EXHIBIT 99.1
News Release
Pioneer Natural Resources Reports
First Quarter 2014 Financial and Operating Results
Dallas, Texas, May 6, 2014 -- Pioneer Natural Resources Company (NYSE:PXD) (“Pioneer” or “the Company”) today announced financial and operating results for the quarter ended March 31, 2014.
Pioneer reported first quarter net income attributable to common stockholders of $123 million, or $0.85 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 first quarter was $183 million after tax, or $1.26 per diluted share.
First quarter and other recent highlights included:
• | producing 172 thousand barrels oil equivalent per day (MBOEPD) from continuing operations in the first quarter (reflects Alaska and Barnett Shale as discontinued operations); first quarter production was up 8 MBOEPD, or 5%, compared to the fourth quarter of 2013; first quarter production growth was primarily driven by the Company’s successful Spraberry/Wolfcamp and Eagle Ford Shale horizontal drilling programs and the full recovery of weather-related production curtailments experienced during the fourth quarter; |
• | continuing to forecast annual production growth from continuing operations of 14% to 19% from 2013 to 2014 based on planned drilling capital expenditures of $3.0 billion; as planned, the Company has increased its drilling rig program in the northern Spraberry/Wolfcamp from five horizontal rigs at year-end 2013 to 16 rigs, with these rigs drilling mostly three-well pads; total horizontal wells placed on production in the Spraberry/Wolfcamp and Eagle Ford Shale are expected to increase from 125 wells in the first half of 2014 to 175 wells in the second half of the year; this increase is being driven by the additional drilling activity in the northern Spraberry/Wolfcamp and is expected to result in the Company’s production growth being weighted towards the second-half of the year; |
• | continuing to target compound annual production growth from continuing operations of 16% to 21% for 2014 to 2016 and expecting to more than double production by 2018 as compared to 2013; |
• | closing the sale of Pioneer’s Alaska subsidiary in April; |
• | continuing to pursue the sale of Pioneer’s Barnett Shale assets; |
• | ensuring adequate gas processing capacity across the Spraberry/Wolfcamp play as drilling activity grows by extending Pioneer’s agreement with Atlas Pipeline Partners for 10 years through 2032; this agreement includes 400 million cubic feet per day of new processing capacity coming online by the second half of 2015; |
• | having derivative coverage for approximately 90% of forecasted 2014 oil production at $93 per barrel or higher; |
• | having approximately 80% of the Company’s Spraberry/Wolfcamp oil production protected against volatility in the Midland-Cushing oil price differential; |
• | maintaining a strong balance sheet with $257 million of cash on hand at the end of the first quarter and net debt-to-book capitalization of 27%; |
• | continuing to observe production data from Pioneer’s horizontal Wolfcamp and Lower Spraberry Shale interval wells on its northern Spraberry/Wolfcamp acreage that supports strong estimated ultimate recoveries (EURs) and internal rates of return (IRRs); |
• | increasing the upper end of the EUR range for horizontal Lower Spraberry Shale wells with 7,000-foot lateral lengths on Pioneer’s northern Spraberry/Wolfcamp acreage from 800 thousand barrels oil equivalent (MBOE) to 1 million barrels oil equivalent (MMBOE) based on recent performance data; |
• | placing on production a horizontal Jo Mill Shale interval well and Pioneer’s first Middle Spraberry Shale interval well on the Company’s northern Spraberry/Wolfcamp acreage; early production from these wells is tracking Pioneer’s successful Lower Spraberry Shale wells; |
• | placing on production 12 Upper Eagle Ford Shale wells through mid-April as part of the continuing downspacing program in this play; results continue to be encouraging; and |
• | reducing drilling costs by $750 thousand per well to $1.0 million per well in the Eagle Ford Shale by utilizing a two-string drilling design instead of a three-string drilling design. |
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. Importantly, oil production grew 9% in the first quarter of 2014 as compared to the fourth quarter of 2013.”
“Our main objective in 2014 is to translate the substantial resource growth we delivered in 2013 into strong production growth. To accomplish this, we increased our horizontal rig count in the northern Spraberry/Wolfcamp from five rigs at the end of 2013 to 16 rigs currently. We are also continuing an active horizontal drilling program in the southern Wolfcamp joint venture area and the Eagle Ford Shale. We continue to expect a 14% to 19% increase in production in 2014 compared to 2013. 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 and more than double production by 2018 as compared to 2013.”
Mark-To-Market Derivative Losses and Unusual Items Included in First Quarter 2014 Earnings
Pioneer’s first quarter earnings included noncash mark-to-market losses on derivatives of $55 million after tax, or $0.38 per diluted share.
First quarter earnings also included a net loss of $5 million after tax, or $0.03 per diluted share, related to the following unusual items:
• | a loss of $26 million after tax, or $0.18 per diluted share, associated with discontinued operations and |
• | a gain of $21 million after tax, or $0.15 per diluted share, related to a tax benefit inherited with the Premier Silica acquisition. |
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 23 horizontal oil wells on production during 2013 and the first quarter of 2014 across its northern acreage position. Of these, 17 wells are in the Wolfcamp A, B and D intervals in the northern Spraberry/Wolfcamp. Production data from these wells continues to support EURs and before-tax IRRs for wells with 7,000-foot lateral lengths of:
• | 1 MMBOE EURs and 100+% IRRs for Wolfcamp B wells and 800 MBOE for Wolfcamp A wells in Midland County, |
• | 800 MBOE EURs and 100+% IRRs for Wolfcamp B wells in Martin County, and |
• | 650 MBOE to 800 MBOE EURs and 45% to 95% IRRs for Wolfcamp D wells in Midland, Martin and Andrews counties. |
The remaining six wells placed on production were in the Lower Spraberry Shale interval in Andrews, Glasscock, Martin and Midland counties. The Lower Spraberry Shale interval is estimated to contain 40 million to 60 million barrels of oil per section on Pioneer’s acreage, making it one of the highest oil-in-place intervals in the Spraberry/Wolfcamp play. Wells completed in this interval typically take 30 days to 60 days to flow back fracture stimulation water before reaching a 24-hour peak initial production rate. Production data from Pioneer’s first six wells suggests that Lower Spraberry Shale wells will decline slower than deeper Wolfcamp interval wells and deliver EURs for 7,000-foot lateral wells that will range from 575 MBOE to 1 MMBOE, with before-tax IRRs ranging from 45% to 100+%. The Company recently increased the high end of the Lower Spraberry Shale EUR range from 800 MBOE to 1 MMBOE to reflect the continuing strong performance of several of these wells.
In early April, Pioneer also placed on production a Jo Mill Shale horizontal well (Glasscock A5 #2H in Martin County - 4,700-foot lateral length) and the Company’s first Middle Spraberry Shale horizontal well (SSU #0102H in Midland County - 4,152-foot lateral length). Early production performance of these wells is closely tracking the production profile of the six horizontal Lower Spraberry Shale wells placed on production to date by the Company.
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 as planned. The 16-rig program is expected to drill approximately 140 wells during 2014 with an average lateral length of approximately 8,200 feet. Approximately 90 wells are expected to be placed on production during the year in this area. 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). The Spraberry Shale well component of the mix has recently been increased from 10% to 15% in recognition of the strong performance of the Lower Spraberry Shale interval wells and the favorable early results from the Jo Mill Shale and Middle Spraberry Shale interval wells that were placed on production in April. Three-well pads will be utilized to drill most of the wells in the 2014 program, and “science” activity will be reduced from 2013 levels. 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).
Pioneer expects to drill approximately 115 horizontal wells in the southern Wolfcamp joint venture area in 2014 with an average lateral length of approximately 9,400 feet. Approximately 100 wells are expected to be placed on production during the year. Three-well pads will be utilized to drill substantially all of the wells in the 2014 program. The 2014 drilling program will be 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 average drilling and completion cost for the 2014 program in the joint venture area is expected to be approximately $8.0 million per well.
Pioneer is currently operating 11 vertical rigs to meet continuous drilling obligations in the Spraberry field, with approximately 200 vertical wells expected to be drilled in 2014. Approximately 90% of the vertical wells in the 2014 drilling program are expected to be completed in the deeper Strawn and Atoka intervals. With only 11 rigs running, vertical production is expected to decline in 2014 by approximately 10%. The Company expects to further reduce its vertical rig count going forward, allowing it to devote more of its capital to higher-rate-of-return horizontal drilling.
Pioneer’s first quarter production from the Spraberry/Wolfcamp (northern acreage and southern Wolfcamp joint venture area) averaged 86 MBOEPD. Fifty-six horizontal wells were drilled and 28 horizontal wells were placed on production during the quarter. Of the 28 wells placed on production, five were in the northern portion of Pioneer’s acreage and 23 were in the southern Wolfcamp joint venture area. Pioneer also drilled 63 vertical wells in the first quarter.
For 2014, Pioneer expects to drill approximately 255 horizontal wells and 200 vertical wells across its northern acreage and southern Wolfcamp joint venture area and place approximately 190 horizontal wells and 200 vertical wells on production. As a result, production is forecasted to be 95 MBOEPD to 100 MBOEPD in 2014, an increase of 21% to 27% compared to 2013. 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. Total horizontal wells placed on production in the Spraberry/Wolfcamp are expected to increase from 67 wells in the first half of 2014 to 123 wells in the second half, with this increase primarily related to the additional drilling activity in the northern Spraberry/Wolfcamp.
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 the Lower and Upper intervals. 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.
Twelve Upper Eagle Ford Shale wells have been placed on production through mid-April as part of the downspacing and staggering program. Early production results from these wells continue to be encouraging and in line with offset Lower Eagle Ford Shale wells. The Company plans to drill 45 Upper Eagle Ford Shale wells as part of the downspacing program in 2014. Approximately 25% of Pioneer’s acreage is expected to be prospective for this interval.
The Company has commenced utilizing a two-string drilling design instead of a three-string drilling design in the liquids-rich area of the play. This change is lowering drilling costs by $750 thousand per well 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 reducing cluster spacing, increasing the pounds of white sand proppant pumped per foot, increasing the barrels of fracture stimulation fluid pumped per minute in each cluster and utilizing combinations of the above. This optimization program is increasing EURs by 20% to 30% with only a minimal increase in drilling and completion capital and generating before-tax returns of 100% on the incremental capital spent.
Pioneer’s first quarter production from the Eagle Ford Shale averaged a record 43 MBOEPD. Thirty-four wells were drilled and 32 wells were placed on production during the quarter. For 2014, the Company expects to drill approximately 110 liquids-rich wells in the Eagle Ford Shale and place a similar number of wells on production (58 wells in the first half of 2014 and 52 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 45 MBOEPD to 49 MBOEPD, an increase of 18% to 29% compared to 2013.
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 $95 per barrel for oil and $4.50 per thousand cubic feet (MCF) for gas), cash on the balance sheet and the proceeds from planned divestitures.
Pioneer’s net debt at the end of the first quarter was $2.4 billion with net debt-to-book capitalization of 27%. The Company will continue to target a net debt-to-book capitalization below 35% and net debt-to-operating cash flow below 1.5.
First Quarter 2014 Financial Review
Sales volumes from continuing operations for the first quarter of 2014 averaged 172 MBOEPD (excludes Alaska and Barnett Shale production, which is reflected in discontinued operations). Oil sales averaged 79 thousand barrels per day (MBPD), natural gas liquids (NGLs) sales averaged 36 MBPD and gas sales averaged 345 million cubic feet per day.
The average realized price for oil was $92.38 per barrel. The average realized price for NGLs was $33.38 per barrel, and the average realized price for gas was $4.81 per MCF. These prices exclude derivatives.
Production costs from continuing operations averaged $14.33 per barrel oil equivalent (BOE). Depreciation, depletion and amortization (DD&A) expense averaged $14.27 per BOE. Exploration and abandonment costs were $31 million, principally comprised of $7 million associated with drilling and acreage abandonments, $7 million for seismic data and $17 million for personnel costs. General and administrative expense totaled $81 million, which included increased employee related costs in support of the Company's growth initiatives. Interest expense was $45 million and other expense was $16 million.
Second Quarter 2014 Financial Outlook
The Company’s second quarter 2014 outlook for certain operating and financial items is provided below. This outlook excludes Alaska and Barnett Shale results of operations as such activity will be reflected in discontinued operations.
Production is forecasted to average 173 MBOEPD to 178 MBOEPD.
Production costs are expected to average $13.50 per BOE to $15.50 per BOE. DD&A expense is expected to average $13.50 per BOE to $15.50 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 Wednesday, May 7, 2014, at 9:00 a.m. Central Time, Pioneer will discuss its financial and operating results for the quarter ended March 31, 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 (888) 617-5714 and confirmation code: 7791759 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 June 1, 2014, by dialing (888) 203-1112 and confirmation code: 7791759.
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 complete the Company's 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 resources 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)
March 31, 2014 | December 31, 2013 | |||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 257 | $ | 393 | ||||
Accounts receivable, net | 439 | 434 | ||||||
Income taxes receivable | — | 5 | ||||||
Inventories | 231 | 220 | ||||||
Prepaid expenses | 13 | 16 | ||||||
Assets held for sale | 554 | 584 | ||||||
Derivatives | 43 | 76 | ||||||
Other current assets, net | 5 | 2 | ||||||
Total current assets | 1,542 | 1,730 | ||||||
Property, plant and equipment, at cost: | ||||||||
Oil and gas properties, using the successful efforts method of accounting | 14,025 | 13,529 | ||||||
Accumulated depletion, depreciation and amortization | (5,035 | ) | (4,903 | ) | ||||
Total property, plant and equipment | 8,990 | 8,626 | ||||||
Goodwill | 274 | 274 | ||||||
Other property and equipment, net | 1,225 | 1,224 | ||||||
Investment in unconsolidated affiliate | 239 | 225 | ||||||
Derivatives | 62 | 91 | ||||||
Other assets, net | 133 | 124 | ||||||
$ | 12,465 | $ | 12,294 | |||||
LIABILITIES AND EQUITY | ||||||||
Current liabilities: | ||||||||
Accounts payable | $ | 971 | $ | 1,060 | ||||
Interest payable | 36 | 62 | ||||||
Income taxes payable | 9 | — | ||||||
Deferred income taxes | 20 | 19 | ||||||
Liabilities held for sale | 93 | 39 | ||||||
Derivatives | 41 | 12 | ||||||
Other current liabilities | 68 | 58 | ||||||
Total current liabilities | 1,238 | 1,250 | ||||||
Long-term debt | 2,706 | 2,653 | ||||||
Derivatives | 5 | 10 | ||||||
Deferred income taxes | 1,496 | 1,473 | ||||||
Other liabilities | 296 | 293 | ||||||
Equity | 6,724 | 6,615 | ||||||
$ | 12,465 | $ | 12,294 | |||||
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per share data)
Three Months Ended March 31, | ||||||||
2014 | 2013 | |||||||
Revenues and other income: | ||||||||
Oil and gas | $ | 910 | $ | 729 | ||||
Sales of purchased oil and gas | 147 | 56 | ||||||
Interest and other | 4 | — | ||||||
Derivative losses, net | (104 | ) | (42 | ) | ||||
Gain on disposition of assets, net | 6 | 24 | ||||||
963 | 767 | |||||||
Costs and expenses: | ||||||||
Oil and gas production | 165 | 150 | ||||||
Production and ad valorem taxes | 57 | 52 | ||||||
Depletion, depreciation and amortization | 221 | 212 | ||||||
Purchased oil and gas | 143 | 56 | ||||||
Exploration and abandonments | 31 | 18 | ||||||
General and administrative | 81 | 62 | ||||||
Accretion of discount on asset retirement obligations | 3 | 3 | ||||||
Interest | 45 | 51 | ||||||
Other | 15 | 20 | ||||||
761 | 624 | |||||||
Income from continuing operations before income taxes | 202 | 143 | ||||||
Income tax provision | (53 | ) | (50 | ) | ||||
Income from continuing operations | 149 | 93 | ||||||
Income (loss) from discontinued operations, net of tax | (26 | ) | 16 | |||||
Net income | 123 | 109 | ||||||
Net income attributable to noncontrolling interests | — | (8 | ) | |||||
Net income attributable to common stockholders | $ | 123 | $ | 101 | ||||
Basic earnings per share attributable to common stockholders: | ||||||||
Income from continuing operations | $ | 1.03 | $ | 0.65 | ||||
Income (loss) from discontinued operations | (0.18 | ) | 0.12 | |||||
Net income | $ | 0.85 | $ | 0.77 | ||||
Diluted earnings per share attributable to common stockholders: | ||||||||
Income from continuing operations | $ | 1.03 | $ | 0.63 | ||||
Income (loss) from discontinued operations | (0.18 | ) | 0.12 | |||||
Net income | $ | 0.85 | $ | 0.75 | ||||
Weighted average shares outstanding: | ||||||||
Basic | 143 | 129 | ||||||
Diluted | 143 | 133 | ||||||
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
Three Months Ended March 31, | ||||||||
2014 | 2013 | |||||||
Cash flows from operating activities: | ||||||||
Net income | $ | 123 | $ | 109 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||
Depletion, depreciation and amortization | 221 | 212 | ||||||
Exploration expenses, including dry holes | 7 | — | ||||||
Deferred income taxes | 41 | 44 | ||||||
Gain on disposition of assets, net | (6 | ) | (24 | ) | ||||
Accretion of discount on asset retirement obligations | 3 | 3 | ||||||
Discontinued operations | 96 | 35 | ||||||
Interest expense | 4 | 5 | ||||||
Derivative related activity | 86 | 96 | ||||||
Amortization of stock-based compensation | 22 | 17 | ||||||
Other noncash items | 8 | (4 | ) | |||||
Change in operating assets and liabilities: | ||||||||
Accounts receivable, net | (37 | ) | (42 | ) | ||||
Income taxes receivable | 5 | 6 | ||||||
Inventories | (16 | ) | 1 | |||||
Prepaid expenses | (1 | ) | — | |||||
Other current assets | (3 | ) | (1 | ) | ||||
Accounts payable | (70 | ) | (57 | ) | ||||
Interest payable | (26 | ) | (30 | ) | ||||
Income taxes payable | 9 | — | ||||||
Other current liabilities | — | (10 | ) | |||||
Net cash provided by operating activities | 466 | 360 | ||||||
Net cash used in investing activities | (626 | ) | (707 | ) | ||||
Net cash provided by financing activities | 24 | 548 | ||||||
Net increase (decrease) in cash and cash equivalents | (136 | ) | 201 | |||||
Cash and cash equivalents, beginning of period | 393 | 229 | ||||||
Cash and cash equivalents, end of period | $ | 257 | $ | 430 | ||||
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUMMARY PRODUCTION AND PRICE DATA
Three Months Ended March 31, | ||||||||
2014 | 2013 | |||||||
Average Daily Sales Volumes from Continuing Operations: | ||||||||
Oil (Bbls) | 78,589 | 68,786 | ||||||
Natural gas liquids ("NGL") (Bbls) | 35,763 | 29,951 | ||||||
Gas (Mcf) | 345,549 | 359,677 | ||||||
Total (BOE) | 171,944 | 158,683 | ||||||
Average Realized Prices from Continuing Operations: | ||||||||
Oil (per Bbl) | $ | 92.38 | $ | 87.67 | ||||
NGL (per Bbl) | $ | 33.38 | $ | 30.86 | ||||
Gas (per Mcf) | $ | 4.81 | $ | 3.17 | ||||
Total (BOE) | $ | 58.83 | $ | 51.01 | ||||
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 months ended March 31, 2014 and 2013:
Three Months Ended March 31, | ||||||||
2014 | 2013 | |||||||
(in millions) | ||||||||
Net income attributable to common stockholders | $ | 123 | $ | 101 | ||||
Participating basic earnings | (1 | ) | (1 | ) | ||||
Basic and diluted net income attributable to common stockholders | $ | 122 | $ | 100 | ||||
The following table is a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three months ended March 31, 2014 and 2013:
Three Months Ended March 31, | ||||||
2014 | 2013 | |||||
(in millions) | ||||||
Weighted average common shares outstanding: | ||||||
Basic | 143 | 129 | ||||
Convertible senior notes dilution | — | 4 | ||||
Diluted (a) | 143 | 133 | ||||
_______________
(a) | Options to purchase 98,819 shares of the Company's common stock were excluded from the diluted income per share calculations for the three months ended March 31, 2013 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 March 31, | ||||||||
2014 | 2013 | |||||||
Net income | $ | 123 | $ | 109 | ||||
Depletion, depreciation and amortization | 221 | 212 | ||||||
Exploration and abandonments | 31 | 18 | ||||||
Accretion of discount on asset retirement obligations | 3 | 3 | ||||||
Interest expense | 45 | 51 | ||||||
Income tax provision | 53 | 50 | ||||||
Gain on disposition of assets, net | (6 | ) | (24 | ) | ||||
(Income) loss from discontinued operations | 26 | (16 | ) | |||||
Derivative related activity | 86 | 96 | ||||||
Amortization of stock-based compensation | 22 | 17 | ||||||
Other noncash items | 8 | (4 | ) | |||||
EBITDAX (a) | 612 | 512 | ||||||
Cash interest expense | (41 | ) | (46 | ) | ||||
Current income tax provision | (12 | ) | (6 | ) | ||||
Discretionary cash flow (b) | 559 | 460 | ||||||
Discontinued operations cash activity | 70 | 51 | ||||||
Cash exploration expense | (24 | ) | (18 | ) | ||||
Changes in operating assets and liabilities | (139 | ) | (133 | ) | ||||
Net cash provided by operating activities | $ | 466 | $ | 360 | ||||
_______________
(a) | “EBITDAX” represents earnings before depletion, depreciation and amortization expense; exploration and abandonments; 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 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)
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 March 31, 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 | $ | 123 | $ | 0.85 | |||
Noncash MTM derivative losses | 55 | 0.38 | |||||
Income adjusted for noncash MTM derivative losses | 178 | 1.23 | |||||
Loss associated with discontinued operations (a) | 26 | 0.18 | |||||
Tax benefit inherited with Premier Silica acquisition (b) | (21 | ) | (0.15 | ) | |||
Adjusted income excluding noncash MTM derivative losses and unusual items | $ | 183 | $ | 1.26 | |||
_______________
(a) | Represents first quarter results of operations and fair value adjustments associated with the Alaska and Barnett divestitures. |
(b) | Tax benefit resulting from resolution during Q1 2014 of the tax uncertainty related to net operating loss carryovers and alternative minimum tax credits obtained from the 2012 Premier Silica acquisition. |
PIONEER NATURAL RESOURCES COMPANY
SUPPLEMENTAL INFORMATION
Open Commodity Derivative Positions as of May 5, 2014
(Volumes are average daily amounts)
2014 | Year Ending December 31, | |||||||||||||||||||
Second Quarter | 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 | 69,000 | 90,000 | 25,000 | |||||||||||||||
NYMEX price: | ||||||||||||||||||||
Ceiling | $ | 114.05 | $ | 114.05 | $ | 114.05 | $ | 99.04 | $ | 93.30 | ||||||||||
Floor | $ | 93.70 | $ | 93.70 | $ | 93.70 | $ | 88.17 | $ | 85.00 | ||||||||||
Short put | $ | 77.61 | $ | 77.61 | $ | 77.61 | $ | 73.44 | $ | 70.00 | ||||||||||
Swap contracts: | ||||||||||||||||||||
Volume | 10,000 | 10,000 | 10,000 | — | — | |||||||||||||||
NYMEX price | $ | 93.87 | $ | 93.87 | $ | 93.87 | $ | — | $ | — | ||||||||||
Rollfactor swap contracts: | ||||||||||||||||||||
Volume | 8,352 | 10,000 | 10,000 | 5,000 | — | |||||||||||||||
NYMEX roll price (b) | $ | 1.04 | $ | 1.10 | $ | 1.10 | $ | 0.60 | $ | — | ||||||||||
Average Daily NGL Production Associated with Derivatives (Bbl): | ||||||||||||||||||||
Collar contracts with short puts (c): | ||||||||||||||||||||
Volume | 2,165 | 3,500 | 3,500 | — | — | |||||||||||||||
Index price: | ||||||||||||||||||||
Ceiling | $ | 100.77 | $ | 97.93 | $ | 97.93 | $ | — | $ | — | ||||||||||
Floor | $ | 91.34 | $ | 90.14 | $ | 90.14 | $ | — | $ | — | ||||||||||
Short put | $ | 81.02 | $ | 81.36 | $ | 81.36 | $ | — | $ | — | ||||||||||
Collar contracts (d): | ||||||||||||||||||||
Volume | 3,000 | 3,000 | 3,000 | — | — | |||||||||||||||
Index price: | ||||||||||||||||||||
Ceiling | $ | 13.72 | $ | 13.72 | $ | 13.72 | $ | — | $ | — | ||||||||||
Floor | $ | 10.78 | $ | 10.78 | $ | 10.78 | $ | — | $ | — | ||||||||||
Swap contracts (e): | ||||||||||||||||||||
Volume | 3,000 | 3,000 | 1,674 | — | — | |||||||||||||||
Index price | $ | 48.20 | $ | 48.20 | $ | 47.95 | $ | — | $ | — | ||||||||||
Average Daily Gas Production Associated with Derivatives (MMBtu): | ||||||||||||||||||||
Collar contracts with short puts: | ||||||||||||||||||||
Volume | 115,000 | 115,000 | 115,000 | 285,000 | 20,000 | |||||||||||||||
NYMEX price: | ||||||||||||||||||||
Ceiling | $ | 4.70 | $ | 4.70 | $ | 4.70 | $ | 5.07 | $ | 5.36 | ||||||||||
Floor | $ | 4.00 | $ | 4.00 | $ | 4.00 | $ | 4.00 | $ | 4.00 | ||||||||||
Short put | $ | 3.00 | $ | 3.00 | $ | 3.00 | $ | 3.00 | $ | 3.00 | ||||||||||
Swap contracts: | ||||||||||||||||||||
Volume | 195,000 | 195,000 | 195,000 | 20,000 | — | |||||||||||||||
NYMEX price (f) | $ | 4.04 | $ | 4.04 | $ | 4.04 | $ | 4.31 | $ | — | ||||||||||
Basis swap contracts: | ||||||||||||||||||||
Permian Basin index swap volume (g) | 10,000 | 10,000 | 10,000 | 10,000 | — | |||||||||||||||
Price differential ($/MMBtu) | $ | (0.15 | ) | $ | (0.15 | ) | $ | (0.15 | ) | $ | (0.13 | ) | $ | — | ||||||
Mid-Continent index swap volume (g) | 100,000 | 120,000 | 120,000 | 40,000 | — | |||||||||||||||
Price differential ($/MMBtu) | $ | (0.23 | ) | $ | (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. As of March 31, 2014, the Company was a party to interest rate derivative contracts whereby the Company will receive 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 through July 15, 2022.
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 May 5, 2014, the Company had (i) marketing gas index swap contracts for 37,782 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 and (ii) marketing oil index swap contracts for 555 BBL per day for the remainder of 2014 with a price differential of $5.55 per BBL between Cushing WTI and Louisiana Light Sweet crude.
Derivative Losses, Net
(in millions)
The following table summarizes net derivative gains and losses that the Company has recorded in it earnings for the three months ended March 31, 2014:
Three Months Ended March 31, 2014 | ||||
Noncash changes in fair value: | ||||
Oil derivative losses | $ | (66 | ) | |
NGL derivative gains | 1 | |||
Gas derivative losses | (27 | ) | ||
Interest rate derivative gains | 6 | |||
Total noncash derivative losses, net | (86 | ) | ||
Net cash receipts (payments) on settled derivative instruments: | ||||
Oil derivative payments | (3 | ) | ||
Gas derivative payments | (19 | ) | ||
Interest rate derivative receipts | 4 | |||
Total cash derivative payments, net | (18 | ) | ||
Total derivative losses, net | $ | (104 | ) | |