183 thousand barrels oil equivalent per day (MBOEPD) from continuing operations in the second quarter (reflects Alaska and Barnett Shale as discontinued operations), an increase of 11 MBOEPD, or 6%, compared to the first quarter of 2014; second quarter production growth was primarily driven by the Company’s successful Spraberry/Wolfcamp and Eagle Ford Shale horizontal drilling programs, which added approximately 3 thousand barrels per day of oil production; production for the quarter also benefited from efficiency improvements in Spraberry/Wolfcamp area gas processing operations; |
• | narrowing annual production growth forecast from continuing operations from a range of 14% to 19% to a range of 16% to 19% (upper end of the range) based on better-than-expected production growth in the first half of 2014 and being on target to nearly double the number of horizontal wells placed on production in the Spraberry/Wolfcamp area from 68 wells in the first half of 2014 to 125 wells in the second half; |
• | continuing to forecast 2014 drilling capital of $3.0 billion; |
• | expecting compound annual production growth from continuing operations of 16% to 21% for 2014 to 2016 and to more than double production by 2018 as compared to 2013; |
• | delivering production results that support strong estimated ultimate recoveries (EURs) and internal rates of return from Pioneer’s horizontal Wolfcamp and Lower Spraberry Shale wells placed on production in its northern Spraberry/Wolfcamp acreage since early 2013; |
• | securing long-term water supply to support fracture stimulation operations in the Spraberry/Wolfcamp area; agreements are being finalized to purchase approximately 120 thousand barrels per day and 240 thousand barrels per day of effluent water from the City of Odessa, Texas, and the City of Midland, Texas, respectively; |
• | continuing the Company’s successful downspacing and staggering program in the Eagle Ford Shale, which included placing 17 wells on production in Upper targets in the first half of 2014; |
• | receiving confirmation from the U.S. Department of Commerce that condensate processed at Pioneer’s Eagle Ford Shale central gathering plants in South Texas is a petroleum product that can be exported without a license; the first cargo was exported in late July; |
• | announcing the sale of Pioneer’s Hugoton, Kansas, assets to Linn Energy, LLC for $340 million, with closing expected by the end of the third quarter of 2014; financial and operating results are expected to be reflected as discontinued operations beginning in the third quarter of 2014; |
• | announcing the sale of Pioneer’s Barnett Shale assets to an undisclosed private company for $155 million, with closing expected by the end of the third quarter of 2014; |
• | having derivative coverage for more than 85% of forecasted oil production for the remainder of 2014 at $93 per barrel or higher; |
• | having approximately 100% of the Company’s Spraberry/Wolfcamp area oil production protected against volatility in the Midland-Cushing oil price differential; and |
• | maintaining a strong balance sheet with $445 million of cash on hand at the end of the second quarter and net debt-to-book capitalization of 25%. |
Scott D. Sheffield, Chairman and CEO, stated, “The Company delivered another great quarter, with strong earnings, production exceeding expectations and continued impressive horizontal well performance in the Spraberry/Wolfcamp and the Eagle Ford Shale areas. We are successfully transforming the substantial resource potential we delineated in 2013 into strong production growth. As a result, we now expect to grow production by 16% to 19% this year - the upper end of our guidance range. Looking beyond 2014, we expect to continue to ramp up our horizontal rig count in the Spraberry/Wolfcamp by five to ten rigs per year.”
“We are pleased that the U.S. Department of Commerce has recently confirmed that Pioneer may begin exporting processed condensate from the Eagle Ford Shale. Our first cargo was shipped in late July and monthly shipments are expected through the end of this year at prices higher than domestic condensate sales. International interest for our processed Eagle Ford Shale condensate is growing, particularly from Asian petrochemical companies.”
Mark-To-Market Derivative Losses and Unusual Items Included in Second Quarter 2014 Earnings
Pioneer’s second quarter earnings included noncash mark-to-market losses on derivatives of $137 million after tax, or $0.94 per diluted share, and a net loss of $57 million after tax, or $0.40 per diluted share, related to discontinued operations associated with Alaska and Barnett Shale results during the quarter.
Operations Update and Drilling Program
Pioneer is the largest acreage holder in the Spraberry/Wolfcamp play in the Midland Basin, with approximately 600,000 gross acres in the northern portion of the play and 200,000 gross acres in the southern Wolfcamp joint venture area. The Company believes it has more than 10 billion barrels oil equivalent of net recoverable resource potential from horizontal drilling across its entire Spraberry/Wolfcamp acreage position based on its extensive geologic data and successful drilling results to date.
The Company successfully placed 40 horizontal oil wells on production during 2013 and the first half of 2014 across its northern acreage position in the Spraberry/Wolfcamp. Of these, 27 were in the Wolfcamp A, B and D intervals and seven were in the Lower Spraberry Shale interval. Production data from these wells continues to support EURs from 7,000-foot lateral lengths of:
• | 1 million barrels oil equivalent (MMBOE) for Wolfcamp B wells and 800 thousand barrels oil equivalent (MBOE) for Wolfcamp A wells in Midland County, |
• | 800 MBOE for Wolfcamp B wells in Martin County, |
• | 650 MBOE to 800 MBOE for Wolfcamp D wells in Midland, Martin and Andrews counties, and |
• | 575 MBOE to 1 MMBOE for Lower Spraberry Shale wells in Andrews, Glasscock, Martin and Midland counties. |
Additionally, Pioneer placed three horizontal Jo Mill Shale interval wells and three horizontal Middle Spraberry Shale wells on production during the first half of 2014. Results have been mixed from both intervals. The best two Jo Mill Shale interval wells, which are in Midland and Martin counties and have an average lateral length of 5,460 feet, are tracking an 800 MBOE type curve on average. The best Middle Spraberry Shale well, which is in Midland County with a lateral length of 6,182 feet, is tracking a 700 MBOE type curve. Pioneer plans to continue to appraise both of these intervals.
Pioneer is transitioning from a horizontal appraisal program in 2013 to a horizontal development program across its northern acreage during 2014. The Company increased its horizontal rig count in the northern Spraberry/Wolfcamp area from five rigs at year-end 2013 to 16 rigs in early 2014. As a result of this significant increase in rigs, 93 horizontal wells are expected to be placed on production in the northern Spraberry/Wolfcamp area during 2014 with an average lateral length of approximately 8,200 feet. Approximately 85% of the drilling program will be Wolfcamp A, B and D interval wells. The remaining 15% will be Spraberry Shale wells (Lower Spraberry Shale, Jo Mill Shale and Middle Spraberry Shale). Three-well pads are being utilized to drill most of the wells in the 2014 program. The average drilling and completion cost for the 2014 program in the northern acreage is expected to be $8.5 million to $9.0 million per well (reflecting an average lateral length of 8,200 feet and “science” costs). The Company has recently initiated completion optimization testing in Midland and Martin counties, which includes increasing clusters per stage, increasing proppant concentration and reducing fluid volume.
Pioneer expects to place approximately 100 wells on production in the southern Wolfcamp joint venture area during 2014 with an average lateral length of approximately 9,400 feet. Three-well pads are being utilized to drill substantially all of the wells in the 2014 program. The 2014 drilling program is focused on the higher-return areas in northern Upton and Reagan counties (includes Giddings and University Block 2), with approximately two-thirds of the wells being completed in the Wolfcamp B interval and the remainder being a mix of Wolfcamp A, C and D interval wells. The Company’s initial Wolfcamp D interval well in Upton County (University 3-19 #31H) was placed on production in the second quarter, with a peak initial 24-hour production rate of 2,103 barrels oil equivalent per day and 68% oil content. The lateral length of this well was 9,927 feet. Three additional Wolfcamp D interval wells are planned in the second half of the year. The average drilling and completion cost for the 2014 program in the joint venture area is expected to be approximately $8.0 million per well.
During the first half of 2014, Pioneer operated 11 vertical rigs to meet continuous drilling obligations and drill water disposal wells in the Spraberry/Wolfcamp area. The Company expects to reduce the vertical rig count to nine rigs during the second half of the year. Pioneer also expects to place approximately 200 vertical wells on production during 2014. Approximately 90% of the vertical wells in the 2014 drilling program are expected to be completed in the deeper Strawn and Atoka intervals. The Company expects to further reduce its vertical rig count to six rigs in early 2015, allowing it to allocate more of its capital to higher-rate-of-return horizontal drilling.
Pioneer’s second quarter production from the Spraberry/Wolfcamp area (northern acreage and southern Wolfcamp joint venture area combined) averaged 92 MBOEPD. Forty horizontal wells were placed on production during the second quarter, of which 16 wells were in the northern portion of Pioneer’s acreage and 24 wells were in the southern Wolfcamp joint venture area. Pioneer also placed 57 vertical wells on production in the Spraberry/Wolfcamp area during the second quarter.
Second quarter production increased by 6 MBOEPD as compared to the first quarter due to horizontal production growth (4 MBOEPD) and more efficient gas processing operations (2 MBOEPD) resulting from improved plant recoveries and reduced gathering line losses. Oil production was essentially flat between the first quarter and the second quarter as new horizontal oil production in the second quarter was offset by (i) the effects of flush oil production in the first quarter from approximately 3,500 vertical wells coming back online after being shut in during the latter part of the fourth quarter of 2013 due to severe winter weather and (ii) an increase in the amount of shut-in production from wells near horizontal fracture stimulations that occurred during the second quarter as compared to the first quarter.
For 2014, Pioneer expects to place 193 horizontal wells and 200 vertical wells on production in the Spraberry/Wolfcamp area. As a result, production is forecasted to be 96 MBOEPD to 100 MBOEPD in 2014, an increase of 22% to 27% compared to 2013 (narrowed from the Company’s earlier range of 95 MBOEPD to 100 MBOEPD). This growth will be second-half weighted, primarily as a result of adding 11
horizontal rigs early in the year on Pioneer’s northern acreage and moving to three-well pad drilling. The total number of horizontal wells placed on production in the Spraberry/Wolfcamp area is expected to increase from 68 wells in the first half of 2014 to 125 wells in the second half, primarily related to the additional drilling activity in the northern Spraberry/Wolfcamp area.
Over the next ten years, Pioneer plans to increase its horizontal rig count in the Spraberry/Wolfcamp area by five to ten rigs per year. The low end of this range assumes that oil prices will be approximately $80 per barrel, while the high end of the range assumes oil prices of approximately $95 per barrel. To efficiently execute this significant rig ramp, Pioneer is developing a long-term growth plan to ensure that the infrastructure, takeaway and services required to support this growth are identified and in place in a timely manner. The growth plan will focus on optimizing the development of the field and identifying the future requirements for gas processing, pipeline takeaway, field infrastructure, water, oilfield services, tubulars, electricity, systems, buildings and roads.
In the liquids-rich Eagle Ford Shale play in South Texas, Pioneer previously announced that it had successfully downspaced from 1,000-foot spacing between wells to 500-foot spacing between wells in the liquids-rich area of the play. This resulted in the addition of 300 drilling locations. Further downspacing and staggered laterals testing to 175 feet between staggered wells is underway in the liquids-rich areas where the 500-foot spacing was successful. Some areas will include testing of the Lower Eagle Ford Shale interval only, while others will include a combination of Lower and Upper targets. Early results from this testing continue to be encouraging. The potential exists to add 300 to 400 Eagle Ford Shale drilling locations from this program.
Seventeen wells were placed on production in Upper targets during the first half of 2014 as part of the downspacing and staggering program. Early production results from these wells are similar to offset Lower Eagle Ford Shale wells. The Company plans to place 50 wells on production in Upper Eagle Ford Shale targets as part of the downspacing program in 2014. Approximately 25% of Pioneer’s acreage is expected to be prospective for the Upper Eagle Ford Shale.
The Company is now utilizing a two-string casing design instead of a three-string casing design in most of its wells in the liquids-rich area of the Eagle Ford Shale play. This change is lowering drilling costs by $750 thousand to $1.0 million per well, primarily as a result of reducing drilling days and casing costs on each well.
Pioneer has continued to improve its Eagle Ford Shale completion design by increasing the pounds of white sand proppant pumped per foot, increasing the barrels of fracture stimulation fluid pumped per minute in each cluster, reducing cluster spacing and utilizing combinations of the above. This optimization program is increasing EURs by 20% to 30%, which more than offsets the increase in drilling and completion capital.
Pioneer’s second quarter production from the Eagle Ford Shale averaged a record 47 MBOEPD. Thirty-one wells were placed on production during the quarter. For 2014, the Company expects to place approximately 125 liquids-rich wells on production in the Eagle Ford Shale (63 wells in the first half of 2014 and 62 wells in the second half). Most of these wells will be drilled utilizing three-well and four-well pads. The 2014 program reflects longer lateral lengths and larger fracture stimulations compared to 2013. Full-year production is forecasted to range from 46 MBOEPD to 49 MBOEPD, an increase of 22% to 30%, compared to 2013 (narrowed from the Company’s earlier range of 45 MBOEPD to 49 MBOEPD).
2014 Capital Budget
Pioneer’s capital program for 2014 of $3.3 billion (excludes acquisitions, asset retirement obligations, capitalized interest, geological and geophysical G&A and capital expenditures associated with the Alaska and Barnett Shale assets prior to their sale) includes $3.0 billion for drilling and $0.3 billion for vertical integration and the construction of new field and office buildings.
The following provides a breakdown of the drilling capital by asset:
• | Northern Spraberry/Wolfcamp area - $2,165 million (includes $1,225 million for the horizontal drilling program, $440 million for the vertical drilling program, $400 million for infrastructure additions, land and science and $100 million for gas processing facilities) |
• | Southern Wolfcamp joint venture area (net of carry) - $205 million (includes $140 million for the horizontal drilling program and $65 million for infrastructure additions, land and science) |
• | Eagle Ford Shale - $545 million (includes $480 million for the horizontal drilling program and $65 million for infrastructure additions and land) |
• | Other assets - $100 million |
The 2014 capital budget is expected to be funded from forecasted operating cash flow of $2.5 billion (assuming commodity prices of $100 per barrel for oil and $4.50 per thousand cubic feet (MCF) for gas), cash on the balance sheet and the proceeds from divestitures.
Pioneer’s net debt at the end of the second quarter was $2.2 billion with net debt-to-book capitalization of 25%. The Company will continue to target a net debt-to-book capitalization below 35% and net debt-to-operating cash flow below 1.5.
Second Quarter 2014 Financial Review
Sales volumes from continuing operations for the second quarter of 2014 averaged 183 MBOEPD (excludes Alaska and Barnett Shale production, which is reflected in discontinued operations). Oil sales averaged 80 thousand barrels per day (MBPD), natural gas liquids (NGLs) sales averaged 41 MBPD and gas sales averaged 370 million cubic feet per day.
The average realized price for oil was $95.87 per barrel. The average realized price for NGLs was $30.65 per barrel, and the average realized price for gas was $4.38 per MCF. These prices exclude the effects of derivatives.
Production costs from continuing operations averaged $13.96 per barrel oil equivalent (BOE). Depreciation, depletion and amortization (DD&A) expense averaged $14.90 per BOE. Exploration and abandonment costs were $29 million, principally comprised of $3 million associated with drilling and acreage abandonments, $10 million for seismic data and $16 million for personnel costs. General and administrative expense totaled $82 million. Interest expense was $47 million and other expense was $22 million.
Third Quarter 2014 Financial Outlook
The Company’s third quarter 2014 outlook for certain operating and financial items is provided below. This outlook excludes Barnett Shale and Hugoton results of operations as such activity is expected to be reflected in discontinued operations.
Production is forecasted to average 181 MBOEPD to 186 MBOEPD.
Production costs are expected to average $13.50 per BOE to $15.50 per BOE. DD&A expense is expected to average $14.00 per BOE to $16.00 per BOE. Total exploration and abandonment expense is forecasted to be $25 million to $35 million.
General and administrative expense is expected to be $80 million to $85 million, interest expense is expected to be $47 million to $52 million and other expense is expected to be $25 million to $35 million. Accretion of discount on asset retirement obligations is expected to be $3 million to $5 million.
The Company’s effective income tax rate is expected to range from 35% to 40%. Current income taxes are expected to be $10 million to $15 million and are primarily attributable to federal alternative minimum tax and state taxes.
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, August 5, 2014, at 9:00 a.m. Central Time, Pioneer will discuss its financial and operating results for the quarter ended June 30, 2014, with an accompanying presentation. Instructions for listening to the call and viewing the accompanying presentation are shown below.
Internet: www.pxd.com
Select “Investors,” then “Earnings & Webcasts” to listen to the discussion, view the presentation and see other related material.
Telephone: Dial (877) 440-5788 and confirmation code: 5159323 five minutes before the call. View the presentation via Pioneer’s internet address above.
A replay of the webcast will be archived on Pioneer’s website. A telephone replay will be available through August 30, 2014, by dialing (888) 203-1112 and confirmation code: 5159323.
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 Pioneer’s website at 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 divestitures, litigation, the costs and results of drilling and operations, availability of equipment, services, resources and personnel required to perform the Company's drilling and operating activities, access to and availability of transportation, processing, fractionation and refining facilities, Pioneer's ability to replace reserves, implement its business plans or complete its development activities as scheduled, access to and cost of capital, the financial strength of counterparties to Pioneer's credit facility and derivative contracts and the purchasers of Pioneer's oil, NGL and gas production, 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 Securities and Exchange Commission. 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
Mike Bandy - 972-969-4513
Media and Public Affairs
Susan Spratlen - 972-969-4018
Suzanne Hicks - 972-969-4020
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions)
June 30, 2014 | December 31, 2013 | |||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 445 | $ | 393 | ||||
Accounts receivable, net | 465 | 434 | ||||||
Income taxes receivable | 7 | 5 | ||||||
Inventories | 221 | 220 | ||||||
Prepaid expenses | 11 | 16 | ||||||
Assets held for sale | 193 | 584 | ||||||
Derivatives | 1 | 76 | ||||||
Other current assets, net | 37 | 2 | ||||||
Total current assets | 1,380 | 1,730 | ||||||
Property, plant and equipment, at cost: | ||||||||
Oil and gas properties, using the successful efforts method of accounting | 14,753 | 13,529 | ||||||
Accumulated depletion, depreciation and amortization | (5,279 | ) | (4,903 | ) | ||||
Total property, plant and equipment | 9,474 | 8,626 | ||||||
Goodwill | 274 | 274 | ||||||
Other property and equipment, net | 1,230 | 1,224 | ||||||
Investment in unconsolidated affiliate | 229 | 225 | ||||||
Derivatives | 10 | 91 | ||||||
Other assets, net | 113 | 124 | ||||||
$ | 12,710 | $ | 12,294 | |||||
LIABILITIES AND EQUITY | ||||||||
Current liabilities: | ||||||||
Accounts payable | $ | 1,145 | $ | 1,060 | ||||
Interest payable | 62 | 62 | ||||||
Income taxes payable | 1 | — | ||||||
Deferred income taxes | 36 | 19 | ||||||
Liabilities held for sale | 45 | 39 | ||||||
Derivatives | 98 | 12 | ||||||
Other current liabilities | 78 | 58 | ||||||
Total current liabilities | 1,465 | 1,250 | ||||||
Long-term debt | 2,659 | 2,653 | ||||||
Derivatives | 66 | 10 | ||||||
Deferred income taxes | 1,475 | 1,473 | ||||||
Other liabilities | 295 | 293 | ||||||
Equity | 6,750 | 6,615 | ||||||
$ | 12,710 | $ | 12,294 | |||||
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, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Revenues and other income: | ||||||||||||||||
Oil and gas | $ | 959 | $ | 781 | $ | 1,869 | $ | 1,510 | ||||||||
Sales of purchased oil and gas | 205 | 56 | 353 | 112 | ||||||||||||
Interest and other | 3 | (5 | ) | 7 | (5 | ) | ||||||||||
Derivative gains (losses), net | (218 | ) | 144 | (322 | ) | 102 | ||||||||||
Gain on disposition of assets, net | 4 | 183 | 10 | 207 | ||||||||||||
953 | 1,159 | 1,917 | 1,926 | |||||||||||||
Costs and expenses: | ||||||||||||||||
Oil and gas production | 173 | 153 | 338 | 303 | ||||||||||||
Production and ad valorem taxes | 59 | 51 | 116 | 103 | ||||||||||||
Depletion, depreciation and amortization | 248 | 225 | 469 | 437 | ||||||||||||
Purchased oil and gas | 198 | 55 | 341 | 111 | ||||||||||||
Exploration and abandonments | 29 | 18 | 60 | 36 | ||||||||||||
General and administrative | 82 | 66 | 163 | 128 | ||||||||||||
Accretion of discount on asset retirement obligations | 3 | 3 | 6 | 6 | ||||||||||||
Interest | 47 | 43 | 92 | 94 | ||||||||||||
Other | 22 | 22 | 38 | 42 | ||||||||||||
861 | 636 | 1,623 | 1,260 | |||||||||||||
Income from continuing operations before income taxes | 92 | 523 | 294 | 666 | ||||||||||||
Income tax provision | (34 | ) | (183 | ) | (87 | ) | (233 | ) | ||||||||
Income from continuing operations | 58 | 340 | 207 | 433 | ||||||||||||
Income (loss) from discontinued operations, net of tax | (57 | ) | 11 | (83 | ) | 27 | ||||||||||
Net income | 1 | 351 | 124 | 460 | ||||||||||||
Net income attributable to noncontrolling interests | — | (14 | ) | — | (22 | ) | ||||||||||
Net income attributable to common stockholders | $ | 1 | $ | 337 | $ | 124 | $ | 438 | ||||||||
Basic earnings per share attributable to common stockholders: | ||||||||||||||||
Income from continuing operations | $ | 0.41 | $ | 2.37 | $ | 1.44 | $ | 3.03 | ||||||||
Income (loss) from discontinued operations | (0.40 | ) | 0.05 | (0.58 | ) | 0.21 | ||||||||||
Net income | $ | 0.01 | $ | 2.42 | $ | 0.86 | $ | 3.24 | ||||||||
Diluted earnings per share attributable to common stockholders: | ||||||||||||||||
Income from continuing operations | $ | 0.41 | $ | 2.35 | $ | 1.44 | $ | 2.95 | ||||||||
Income (loss) from discontinued operations | (0.40 | ) | 0.05 | (0.58 | ) | 0.24 | ||||||||||
Net income | $ | 0.01 | $ | 2.40 | $ | 0.86 | $ | 3.19 | ||||||||
Weighted average shares outstanding: | ||||||||||||||||
Basic | 143 | 138 | 143 | 133 | ||||||||||||
Diluted | 143 | 139 | 143 | 136 | ||||||||||||
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Cash flows from operating activities: | ||||||||||||||||
Net income | $ | 1 | $ | 351 | $ | 124 | $ | 460 | ||||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||||||
Depletion, depreciation and amortization | 248 | 225 | 469 | 437 | ||||||||||||
Impairment of inventory and other property and equipment | 4 | 2 | 4 | 4 | ||||||||||||
Exploration expenses, including dry holes | 3 | 1 | 10 | 1 | ||||||||||||
Deferred income taxes | 28 | 176 | 69 | 219 | ||||||||||||
Gain on disposition of assets, net | (4 | ) | (183 | ) | (10 | ) | (207 | ) | ||||||||
Accretion of discount on asset retirement obligations | 3 | 3 | 6 | 6 | ||||||||||||
Discontinued operations | 70 | 25 | 166 | 60 | ||||||||||||
Interest expense | 5 | 4 | 9 | 9 | ||||||||||||
Derivative related activity | 212 | (110 | ) | 298 | (14 | ) | ||||||||||
Amortization of stock-based compensation | 21 | 17 | 43 | 34 | ||||||||||||
Other | 21 | (4 | ) | 28 | (8 | ) | ||||||||||
Change in operating assets and liabilities: | ||||||||||||||||
Accounts receivable, net | (22 | ) | 9 | (59 | ) | (33 | ) | |||||||||
Income taxes receivable | (7 | ) | 1 | (2 | ) | 7 | ||||||||||
Inventories | 8 | (2 | ) | (8 | ) | (1 | ) | |||||||||
Prepaid expenses | 3 | (10 | ) | 2 | (10 | ) | ||||||||||
Other current assets | (1 | ) | 4 | (4 | ) | 3 | ||||||||||
Accounts payable | 100 | 48 | 30 | (9 | ) | |||||||||||
Interest payable | 26 | 23 | — | (7 | ) | |||||||||||
Income taxes payable | (8 | ) | 1 | 1 | 1 | |||||||||||
Other current liabilities | 7 | (5 | ) | 7 | (15 | ) | ||||||||||
Net cash provided by operating activities | 718 | 576 | 1,183 | 937 | ||||||||||||
Net cash used in investing activities | (477 | ) | (106 | ) | (1,103 | ) | (814 | ) | ||||||||
Net cash provided by (used in) financing activities | (53 | ) | (204 | ) | (28 | ) | 344 | |||||||||
Net increase in cash and cash equivalents | 188 | 266 | 52 | 467 | ||||||||||||
Cash and cash equivalents, beginning of period | 257 | 430 | 393 | 229 | ||||||||||||
Cash and cash equivalents, end of period | $ | 445 | $ | 696 | $ | 445 | $ | 696 | ||||||||
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUMMARY PRODUCTION AND PRICE DATA
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Average Daily Sales Volumes from Continuing Operations: | ||||||||||||||||
Oil (Bbls) | 79,780 | 69,501 | 79,188 | 69,145 | ||||||||||||
Natural gas liquids ("NGL") (Bbls) | 41,302 | 31,231 | 38,548 | 30,595 | ||||||||||||
Gas (Mcf) | 369,987 | 376,267 | 357,835 | 368,018 | ||||||||||||
Total (BOE) | 182,747 | 163,443 | 177,375 | 161,076 | ||||||||||||
Average Realized Prices from Continuing Operations: | ||||||||||||||||
Oil (per Bbl) | $ | 95.87 | $ | 90.35 | $ | 94.15 | $ | 89.03 | ||||||||
NGL (per Bbl) | $ | 30.65 | $ | 28.54 | $ | 31.91 | $ | 29.67 | ||||||||
Gas (per Mcf) | $ | 4.38 | $ | 3.76 | $ | 4.58 | $ | 3.47 | ||||||||
Total (BOE) | $ | 57.64 | $ | 52.52 | $ | 58.21 | $ | 51.78 | ||||||||
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- and unit-based awards with guaranteed dividend or distribution participation rights qualify as "participating securities" during their vesting periods. The Company's basic net income per share attributable to common stockholders is computed as (i) net income attributable to common stockholders, (ii) less participating share- and unit-based basic earnings (iii) divided by weighted average basic shares outstanding. The Company's diluted net income per share attributable to common stockholders is computed as (i) basic net income attributable to common stockholders, (ii) plus the reallocation of participating earnings (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 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 attributable to common stockholders to basic and diluted net income attributable to common stockholders for the three and six months ended June 30, 2014 and 2013:
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
(in millions) | ||||||||||||||||
Net income attributable to common stockholders | $ | 1 | $ | 337 | $ | 124 | $ | 438 | ||||||||
Participating basic earnings | — | (4 | ) | (1 | ) | (6 | ) | |||||||||
Basic and diluted net income attributable to common stockholders | $ | 1 | $ | 333 | $ | 123 | $ | 432 | ||||||||
The following table is a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three and six months ended June 30, 2014 and 2013:
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||
(in millions) | ||||||||||||
Weighted average common shares outstanding: | ||||||||||||
Basic | 143 | 138 | 143 | 133 | ||||||||
Convertible senior notes dilution | — | 1 | — | 3 | ||||||||
Diluted (a) | 143 | 139 | 143 | 136 | ||||||||
_______________
(a) | Options to purchase 5,707 and 52,263 shares of the Company's common stock were excluded from the diluted income per share calculations for the three and six months ended June 30, 2013, respectively, because they would have been anti-dilutive to the calculation. |
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 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 or net cash provided by operating activities, as defined by GAAP.
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Net income | $ | 1 | $ | 351 | $ | 124 | $ | 460 | ||||||||
Depletion, depreciation and amortization | 248 | 225 | 469 | 437 | ||||||||||||
Exploration and abandonments | 29 | 18 | 60 | 36 | ||||||||||||
Impairment of inventory and other property and equipment | 4 | 2 | 4 | 4 | ||||||||||||
Accretion of discount on asset retirement obligations | 3 | 3 | 6 | 6 | ||||||||||||
Interest expense | 47 | 43 | 92 | 94 | ||||||||||||
Income tax provision | 34 | 183 | 87 | 233 | ||||||||||||
Gain on disposition of assets, net | (4 | ) | (183 | ) | (10 | ) | (207 | ) | ||||||||
(Income) loss from discontinued operations | 57 | (11 | ) | 83 | (27 | ) | ||||||||||
Derivative related activity | 212 | (110 | ) | 298 | (14 | ) | ||||||||||
Amortization of stock-based compensation | 21 | 17 | 43 | 34 | ||||||||||||
Other | 21 | (4 | ) | 28 | (8 | ) | ||||||||||
EBITDAX (a) | 673 | 534 | 1,284 | 1,048 | ||||||||||||
Cash interest expense | (42 | ) | (39 | ) | (83 | ) | (85 | ) | ||||||||
Current income tax provision | (6 | ) | (7 | ) | (18 | ) | (14 | ) | ||||||||
Discretionary cash flow (b) | 625 | 488 | 1,183 | 949 | ||||||||||||
Discontinued operations cash activity | 13 | 36 | 83 | 87 | ||||||||||||
Cash exploration expense | (26 | ) | (17 | ) | (50 | ) | (35 | ) | ||||||||
Changes in operating assets and liabilities | 106 | 69 | (33 | ) | (64 | ) | ||||||||||
Net cash provided by operating activities | $ | 718 | $ | 576 | $ | 1,183 | $ | 937 | ||||||||
_______________
(a) | “EBITDAX” represents earnings before depletion, depreciation and amortization expense; exploration and abandonments; 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; (income) loss from discontinued operations; noncash derivative related activity; amortization of stock-based compensation and other items. |
(b) | Discretionary cash flow equals cash flows from operating activities before changes in operating assets and liabilities and 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, and adjusted income excluding MTM derivative losses and unusual items, as presented in this press release, are presented and reconciled to Pioneer's net income attributable to common stockholders (determined in accordance with GAAP) because Pioneer believes that these non-GAAP financial measures reflect an additional way of viewing aspects of Pioneer's business that, when viewed together with its financial results computed in accordance with GAAP, 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 income attributable to common stockholders for the three months ended June 30, 2014, as determined in accordance with GAAP, to income adjusted for noncash MTM derivative losses and 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 | $ | 1 | $ | 0.01 | |||
Noncash MTM derivative losses | 137 | 0.94 | |||||
Income adjusted for noncash MTM derivative losses | 138 | 0.95 | |||||
Loss associated with discontinued operations (a) | 57 | 0.40 | |||||
Adjusted income excluding noncash MTM derivative losses and unusual items | $ | 195 | $ | 1.35 | |||
_______________
(a) | Represents second quarter results of operations for the Barnett Shale and Alaska assets, a fair value adjustment to reduce the carrying value of the Barnett Shale assets to their estimated sales price and miscellaneous adjustments related to the final sale of Alaska. |
PIONEER NATURAL RESOURCES COMPANY
SUPPLEMENTAL INFORMATION
Open Commodity Derivative Positions as of August 1, 2014
(Volumes are average daily amounts)
2014 | Year Ending December 31, | |||||||||||||||
Third Quarter | Fourth Quarter | 2015 | 2016 | |||||||||||||
Average Daily Oil Production Associated with Derivatives (Bbl): | ||||||||||||||||
Collar contracts with short puts: | ||||||||||||||||
Volume (a) | 69,000 | 69,000 | 95,767 | 58,000 | ||||||||||||
NYMEX price: | ||||||||||||||||
Ceiling | $ | 114.05 | $ | 114.05 | $ | 99.36 | $ | 98.53 | ||||||||
Floor | $ | 93.70 | $ | 93.70 | $ | 87.98 | $ | 86.12 | ||||||||
Short put | $ | 77.61 | $ | 77.61 | $ | 73.54 | $ | 74.66 | ||||||||
Swap contracts: | ||||||||||||||||
Volume | 10,000 | 15,000 | — | — | ||||||||||||
NYMEX price | $ | 93.87 | $ | 96.31 | $ | — | $ | — | ||||||||
Rollfactor swap contracts: | ||||||||||||||||
Volume | 10,000 | 10,000 | 5,000 | — | ||||||||||||
NYMEX roll price (b) | $ | 1.10 | $ | 1.10 | $ | 0.60 | $ | — | ||||||||
Average Daily NGL Production Associated with Derivatives (Bbl): | ||||||||||||||||
Collar contracts with short puts (c): | ||||||||||||||||
Volume | 3,500 | 3,500 | — | — | ||||||||||||
Index price: | ||||||||||||||||
Ceiling | $ | 97.93 | $ | 97.93 | $ | — | $ | — | ||||||||
Floor | $ | 90.14 | $ | 90.14 | $ | — | $ | — | ||||||||
Short put | $ | 81.36 | $ | 81.36 | $ | — | $ | — | ||||||||
Collar contracts (d): | ||||||||||||||||
Volume | 3,000 | 3,000 | — | — | ||||||||||||
Index price: | ||||||||||||||||
Ceiling | $ | 13.72 | $ | 13.72 | $ | — | $ | — | ||||||||
Floor | $ | 10.78 | $ | 10.78 | $ | — | $ | — | ||||||||
Swap contracts (e): | ||||||||||||||||
Volume | 3,000 | 1,674 | — | — | ||||||||||||
Index price | $ | 48.20 | $ | 47.95 | $ | — | $ | — | ||||||||
Average Daily Gas Production Associated with Derivatives (MMBtu): | ||||||||||||||||
Collar contracts with short puts: | ||||||||||||||||
Volume | 115,000 | 115,000 | 285,000 | 20,000 | ||||||||||||
NYMEX price: | ||||||||||||||||
Ceiling | $ | 4.70 | $ | 4.70 | $ | 5.07 | $ | 5.36 | ||||||||
Floor | $ | 4.00 | $ | 4.00 | $ | 4.00 | $ | 4.00 | ||||||||
Short put | $ | 3.00 | $ | 3.00 | $ | 3.00 | $ | 3.00 | ||||||||
Swap contracts: | ||||||||||||||||
Volume | 195,000 | 195,000 | 20,000 | — | ||||||||||||
NYMEX price (f) | $ | 4.04 | $ | 4.04 | $ | 4.31 | $ | — | ||||||||
Basis swap contracts: | ||||||||||||||||
Permian Basin index swap volume (g) | 10,000 | 10,000 | 10,000 | — | ||||||||||||
Price differential ($/MMBtu) | $ | 0.35 | $ | 0.09 | $ | (0.13 | ) | $ | — | |||||||
Mid-Continent index swap volume (g) | 120,000 | 120,000 | 80,000 | — | ||||||||||||
Price differential ($/MMBtu) | $ | (0.22 | ) | $ | (0.22 | ) | $ | (0.23 | ) | $ | — | |||||
_______________
(a) | Counterparties have the option to extend 5,000 BBLs per day of 2015 collar contracts with short puts for an additional year with a ceiling price of $100.08 per BBL, a floor price of $90.00 per BBL and a short put price of $80.00 per BBL. The option to extend is exercisable by the counterparties on December 31, 2015. |
(b) | Represent swaps that fix the difference between (i) each day's price per Bbl of West Texas Intermediate oil ("WTI") for the first nearby month less (ii) the price per Bbl of WTI for the second nearby NYMEX month, multiplied by .6667; plus (iii) each day's price per Bbl of WTI for the first nearby month less (iv) the price per Bbl of WTI for the third nearby NYMEX month, multiplied by .3333. |
(c) | Represent collar contracts with short puts that reduce the price volatility of natural gasoline forecasted for sale by the Company at Mont Belvieu, Texas-posted prices. |
(d) | Represent collar contracts that reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices. |
(e) | Represent collar contracts that reduce the price volatility of propane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices. |
(f) | Represents the NYMEX Henry Hub index price on the derivative trade date. |
(g) | Represent swaps that fix the basis differentials between the indices price at which the Company sells its Permian Basin and Mid-Continent gas and the NYMEX Henry Hub index price used in gas swap and collar contracts. |
Interest rate derivatives. During the period ended June 30, 2014, the Company terminated its interest rate derivative contracts for cash proceeds of $14 million. Prior to termination, the Company received a fixed interest rate of 3.95 percent in exchange for paying a floating interest rate comprised of the three-month LIBOR plus an average rate of 1.11 percent on a notional amount of $400 million.
Marketing and basis transfer derivatives. Periodically, the Company enters into buy and sell marketing arrangements to fulfill firm pipeline transportation commitments. Associated with these marketing arrangements, the Company may enter into index swaps to mitigate price risk. As of August 1, 2014, the Company had marketing gas index swap contracts for 40,000 MMBTU per day for the remainder of 2014 with a price differential of $0.31 per MMBTU between Permian Basin index prices and southern California index prices.
Derivative Losses, Net
(in millions)
The following table summarizes net derivative gains and losses that the Company has recorded in earnings for the three and six months ended June 30, 2014:
Three Months Ended June 30, 2014 | Six Months Ended June 30, 2014 | |||||||
Noncash changes in fair value: | ||||||||
Oil derivative losses | $ | (213 | ) | $ | (279 | ) | ||
NGL derivative losses | (2 | ) | (1 | ) | ||||
Gas derivative gains (losses) | 9 | (18 | ) | |||||
Interest rate derivative gains (losses) | (6 | ) | — | |||||
Total noncash derivative losses, net | (212 | ) | (298 | ) | ||||
Net cash receipts (payments) on settled derivative instruments: | ||||||||
Oil derivative payments | (11 | ) | (14 | ) | ||||
NGL derivative receipts | 1 | 1 | ||||||
Gas derivative payments | (10 | ) | (29 | ) | ||||
Interest rate derivative receipts | 14 | 18 | ||||||
Total cash derivative payments, net | (6 | ) | (24 | ) | ||||
Total derivative losses, net | $ | (218 | ) | $ | (322 | ) | ||