EXHIBIT 99.1
News Release
Pioneer Natural Resources Company Reports Fourth Quarter 2016
Financial and Operating Results and Announces 2017 Capital Program
Dallas, Texas, February 7, 2017 - Pioneer Natural Resources Company (NYSE:PXD) (“Pioneer” or “the Company”) today reported financial and operating results for the quarter ended December 31, 2016, and announced the Company’s capital program for 2017.
Pioneer reported a fourth quarter net loss attributable to common stockholders of $44 million, or $0.26 per diluted share. Noncash mark-to-market derivative losses of $142 million after tax were offset by an income tax benefit attributable to tax credits for research and experimental expenditures related to horizontal drilling and completion innovations of $13 million, resulting in adjusted income (income adjusted for noncash mark-to-market derivative losses and unusual items) for the fourth quarter of $85 million after tax, or $0.49 per diluted share.
Fourth quarter, full-year 2016 and other recent highlights included:
• | producing 242 thousand barrels oil equivalent per day (MBOEPD), of which 59% was oil; quarterly production grew by 3 MBOEPD compared to the third quarter of 2016, and was at the top end of Pioneer’s fourth quarter production guidance range of 237 MBOEPD to 242 MBOEPD; the seventh consecutive quarter of production growth since the oil price collapse in late 2014; |
• | producing 234 MBOEPD in 2016, an increase of 30 MBOEPD, or 15%, from 2015; oil production increased by 28 thousand barrels of oil per day (MBPD), or 27%, from 2015; oil production was 57% of Pioneer’s total 2016 production compared to 52% in 2015; |
• | fourth quarter and full-year 2016 production growth was driven by the Company’s Spraberry/Wolfcamp horizontal drilling program; total Spraberry/Wolfcamp production increased 36% year-over-year, with oil output increasing 42%; |
• | reducing production costs per barrel oil equivalent (BOE) by 29% in 2016 compared to 2015; decrease driven by cost reduction initiatives and growth of low-cost Spraberry/Wolfcamp horizontal production; |
• | delivering 232% drillbit reserve replacement in 2016 by adding proved reserves of 205 million barrels oil equivalent (MMBOE) from discoveries, extensions and technical revisions of previous estimates at a drillbit finding and development cost of $9.59 per BOE (excludes negative price revisions of 58 MMBOE and net proved reserves added from acquisitions and divestitures of 3 MMBOE); the Company’s proved developed finding and development cost was $9.11 per BOE, reflecting the addition of proved developed reserves totaling 213 MMBOE from (i) discoveries and extensions placed on production during 2016, (ii) transfers from proved undeveloped reserves at year-end 2015 and (iii) technical revisions of previous estimates for proved developed reserves during 2016 (excludes negative price revisions); |
• | protecting 2016 cash flow and margins through attractive oil and gas derivative positions that provided incremental cash receipts of $680 million; |
• | maintaining a strong balance sheet with cash on hand at year end of $3 billion (includes liquid investments); net debt to 2016 operating cash flow at year end was 0.2 times and net debt to book capitalization was 2%; |
• | increasing the northern Spraberry/Wolfcamp horizontal rig count from 12 rigs to 17 rigs during the fourth quarter, as expected; |
• | placing 66 horizontal wells on production in the Spraberry/Wolfcamp during the fourth quarter, as expected, with continuing strong performance; 38 wells benefited from Pioneer’s Version 3.0 completion optimization design; Version 3.0 wells are continuing to outperform earlier wells that utilized the Version 2.0 completion optimization design; |
• | 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; |
• | signing an agreement with the City of Midland to upgrade the City’s wastewater treatment plant in return for a dedicated long-term supply of water from the plant; and |
• | exporting 525,000 barrels of Permian oil during the fourth quarter; expect to export two 525,000-barrel Permian oil cargoes to Asia during the first quarter. |
Pioneer’s 2017 Plan and Capital Program is summarized below:
• | planning to operate 18 horizontal rigs in the Spraberry/Wolfcamp during 2017; of these, 14 rigs will be in the northern area (13 rigs currently operating with an additional rig to be added in March) and four rigs will be focused in the northern portion of the southern Wolfcamp joint venture area (Pioneer has a 60% working interest in the joint venture); completions in both areas will be predominantly Version 3.0, with some wells testing larger completions during the year; |
• | planning to complete 20 wells in the Eagle Ford Shale, which includes nine drilled but uncompleted wells and 11 new drills (Pioneer has a 46% working interest); the objective of the limited new well program is to test longer laterals and higher-intensity completions; |
• | transferring West Panhandle gas processing operations from the Company’s Fain plant to a third-party facility in March; |
• | forecasting production growth in 2017 ranging from 15% to 18% compared to 2016 (approximately 62% oil content compared to 57% oil content in 2016); Spraberry/Wolfcamp production growth is expected to be the primary contributor, with growth ranging from 30% to 34% in 2017 compared to 2016 (oil growth expected to increase by 33% to 37%); |
• | expecting internal rates of return for the 2017 drilling program, including tank battery and saltwater disposal facility investments, ranging from 50% to 100% assuming an oil price of $55.00 per barrel and a gas price of $3.00 per thousand cubic feet (MCF); |
• | planning capital expenditures for 2017 of $2.8 billion, which includes $2.5 billion for drilling and completion activities and $275 million for water infrastructure, vertical integration and field facilities; this capital program assumes that further efficiency gains will offset the Company’s estimated cost inflation of 5%; Pioneer’s vertical integration operations mitigate the impact of the 10% to 15% cost inflation forecasted for the industry in 2017; the 2017 drilling and completion capital of $2.5 billion is $0.6 billion higher than 2016, reflecting (i) the higher Spraberry/Wolfcamp rig count for 2017, (ii) a reduced southern Wolfcamp joint venture drilling carry benefit in 2017, (iii) an increased number of higher-cost Version 3.0 completions in the 2017 Spraberry/Wolfcamp drilling program, (iv) additional tank batteries, saltwater disposal facilities and gas processing facilities related to the increased 2017 drilling activity in the Spraberry/Wolfcamp and (v) additional drilling activity in the Eagle Ford Shale in 2017; |
• | funding the 2017 capital program from forecasted cash flow of $2.2 billion and cash on hand; |
• | maintaining derivative positions that cover approximately 85% of forecasted 2017 oil production and 55% of forecasted 2017 gas production; |
• | forecasting net debt to 2017 operating cash flow to remain below 1.0 times; and |
• | high-grading Pioneer’s Permian acreage position by (i) agreeing in January to sell approximately 5,600 net acres in Upton and Andrews counties for $63 million (before normal closing adjustments) and (ii) evaluating offers to sell approximately 20,500 net acres in Martin County; also opening a data room to sell approximately 10,500 net acres in the Eagle Ford Shale. |
President and CEO Timothy L. Dove stated, “Despite experiencing another year of downward pressure on oil prices, the Company’s focus on execution, improving capital efficiency and maintaining a strong balance
sheet allowed us to meet or exceed all of the Company’s financial and operating goals for 2016 and deliver one of the best years in the Company’s 20-year history. The key drivers of this strong performance were the continued success of Pioneer’s horizontal drilling program in the Spraberry/Wolfcamp and the outstanding efforts of our employees. As we enter 2017, we are well positioned to drill high-return wells, grow production and bring forward the inherent net asset value associated with this world-class asset.”
“I am excited about Pioneer’s vision to grow production from 234 MBOEPD in 2016 to approximately 1 million barrels oil equivalent per day in 2026. We expect to achieve this vision by continuing to drill high-return wells that will deliver organic compound annual production growth of 15%+ and compound annual cash flow growth of approximately 20% over this 10-year period. This assumes an oil price of $55.00 per barrel and a gas price of $3.00 per MCF. In addition, we expect to maintain our net debt to operating cash flow ratio below 1.0 times and improve corporate returns. We also expect to spend within cash flow beginning in 2018 and generate free cash flow thereafter.”
Spraberry/Wolfcamp Operations Update and Outlook
Pioneer is the largest acreage holder in the Spraberry/Wolfcamp, with approximately 600,000 gross acres in the northern portion of the play and approximately 200,000 gross acres in the southern Wolfcamp joint venture area. Pioneer’s contiguous acreage position and substantial resource potential allow for decades of drilling horizontal wells with lateral lengths ranging from 7,500 feet to 14,000 feet.
The Company implemented a completion optimization program during 2015 in the Spraberry/Wolfcamp that combines longer laterals with optimized stage length, clusters per stage, fluid volumes and proppant concentrations. The objective of the program is to improve well productivity by allowing more rock to be contacted closer to the horizontal wellbore. In 2013 and 2014, the Company’s initial fracture stimulation design (Version 1.0) consisted of proppant concentrations of 1,000 pounds per foot, fluid concentrations of 30 barrels per foot, cluster spacing of 60 feet and stage spacing of 240 feet. Beginning in mid-2015, the Company enhanced its fracture stimulation design (Version 2.0), which consisted of larger proppant concentrations of 1,400 pounds per foot, larger fluid concentrations of 36 barrels per foot, tighter cluster spacing of 30 feet and shorter stage spacing of 150 feet. The Version 2.0 design increased the cost of a completion by approximately $500 thousand per well. Beginning in the first quarter of 2016, Pioneer commenced testing further-enhanced completion designs (Version 3.0), which included larger proppant concentrations up to 1,700 pounds per foot, larger fluid concentrations up to 50 barrels per foot, tighter cluster spacing down to 15 feet and shorter stage spacing down to 100 feet. The cost of this design added $500 thousand to $1 million per well compared to Version 2.0.
The Company placed 66 horizontal wells on production in the Spraberry/Wolfcamp during the fourth quarter of 2016, as expected. Of the 66 wells, 38 wells utilized the Version 3.0 completion design. Pioneer has now placed a total of 109 Version 3.0 wells on production since early 2016 (64 Wolfcamp B wells and 45 Wolfcamp A wells) compared to 151 wells that have been placed on production since mid-2015 utilizing the less-intense Version 2.0 completion design (131 Wolfcamp B wells and 20 Wolfcamp A wells). Production from the Version 3.0 completion optimization wells is continuing to outperform the Version 2.0 wells. The incremental capital cost to complete the Version 3.0 wells of $500 thousand to $1 million per well is paying out in less than one year at current prices.
The drilling and completion cost per perforated lateral foot for all horizontal wells placed on production (includes completion-optimized wells and non-optimized wells) in the Spraberry/Wolfcamp area averaged $817 per foot in the fourth quarter of 2016, a decrease of 25% from the first quarter of 2015. This decrease reflects the Company’s cost reduction initiatives and efficiency gains, and includes the use of more expensive Version 2.0 and Version 3.0 completion designs over the past 18 months (incremental $500 thousand per well and incremental $1.0 million to $1.5 million per well, respectively, compared to Version 1.0 completions). During the fourth quarter, Pioneer’s horizontal drilling and completion costs averaged $8.5 million for Wolfcamp B interval wells, $6.4 million for Wolfcamp A interval wells and $6.4 million for
Lower Spraberry Shale interval wells. These wells had average perforated lateral lengths ranging from 8,200 feet to 9,500 feet.
Pioneer expects to place approximately 260 gross horizontal wells on production in the Spraberry/Wolfcamp during 2017. Of these wells, approximately 220 gross wells will be in the northern area and 40 gross wells will be in the southern Wolfcamp joint venture area (results in 244 net wells after recognizing Pioneer’s 60% interest in the wells in the southern Wolfcamp joint venture area). Approximately 55% of the wells will be in the Wolfcamp B, 30% in the Wolfcamp A and 15% in the Lower Spraberry Shale. The Company also plans a limited appraisal program for the Clearfork, Jo Mill and Wolfcamp D intervals during 2017.
As a result of the strong performance of Version 3.0 completions compared to Version 2.0 completions, the 2017 drilling program in the Spraberry/Wolfcamp will utilize predominantly Version 3.0 completions. The Company expects estimated ultimate recoveries (EURs) for the wells planned in the 2017 program to average 1.5 MMBOE for Wolfcamp B wells, 1.2 MMBOE for Wolfcamp A wells and 1.0 MMBOE for Lower Spraberry Shale wells. The expected costs to drill and complete these wells are: Wolfcamp B - $8.5 million for a 10,000-foot lateral well; Wolfcamp A - $7.5 million for a 9,500-foot lateral well; and Lower Spraberry Shale - $7.2 million for a 9,500-foot lateral well. Production costs for Pioneer’s horizontal Spraberry/Wolfcamp wells are expected to range from $4.00 per BOE to $5.00 per BOE (includes production and ad valorem taxes).
The drilling program in the Spraberry/Wolfcamp is expected to deliver internal rates of return (IRRs) ranging from 50% to 100%, assuming an oil price of $55.00 per barrel and a gas price of $3.00 per MCF. These returns, which include tank battery and saltwater disposal facility costs, are benefiting from ongoing cost reduction initiatives, drilling and completion efficiency gains and well productivity improvements.
The Company’s Spraberry/Wolfcamp horizontal drilling program continues to drive production growth, with total Spraberry/Wolfcamp production growing by 8 MBOEPD, or 5%, in the fourth quarter of 2016 compared to the third quarter of 2016. Oil production grew 8% in the fourth quarter and represented 69% of fourth quarter Spraberry/Wolfcamp production on a BOE basis. The Company continued to reject ethane during the fourth quarter due to weak market conditions, which negatively impacted production by approximately 4 MBOEPD.
For the fourth quarter of 2016, Pioneer placed 66 horizontal wells on production, up from the 46 wells placed on production in the third quarter. Sixty-four wells were in the northern area and two wells were in the southern Wolfcamp joint venture area. For the full year, 195 wells were placed on production in the northern area and 41 wells were placed on production in the southern Wolfcamp joint venture area.
Pioneer’s forecasted 2017 production growth rate for the Spraberry/Wolfcamp ranges from 30% to 34%, with oil production increasing 33% to 37%. This reflects the Company placing approximately 260 gross wells (244 net wells) on production in 2017. In the first quarter, the Company expects to place approximately 45 wells on production, which is weighted to the second half of the quarter, compared to 66 wells in the fourth quarter that were evenly distributed over the quarter. The Company assumes that it will continue to reject ethane throughout 2017 based on continuing weak market conditions.
Spraberry/Wolfcamp Vertical Integration and Gas Processing
Pioneer is focused on optimizing the development of the Spraberry/Wolfcamp, which includes ensuring that certain infrastructure and services are available. These include the build-out of a field-wide water distribution system, optimization of the Company’s sand mine in Brady, Texas, construction of additional field and gas processing facilities, and maintaining the Company’s pressure pumping equipment.
The Company is constructing a field-wide water distribution system to reduce the cost of water for drilling and completion activities and to ensure that adequate supplies of non-potable water are available for use in
the development of the Spraberry/Wolfcamp field. The 2017 capital program includes $160 million for expansion of the mainline system, subsystems and frac ponds to efficiently deliver water to Pioneer’s drilling locations. The Company recently signed an agreement with the City of Midland to upgrade the City’s wastewater treatment plant in return for a dedicated long-term supply of water from the plant. The 2017 program includes $10 million of engineering capital to begin work on this upgrade. Pioneer expects to spend approximately $110 million over the 2017 through 2019 period for the Midland plant upgrade. In return, the Company will receive two billion barrels of low-cost, non-potable water over a 28-year contract period (up to 240 MBPD) to support its completion operations.
Pioneer’s sand mine in Brady, Texas, which is strategically located within close proximity (~190 miles) of the Spraberry/Wolfcamp field, provides a low-cost sand source for the Company’s horizontal drilling program. The 2017 capital program includes $30 million to complete an optimization project for the Company’s existing sand mining facilities. This project will improve yields and reduce the Company’s overall cost of supply. The 2017 capital program also includes $45 million for upgrades and maintenance to the six pressure pumping fleets that the Company plans to operate during 2017.
Pioneer owns a 27% interest in Targa Resources’ West Texas gas processing system and a 30% interest in WTG’s Sale Ranch gas processing system. These investments (i) improve Pioneer’s contract terms for field gas processing, (ii) ensure the timely connection of Pioneer’s new horizontal wells and (iii) provide the Company with opportunities to benefit from third-party processing revenues. During 2017, the Company expects to spend $70 million for system compression and new connections and $45 million for new gas processing capacity additions.
Eagle Ford Shale Operations
In the liquids-rich area of the Eagle Ford Shale play in South Texas, Pioneer is planning a limited horizontal drilling program in 2017 that will be focused in Karnes, DeWitt and Live Oak counties. The program, which is expected to begin in the second quarter, includes completing nine wells that were drilled in late 2015/early 2016 and drilling and completing 11 new wells.
The objective of this drilling program is to test longer laterals with higher-intensity completions in the new wells. Lateral lengths will be extended to 7,500 feet from the previous design of 5,200 feet, with cluster spacing reduced from 50 feet to 30 feet. Proppant concentrations will be increased from 1,200 pounds per foot to 2,000 pounds per foot. The cost of drilling and completing the new wells is expected to be $8.5 million per well. The Company expects EURs averaging 1.3 MMBOE for the new wells with IRRs ranging from 40% to 50%, assuming an oil price of $55.00 per barrel and a gas price of $3.00 per MCF.
Pioneer’s production from the Eagle Ford Shale averaged 27 MBOEPD in the fourth quarter, of which 33% was condensate, 33% was NGLs and 34% was gas. The 2017 drilling program is expected to moderate the production decline Pioneer has experienced in the field since it stopped drilling there in early 2016. While the year-over-year decline is still forecasted to be approximately 40%, the decline from the fourth quarter of 2016 to the fourth quarter of 2017 is expected to be shallower at 20% since the production from the 2017 program is heavily weighted to the second half of the year.
Pioneer’s acreage position in the Eagle Ford Shale is approximately 59,000 net acres, all of which is held by production. This excludes the 10,500 net acres that are currently being marketed for divestiture.
West Panhandle Operations
Production in the West Panhandle field during the fourth quarter of 7 MBOEPD was lower than planned as a result of continuing mechanical problems at Pioneer’s Fain gas processing plant. The Company will be transferring its West Panhandle gas processing operations to a third-party facility beginning in March. Due to the ongoing operational uncertainty at the Fain plant, the Company is estimating first quarter 2017
production of approximately 7 MBOEPD, which is consistent with actual results over the past six months when the plant was experiencing similar mechanical problems.
2017 Capital Program
The Company’s capital budget for 2017 is $2.8 billion (excluding acquisitions, asset retirement obligations, capitalized interest and geological and geophysical G&A and IT system upgrades), in line with the Company’s preliminary forecast of $2.7 billion to $2.8 billion. The budget includes $2.5 billion for drilling and completion activities, including tank batteries/saltwater disposal facilities and gas processing facilities, and $275 million for water infrastructure, vertical integration and field facilities.
The following provides a breakdown of the drilling capital budget by asset:
• | Spraberry/Wolfcamp - $2.4 billion (includes $1.9 billion for the horizontal drilling program, $265 million for tank batteries/saltwater disposal facilities, $115 million for gas processing facilities and $110 million for land, science and other expenditures); |
• | Eagle Ford Shale - $95 million (includes $65 million for the horizontal drilling program and $30 million for compression, land and other expenditures); and |
• | Other assets - $20 million. |
The 2017 drilling and completion capital of $2.5 billion is $0.6 billion higher than 2016 reflecting:
• | the higher Spraberry/Wolfcamp rig count for 2017 ($224 million); |
• | a reduced Spraberry/Wolfcamp joint venture drilling carry benefit in 2017 ($137 million); |
• | additional tank batteries and saltwater disposal facilities related to the increased 2017 drilling activity in the Spraberry/Wolfcamp ($95 million); |
• | additional gas processing compression, hookups and new gas processing capacity additions required in the Spraberry/Wolfcamp to support the increased drilling activity ($70 million); |
• | an increase in the number of higher-cost Version 3.0 completions in the 2017 Spraberry/Wolfcamp drilling program ($65 million); and |
• | additional drilling activity in the Eagle Ford Shale in 2017 ($35 million). |
The 2017 capital budget is expected to be funded from forecasted operating cash flow of $2.2 billion (assuming average 2017 estimated prices of $55.00 per barrel for oil and $3.00 per MCF for gas) and cash on hand (including liquid investments). Net debt to 2017 operating cash flow is forecasted to remain below 1.0 times.
Fourth Quarter 2016 Financial Review
Sales volumes for the fourth quarter of 2016 averaged 242 MBOEPD. Oil sales averaged 143 MBPD, NGL sales averaged 44 MBPD and gas sales averaged 328 million cubic feet per day.
The average realized price for oil was $46.13 per barrel. The average realized price for NGLs was $16.76 per barrel, and the average realized price for gas was $2.59 per MCF. These prices exclude the effects of derivatives.
Production costs averaged $8.20 per BOE. Depreciation, depletion and amortization (DD&A) expense averaged $16.04 per BOE, benefiting from fourth quarter reserve additions associated with (i) successful drilling activities and (ii) production cost reduction initiatives, which had the effect of adding proved reserves by lengthening the economic lives of the Company’s producing wells. Exploration and abandonment costs were $23 million, including $1 million of acreage abandonments, $3 million of seismic purchases and $19 million of personnel costs. General and administrative expense totaled $89 million and included $8 million of incremental charges associated with performance-based compensation. Interest expense was $46 million. Other expense was $65 million, including (i) $33 million of charges associated with excess firm gathering and transportation commitments, (ii) $8 million of losses (principally noncash) associated with the
portion of vertical integration services provided to nonaffiliated working interest owners, including joint venture partners, in wells operated by the Company and (iii) $7 million of stacked drilling rig charges.
The Company recognized an income tax benefit of $13 million during the fourth quarter associated with tax credits for research and experimental expenditures related to ongoing drilling and completion innovations on horizontal wells.
First Quarter 2017 Financial Outlook
The Company’s first quarter 2017 outlook for certain operating and financial items is provided below.
Production is forecasted to average 243 MBOEPD to 248 MBOEPD.
Production costs are expected to average $7.75 per BOE to $9.75 per BOE. DD&A expense is expected to average $15.50 per BOE to $17.50 per BOE. Total exploration and abandonment expense is forecasted to be $20 million to $30 million.
General and administrative expense is expected to be $80 million to $85 million. Interest expense is expected to be $45 million to $50 million. Other expense is forecasted to be $60 million to $70 million and is expected to include (i) $35 million to $40 million of charges associated with excess firm gathering and transportation commitments and (ii) $10 million to $15 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. Accretion of discount on asset retirement obligations is expected to be $4 million to $7 million.
The Company’s effective income tax rate is expected to range from 35% to 40%. Current income taxes are expected to be less than $5 million.
The Company’s financial and derivative mark-to-market results and open derivatives positions are outlined on the attached schedules.
Earnings Conference Call
On Wednesday, February 8, 2017, at 9:00 a.m. Central Time, Pioneer will discuss its financial and operating results for the quarter ended December 31, 2016, and its 2017 capital program, 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 (800) 946-0783 and confirmation code 6806703 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 March 5, 2017. Click here to register for the call-in audio replay, and enter confirmation code 6806703.
Pioneer is a large independent oil and gas exploration and production company, headquartered in Dallas, Texas, with operations in the United States. For more information, visit www.pxd.com.
Except for historical information contained herein, the statements in this news release are forward-looking statements that are made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause Pioneer's actual results in future periods to differ materially from the forward-looking statements.
These risks and uncertainties include, among other things, volatility of commodity prices, product supply and demand, competition, the ability to obtain environmental and other permits and the timing thereof, other government regulation or action, the ability to obtain approvals from third parties and negotiate agreements with third parties on mutually acceptable terms, completion of planned 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, investment instruments, derivative contracts and the purchasers of Pioneer’s oil, NGL and gas production, uncertainties about estimates of reserves and resource potential, identification of drilling locations and the ability to add proved reserves in the future, the assumptions underlying production forecasts, quality of technical data, environmental and weather risks, including the possible impacts of climate change, the risks associated with the ownership and operation of the Company’s industrial sand mining and oilfield services businesses, and acts of war or terrorism. These and other risks are described in Pioneer's 10-K and 10-Q Reports and other filings with the U.S. Securities and Exchange Commission (SEC). In addition, Pioneer may be subject to currently unforeseen risks that may have a materially adverse impact on it. Pioneer undertakes no duty to publicly update these statements except as required by law.
An audit of proved reserves follows the general principles set forth in the standards pertaining to the estimating and auditing of oil and gas reserve information promulgated by the Society of Petroleum Engineers ("SPE"). A reserve audit as defined by the SPE is not the same as a financial audit. Please see the Company's Annual Report on Form 10-K for a general description of the concepts included in the SPE's definition of a reserve audit.
"Drillbit finding and development cost per BOE," or “drillbit F&D cost per BOE,” means the summation of exploration and development costs incurred divided by the summation of annual proved reserves, on a BOE basis, attributable to discoveries and extensions (excludes purchases of minerals-in-place) and revisions of previous estimates. Revisions of previous estimates exclude price revisions. Consistent with industry practice, future capital costs to develop proved undeveloped reserves are not included in costs incurred.
“Drillbit reserve replacement” is the summation of annual proved reserves, on a BOE basis, attributable to discoveries and extensions (excludes purchases of minerals-in-place) and revisions of previous estimates divided by annual production of oil, NGLs and gas, on a BOE basis. Revisions of previous estimates exclude price revisions.
“Proved developed finding and development cost per BOE,” or “proved developed F&D cost per BOE,” means the summation of exploration and development costs incurred (excluding asset retirements obligations) divided by the summation of annual proved reserves, on a BOE basis, attributable to proved developed reserve additions, including (i) discoveries and extensions placed on production during 2016, (ii) transfers from proved undeveloped reserves at year-end 2015 and (iii) technical revisions of previous estimates for proved developed reserves during 2016. Revisions of previous estimates exclude price revisions.
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)
December 31, 2016 | December 31, 2015 | |||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 1,118 | $ | 1,391 | ||||
Short-term investments | 1,441 | — | ||||||
Accounts receivable, net | 518 | 385 | ||||||
Income taxes receivable | 3 | 43 | ||||||
Inventories | 181 | 155 | ||||||
Notes receivable | — | 498 | ||||||
Derivatives | 14 | 694 | ||||||
Other | 23 | 28 | ||||||
Total current assets | 3,298 | 3,194 | ||||||
Property, plant and equipment, at cost: | ||||||||
Oil and gas properties, using the successful efforts method of accounting | 19,052 | 16,800 | ||||||
Accumulated depletion, depreciation and amortization | (8,211 | ) | (6,778 | ) | ||||
Total property, plant and equipment | 10,841 | 10,022 | ||||||
Long-term investments | 420 | — | ||||||
Goodwill | 272 | 272 | ||||||
Other property and equipment, net | 1,529 | 1,523 | ||||||
Derivatives | — | 64 | ||||||
Other assets, net | 99 | 79 | ||||||
$ | 16,459 | $ | 15,154 | |||||
LIABILITIES AND EQUITY | ||||||||
Current liabilities: | ||||||||
Accounts payable | $ | 875 | $ | 883 | ||||
Interest payable | 68 | 65 | ||||||
Income taxes payable | — | 2 | ||||||
Current portion of long-term debt | 485 | 448 | ||||||
Derivatives | 77 | — | ||||||
Other | 61 | 64 | ||||||
Total current liabilities | 1,566 | 1,462 | ||||||
Long-term debt | 2,728 | 3,207 | ||||||
Derivatives | 7 | 1 | ||||||
Deferred income taxes | 1,397 | 1,776 | ||||||
Other liabilities | 350 | 333 | ||||||
Equity | 10,411 | 8,375 | ||||||
$ | 16,459 | $ | 15,154 | |||||
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per share data)
Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
Revenues and other income: | ||||||||||||||||
Oil and gas | $ | 753 | $ | 508 | $ | 2,418 | $ | 2,178 | ||||||||
Sales of purchased oil and gas | 470 | 299 | 1,533 | 964 | ||||||||||||
Interest and other | 12 | 5 | 32 | 22 | ||||||||||||
Derivative gains (losses), net | (66 | ) | 262 | (161 | ) | 879 | ||||||||||
Gain (loss) on disposition of assets, net | (1 | ) | — | 2 | 782 | |||||||||||
1,168 | 1,074 | 3,824 | 4,825 | |||||||||||||
Costs and expenses: | ||||||||||||||||
Oil and gas production | 143 | 185 | 581 | 717 | ||||||||||||
Production and ad valorem taxes | 40 | 33 | 136 | 145 | ||||||||||||
Depletion, depreciation and amortization | 357 | 382 | 1,480 | 1,385 | ||||||||||||
Purchased oil and gas | 485 | 319 | 1,597 | 1,003 | ||||||||||||
Impairment of oil and gas properties | — | 846 | 32 | 1,056 | ||||||||||||
Exploration and abandonments | 23 | 21 | 119 | 99 | ||||||||||||
General and administrative | 89 | 81 | 325 | 327 | ||||||||||||
Accretion of discount on asset retirement obligations | 5 | 3 | 18 | 12 | ||||||||||||
Interest | 46 | 48 | 207 | 187 | ||||||||||||
Other | 65 | 129 | 288 | 315 | ||||||||||||
1,253 | 2,047 | 4,783 | 5,246 | |||||||||||||
Loss from continuing operations before income taxes | (85 | ) | (973 | ) | (959 | ) | (421 | ) | ||||||||
Income tax benefit | 41 | 351 | 403 | 155 | ||||||||||||
Loss from continuing operations | (44 | ) | (622 | ) | (556 | ) | (266 | ) | ||||||||
Loss from discontinued operations, net of tax | — | (1 | ) | — | (7 | ) | ||||||||||
Net loss attributable to common stockholders | $ | (44 | ) | $ | (623 | ) | $ | (556 | ) | $ | (273 | ) | ||||
Basic earnings per share attributable to common stockholders: | ||||||||||||||||
Loss from continuing operations | $ | (0.26 | ) | $ | (4.17 | ) | $ | (3.34 | ) | $ | (1.79 | ) | ||||
Loss from discontinued operations | — | — | — | (0.04 | ) | |||||||||||
Net loss | $ | (0.26 | ) | $ | (4.17 | ) | $ | (3.34 | ) | $ | (1.83 | ) | ||||
Diluted earnings per share attributable to common stockholders: | ||||||||||||||||
Loss from continuing operations | $ | (0.26 | ) | $ | (4.17 | ) | $ | (3.34 | ) | $ | (1.79 | ) | ||||
Loss from discontinued operations | — | — | — | (0.04 | ) | |||||||||||
Net loss | $ | (0.26 | ) | $ | (4.17 | ) | $ | (3.34 | ) | $ | (1.83 | ) | ||||
Weighted average shares outstanding: | ||||||||||||||||
Basic | 170 | 149 | 166 | 149 | ||||||||||||
Diluted | 170 | 149 | 166 | 149 | ||||||||||||
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
Cash flows from operating activities: | ||||||||||||||||
Net loss | $ | (44 | ) | $ | (623 | ) | $ | (556 | ) | $ | (273 | ) | ||||
Adjustments to reconcile net loss to net cash provided by operating activities: | ||||||||||||||||
Depletion, depreciation and amortization | 357 | 382 | 1,480 | 1,385 | ||||||||||||
Impairment of oil and gas properties | — | 846 | 32 | 1,056 | ||||||||||||
Impairment of inventory and other property and equipment | 2 | 64 | 8 | 86 | ||||||||||||
Exploration expenses, including dry holes | 1 | 6 | 42 | 28 | ||||||||||||
Deferred income taxes | (39 | ) | (325 | ) | (379 | ) | (178 | ) | ||||||||
(Gain) loss on disposition of assets, net | 1 | — | (2 | ) | (782 | ) | ||||||||||
Accretion of discount on asset retirement obligations | 5 | 3 | 18 | 12 | ||||||||||||
Discontinued operations | — | — | — | (4 | ) | |||||||||||
Interest expense | 1 | 4 | 13 | 18 | ||||||||||||
Derivative related activity | 222 | 20 | 851 | (3 | ) | |||||||||||
Amortization of stock-based compensation | 23 | 21 | 89 | 90 | ||||||||||||
Other noncash items | 17 | 25 | 65 | 38 | ||||||||||||
Change in operating assets and liabilities: | ||||||||||||||||
Accounts receivable, net | (70 | ) | 29 | (134 | ) | 54 | ||||||||||
Income taxes receivable | 23 | (43 | ) | 40 | (20 | ) | ||||||||||
Inventories | (25 | ) | 37 | (32 | ) | 8 | ||||||||||
Derivatives | — | — | (23 | ) | — | |||||||||||
Investments | (22 | ) | — | (22 | ) | — | ||||||||||
Other current assets | (4 | ) | 9 | (7 | ) | — | ||||||||||
Accounts payable | 66 | 8 | 58 | (258 | ) | |||||||||||
Interest payable | 29 | 29 | 3 | 25 | ||||||||||||
Income taxes payable | — | (24 | ) | (2 | ) | 1 | ||||||||||
Other current liabilities | (6 | ) | (7 | ) | (44 | ) | (35 | ) | ||||||||
Net cash provided by operating activities | 537 | 461 | 1,498 | 1,248 | ||||||||||||
Net cash used in investing activities | (305 | ) | (633 | ) | (3,820 | ) | (1,840 | ) | ||||||||
Net cash provided by (used in) financing activities | (5 | ) | 982 | 2,049 | 958 | |||||||||||
Net increase (decrease) in cash and cash equivalents | 227 | 810 | (273 | ) | 366 | |||||||||||
Cash and cash equivalents, beginning of period | 891 | 581 | 1,391 | 1,025 | ||||||||||||
Cash and cash equivalents, end of period | $ | 1,118 | $ | 1,391 | $ | 1,118 | $ | 1,391 | ||||||||
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUMMARY PRODUCTION AND PRICE DATA
Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
Average Daily Sales Volumes: | ||||||||||||||||
Oil (Bbls) | 142,834 | 112,965 | 133,677 | 105,347 | ||||||||||||
Natural gas liquids ("NGL") (Bbls) | 44,255 | 40,639 | 43,504 | 38,592 | ||||||||||||
Gas (Mcf) | 328,465 | 366,799 | 339,966 | 360,662 | ||||||||||||
Total (BOE) | 241,833 | 214,738 | 233,842 | 204,050 | ||||||||||||
Average Prices: | ||||||||||||||||
Oil (per Bbl) | $ | 46.13 | $ | 37.92 | $ | 39.65 | $ | 43.55 | ||||||||
NGL (per Bbl) | $ | 16.76 | $ | 12.16 | $ | 13.49 | $ | 13.31 | ||||||||
Gas (per Mcf) | $ | 2.59 | $ | 2.03 | $ | 2.11 | $ | 2.40 | ||||||||
Total (BOE) | $ | 33.84 | $ | 25.72 | $ | 28.25 | $ | 29.25 | ||||||||
Three Months Ended December 31, 2016 | ||||||||||||||||||||
Permian Horizontals | Permian Verticals | Eagle Ford | Other Assets | Total | ||||||||||||||||
($ per BOE) | ||||||||||||||||||||
Margin Data: | ||||||||||||||||||||
Average prices | $ | 37.70 | $ | 35.01 | $ | 26.31 | $ | 19.44 | $ | 33.84 | ||||||||||
Production costs | (1.96 | ) | (14.01 | ) | (10.88 | ) | (11.41 | ) | (6.42 | ) | ||||||||||
Production and ad valorem taxes | (2.31 | ) | (1.53 | ) | (0.34 | ) | (0.94 | ) | (1.78 | ) | ||||||||||
$ | 33.43 | $ | 19.47 | $ | 15.09 | $ | 7.09 | $ | 25.64 | |||||||||||
% Oil | 71 | % | 64 | % | 33 | % | 13 | % | 59 | % | ||||||||||
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. During periods in which the Company realizes net income attributable to common stockholders, 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-based basic earnings (iii) divided by weighted average basic shares outstanding and 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, if any, (iii) divided by weighted average diluted shares outstanding. During periods in which the Company realizes a loss 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 loss attributable to common stockholders to basic and diluted net loss attributable to common stockholders for the three and twelve months ended December 31, 2016 and 2015:
Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
(in millions) | ||||||||||||||||
Net loss attributable to common stockholders | $ | (44 | ) | $ | (623 | ) | $ | (556 | ) | $ | (273 | ) | ||||
Participating basic earnings | — | — | — | — | ||||||||||||
Basic and diluted net loss attributable to common stockholders | $ | (44 | ) | $ | (623 | ) | $ | (556 | ) | $ | (273 | ) | ||||
Basic and diluted weighted average common shares outstanding were 170 million and 166 million for the three and twelve months ended December 31, 2016, respectively. Basic and diluted weighted average common shares outstanding were 149 million for both the three and twelve months ended December 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 December 31, | Twelve Months Ended December 31, | |||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
Net loss | $ | (44 | ) | $ | (623 | ) | $ | (556 | ) | $ | (273 | ) | ||||
Depletion, depreciation and amortization | 357 | 382 | 1,480 | 1,385 | ||||||||||||
Exploration and abandonments | 23 | 21 | 119 | 99 | ||||||||||||
Impairment of oil and gas properties | — | 846 | 32 | 1,056 | ||||||||||||
Impairment of inventory and other property equipment | 2 | 64 | 8 | 86 | ||||||||||||
Accretion of discount on asset retirement obligations | 5 | 3 | 18 | 12 | ||||||||||||
Interest expense | 46 | 48 | 207 | 187 | ||||||||||||
Income tax benefit | (41 | ) | (351 | ) | (403 | ) | (155 | ) | ||||||||
(Gain) loss on disposition of assets, net | 1 | — | (2 | ) | (782 | ) | ||||||||||
Loss from discontinued operations, net of tax | — | 1 | — | 7 | ||||||||||||
Derivative related activity | 222 | 20 | 851 | (3 | ) | |||||||||||
Amortization of stock-based compensation | 23 | 21 | 89 | 90 | ||||||||||||
Other | 17 | 25 | 65 | 38 | ||||||||||||
EBITDAX (a) | 611 | 457 | 1,908 | 1,747 | ||||||||||||
Cash interest expense | (45 | ) | (44 | ) | (194 | ) | (169 | ) | ||||||||
Current income tax benefit (provision) | 2 | 26 | 24 | (23 | ) | |||||||||||
Discretionary cash flow (b) | 568 | 439 | 1,738 | 1,555 | ||||||||||||
Discontinued operations cash activity | — | (1 | ) | — | (11 | ) | ||||||||||
Cash exploration expense | (22 | ) | (15 | ) | (77 | ) | (71 | ) | ||||||||
Changes in operating assets and liabilities | (9 | ) | 38 | (163 | ) | (225 | ) | |||||||||
Net cash provided by operating activities | $ | 537 | $ | 461 | $ | 1,498 | $ | 1,248 | ||||||||
_______________
(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) loss on the disposition of assets; loss from discontinued operations, net of tax; 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 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 December 31, 2016, as determined in accordance with GAAP, to adjusted income excluding 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 loss attributable to common stockholders | $ | (44 | ) | $ | (0.26 | ) | |
Noncash MTM derivative losses, net ($222 million pretax) | 142 | 0.83 | |||||
Adjusted income excluding noncash MTM derivative losses | 98 | 0.57 | |||||
Tax credit for research and experimental expenditures | (13 | ) | (0.08 | ) | |||
Adjusted income excluding noncash MTM derivative losses and unusual items | $ | 85 | $ | 0.49 | |||
PIONEER NATURAL RESOURCES COMPANY
SUPPLEMENTAL INFORMATION
Open Commodity Derivative Positions as of February 3, 2017
(Volumes are average daily amounts)
2017 | Twelve Months Ending December 31, | |||||||||||||||||||
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | 2018 | ||||||||||||||||
Average Daily Oil Production Associated with Derivatives (Bbl): | ||||||||||||||||||||
Collar contracts: | ||||||||||||||||||||
Volume | 6,000 | 6,000 | 6,000 | 6,000 | — | |||||||||||||||
NYMEX price: | ||||||||||||||||||||
Ceiling | $ | 70.40 | $ | 70.40 | $ | 70.40 | $ | 70.40 | $ | — | ||||||||||
Floor | $ | 50.00 | $ | 50.00 | $ | 50.00 | $ | 50.00 | $ | — | ||||||||||
Collar contracts with short puts: | ||||||||||||||||||||
Volume | 119,000 | 129,000 | 147,000 | 155,000 | 20,000 | |||||||||||||||
NYMEX price: | ||||||||||||||||||||
Ceiling | $ | 61.36 | $ | 61.19 | $ | 62.03 | $ | 62.12 | $ | 65.14 | ||||||||||
Floor | $ | 48.67 | $ | 48.46 | $ | 49.81 | $ | 49.82 | $ | 50.00 | ||||||||||
Short put | $ | 40.65 | $ | 40.45 | $ | 41.07 | $ | 41.02 | $ | 40.00 | ||||||||||
Rollfactor swap contracts (a): | ||||||||||||||||||||
Volume | 13,111 | 20,000 | 20,000 | 20,000 | — | |||||||||||||||
NYMEX roll price | $ | (0.32 | ) | $ | (0.32 | ) | $ | (0.32 | ) | $ | (0.32 | ) | $ | — | ||||||
Basis swap contracts (b): | ||||||||||||||||||||
Midland-Cushing index swap volume | — | — | — | 3,000 | 740 | |||||||||||||||
Price | $ | — | $ | — | $ | — | $ | (0.65 | ) | $ | (0.65 | ) | ||||||||
Average Daily NGL Production Associated with Derivatives: | ||||||||||||||||||||
Butane Swap contracts (c): | ||||||||||||||||||||
Volume | — | 2,000 | 2,000 | — | — | |||||||||||||||
Index price | $ | — | $ | 34.86 | $ | 34.86 | $ | — | $ | — | ||||||||||
Butane collar contracts with short puts (c): | ||||||||||||||||||||
Volume | — | 2,000 | 2,000 | — | — | |||||||||||||||
Index price | ||||||||||||||||||||
Ceiling | $ | — | $ | 36.12 | $ | 36.12 | $ | — | $ | — | ||||||||||
Floor | $ | — | $ | 29.25 | $ | 29.25 | $ | — | $ | — | ||||||||||
Short put | $ | — | $ | 23.40 | $ | 23.40 | $ | — | $ | — | ||||||||||
Ethane collar contracts (d): | ||||||||||||||||||||
Volume | 3,000 | 3,000 | 3,000 | 3,000 | — | |||||||||||||||
Index price | ||||||||||||||||||||
Ceiling | $ | 11.83 | $ | 11.83 | $ | 11.83 | $ | 11.83 | $ | — | ||||||||||
Floor | $ | 8.68 | $ | 8.68 | $ | 8.68 | $ | 8.68 | $ | — | ||||||||||
Average Daily Gas Production Associated with Derivatives (MMBtu): | ||||||||||||||||||||
Collar contracts with short puts: | ||||||||||||||||||||
Volume | 190,000 | 190,000 | 190,000 | 190,000 | 62,329 | |||||||||||||||
NYMEX price: | ||||||||||||||||||||
Ceiling | $ | 3.51 | $ | 3.51 | $ | 3.51 | $ | 3.51 | $ | 3.56 | ||||||||||
Floor | $ | 2.93 | $ | 2.93 | $ | 2.93 | $ | 2.93 | $ | 2.91 | ||||||||||
Short put | $ | 2.46 | $ | 2.46 | $ | 2.46 | $ | 2.46 | $ | 2.37 | ||||||||||
Basis swap contracts: | ||||||||||||||||||||
Mid-Continent index swap volume (e) | 45,000 | 45,000 | 45,000 | 45,000 | — | |||||||||||||||
Price differential ($/MMBtu) | $ | (0.32 | ) | $ | (0.32 | ) | $ | (0.32 | ) | $ | (0.32 | ) | $ | — | ||||||
Permian Basin index swap volume (f) | 40,000 | — | — | — | — | |||||||||||||||
Price differential ($/MMBtu) | $ | 0.37 | $ | — | $ | — | $ | — | $ | — | ||||||||||
_______________
(a) | Represent swap contracts 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. |
(b) | Represent swap contracts that fix the basis differential between Midland , Texas WTI-posted prices and Cushing, Oklahoma WTI-posted prices. |
(c) | Represent swap contracts and collar contracts with short puts that reduce the price volatility of butane 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 swap contracts that fix the basis differentials between the index price at which the Company sells its Mid-Continent gas and the NYMEX Henry Hub index price used in collar contracts with short puts. |
(f) | Represent swap contracts 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. During the fourth quarter of 2016, the Company terminated interest rate derivative contracts on a notional amount of $150 million for cash proceeds of $7 million. As of February 3, 2017, 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 1.81 percent on a notional amount of $100 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 swap contracts to mitigate price risk. As of December 31, 2016 and February 3, 2017, the Company does not have any marketing derivatives outstanding.
Derivative Losses, Net
(in millions)
Three Months Ended December 31, 2016 | Twelve Months Ended December 31, 2016 | |||||||
Noncash changes in fair value: | ||||||||
Oil derivative losses | $ | (202 | ) | $ | (751 | ) | ||
NGL derivative losses | (1 | ) | (16 | ) | ||||
Gas derivative losses | (32 | ) | (90 | ) | ||||
Interest rate derivative gains | 14 | 6 | ||||||
Total noncash derivative losses, net | (222 | ) | (851 | ) | ||||
Net cash receipts (payments) on settled derivative instruments: | ||||||||
Oil derivative receipts | 137 | 609 | ||||||
NGL derivative receipts (payments) | (2 | ) | 5 | |||||
Gas derivative receipts | 12 | 67 | ||||||
Diesel derivative receipts | 2 | 2 | ||||||
Interest rate derivative receipts | 7 | 7 | ||||||
Total cash receipts on settled derivative instruments, net | 156 | 690 | ||||||
Total derivative losses, net | $ | (66 | ) | $ | (161 | ) | ||