EXHIBIT 99.1
News Release
Pioneer Natural Resources Reports Fourth Quarter 2014 Financial
and Operating Results
Dallas, Texas, February 10, 2015 - Pioneer Natural Resources Company (NYSE:PXD) (“Pioneer” or “the Company”) today announced financial and operating results for the quarter ended December 31, 2014.
Pioneer reported fourth quarter net income attributable to common stockholders of $431 million, or $2.91 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 gains and other unusual items, adjusted income for the fourth quarter was $116 million after tax, or $0.80 per diluted share.
Fourth quarter and other recent highlights included:
• | producing 201 thousand barrels oil equivalent per day (MBOEPD) from continuing operations in the fourth quarter, an increase of 15 MBOEPD, or 8%, compared to the third quarter of 2014 (reflects Barnett Shale and Hugoton divestitures as discontinued operations); oil production increased 12 thousand barrels per day (MBPD) quarter over quarter, or 13%; fourth quarter production growth was primarily driven by the Company’s successful Spraberry/Wolfcamp horizontal drilling program; |
• | producing 182 MBOEPD from continuing operations in 2014 (reflects Alaska, Barnett Shale and Hugoton divestitures as discontinued operations), an increase of 18% from 2013 on a comparable basis; this strong annual production growth was primarily related to the Company’s successful Spraberry/Wolfcamp (+26%) and Eagle Ford Shale (+23%) drilling programs; oil production increased 18 MBPD year-over-year, or 25%; |
• | delivering 239% drillbit reserve replacement in 2014 by adding proved reserves of 177 million barrels oil equivalent (MMBOE) from discoveries, extensions and technical revisions of previous estimates at a drillbit finding and development cost of $19.65 per barrel oil equivalent (BOE) (excludes revisions of previous estimates of 39 MMBOE of proved undeveloped (PUD) reserves related to vertical drilling locations in the Spraberry/Wolfcamp that are no longer expected to be drilled, 12 MMBOE of positive pricing revisions and acquisitions of 2 MMBOE); the drillbit finding and development cost for horizontal reserve additions was $15.51 per BOE; |
• | maintaining a strong year-end balance sheet with $1.0 billion of cash on hand, net debt-to-operating cash flow of less than 1.0 times and net debt-to-book capitalization of 16%; |
• | placing 36 Wolfcamp Shale wells on production in the A, B and D intervals during the fourth quarter in the northern Spraberry/Wolfcamp; for each interval, the fourth quarter wells are outperforming the average of all previously drilled wells in that interval; |
• | continuing the Company’s successful downspacing and staggering program in the Eagle Ford Shale, which included placing 16 horizontal wells on production in Upper targets during the fourth quarter; and |
• | exporting approximately 10 MBOEPD gross (3.5 MBOEPD net) of Eagle Ford Shale condensate during the second half of 2014 with significantly improved pricing compared to domestic condensate sales; approximately 20 MBOEPD gross (7 MBOEPD net) of Eagle Ford Shale condensate has been committed for export during 2015 under two contracts. |
Pioneer’s current outlook for 2015 is summarized below:
• | In response to the current low oil price environment and reduced margins, Pioneer is significantly reducing spending and is focusing on optimizing returns, capital efficiency and production by high-grading drilling activity in the best areas of the Spraberry/Wolfcamp and Eagle Ford Shale; this will preserve the Company’s strong cash position and balance sheet until margins improve. |
• | Pioneer is reducing horizontal drilling activity in the Spraberry/Wolfcamp and Eagle Ford Shale to 16 rigs by the end of February (approximately a 50% reduction from year-end 2014); this will include six rigs in the northern Spraberry/Wolfcamp, four rigs in the southern Wolfcamp joint venture area and six rigs in the Eagle Ford Shale; vertical drilling in the Spraberry/Wolfcamp area is being shut down by the end of February. |
• | Infrastructure projects, including construction of the Spraberry/Wolfcamp area water system and expansion of the Brady sand mine, will be slowed down. |
• | The reduction in drilling activity and infrastructure build-out results in planned capital expenditures of $1.85 billion for 2015, a 45% reduction from 2014 capital spending for continuing operations; $1.6 billion will be for drilling and the remaining $0.25 billion will be for water infrastructure, vertical integration and facilities. |
• | The 2015 capital program is expected to be funded from operating cash flow of $1.7 billion (assuming commodity prices of $55 per barrel for oil and $3.00 per thousand cubic feet (MCF) for gas) and cash on hand of $1.0 billion at year-end 2014. |
• | Production growth from continuing operations for 2015 is forecasted to be 10%+ compared to 2014 based on the $1.85 billion capital budget and the high-graded drilling program; growth is primarily weighted to the first half of the year, with production in the fourth quarter of 2015 expected to be essentially flat with production in the fourth quarter of 2014; oil production is forecasted to increase by 20%+ in 2015 compared to 2014. |
• | The Company expects to aggressively improve margins through cost reductions and efficiency gains; a 10% decrease in drilling costs has already been realized in 2015 compared to 2014; this decrease is expected to be at least 20% by the end of the year compared to 2014. |
• | Pioneer is prepared to add horizontal rigs later in 2015 in response to reduced costs and/or an improvement in the oil price environment. |
• | Divestment of the Eagle Ford Shale Midstream business continues to be pursued. |
• | The Company’s cash flow is protected by derivatives, including (i) coverage for 2015 forecasted oil production of approximately 90% with most volumes protected by swaps at $71 per barrel, (ii) a significant portion of 2016 oil production being covered by three-way collars that provide attractive downside protection and (iii) coverage for 2015 forecasted gas production of approximately 90% with three-way collars that provide attractive downside protection. |
Scott D. Sheffield, Chairman and CEO, stated, “The Company delivered another great operational quarter, with strong production growth being driven by impressive horizontal well performance in the Spraberry/Wolfcamp. We also achieved the substantial second half 2014 production growth that we forecasted early last year, successfully transforming our Spraberry/Wolfcamp acreage position from a vertical play into a world-class horizontal play.”
“In response to the current low oil price environment and reduced margins, we are preserving our strong cash position and balance sheet by reducing drilling activity and related infrastructure spending until margins improve significantly. Even with this slowdown, we will be able to continue to prudently develop and grow our industry-leading positions in the Spraberry/Wolfcamp and Eagle Ford Shale plays during 2015 by focusing our drilling activity in the best areas of both plays. As a result of our strong balance sheet, planned Eagle Ford Shale Midstream sale and strong derivatives position, Pioneer has the financial flexibility to prudently manage through a protracted oil price downturn or quickly ramp up drilling activity when margins improve.”
Mark-To-Market Derivative Gains and Unusual Items Included in Fourth Quarter 2014 Earnings
Pioneer’s fourth quarter earnings included noncash mark-to-market gains on derivatives of $364 million after tax, or $2.45 per diluted share.
Fourth quarter earnings also included a net loss of $49 million after tax, or $0.34 per diluted share, related to the following unusual items:
• | a charge of $45 million after tax, or $0.31 per diluted share, associated with the impairment of unproved acreage and exploration costs in southeastern Colorado (Black Fox prospect); |
• | a charge of $6 million after tax, or $0.04 per diluted share, associated with drilling rig termination charges, and |
• | income from discontinued operations of $2 million, or $0.01 per diluted share, associated with post-closing adjustments related to the Barnett Shale and Hugoton divestitures in 2014. |
Spraberry/Wolfcamp Operations Update and 2015 Outlook
In the northern Spraberry/Wolfcamp, the Company successfully placed 36 horizontal Wolfcamp Shale wells on production during the fourth quarter. This included 20 Wolfcamp B interval wells, 11 Wolfcamp A interval wells and five Wolfcamp D interval wells. The 36 wells delivered an average 24-hour peak initial production (IP) rate of approximately 1,700 barrels oil equivalent per day (BOEPD) with 76% oil content. For each interval, the wells placed on production in the fourth quarter are outperforming the average of all previously drilled wells in that interval based on their first sixty days of cumulative production. This improvement is attributed to the longer average lateral lengths for these wells and Pioneer’s expanding knowledge of the play. Production from the Wolfcamp A and Wolfcamp B interval wells placed on production during the fourth quarter is expected to be representative of the high-graded 2015 drilling program for the northern Spraberry/Wolfcamp (discussed below).
Four horizontal Lower Spraberry Shale wells were also placed on production during the fourth quarter. Early production data from these wells, which had an average oil content of 80% and an average lateral length of 5,600 feet, is similar to Pioneer’s previously drilled horizontal Lower Spraberry Shale wells. One horizontal Jo Mill Shale well and two horizontal Middle Spraberry Shale wells were also placed on production during the fourth quarter. The Jo Mill Shale well delivered Pioneer’s highest 24-hour peak IP rate to date for this interval of 914 BOEPD, with an oil content of 81% and a lateral length of 4,850 feet. The two Middle Spraberry Shale wells had an average 24-hour peak IP rate of 417 BOEPD, with an average oil content of 76% and an average lateral length of 6,000 feet.
Pioneer’s horizontal rig count in the northern Spraberry/Wolfcamp is being reduced to six rigs by the end of February. Drilling activity is being high-graded to the areas and intervals in the play with the highest estimated ultimate recoveries (EURs) and net revenue interests. Activity will also be focused in areas where horizontal tank batteries already exist. The Company plans to spud approximately 60 new wells in 2015 utilizing two-well and three-well pads. Approximately 90% of these new wells will be drilled in the Wolfcamp B interval and the remaining 10% in the Wolfcamp A interval.
As a result of the carryover drilling activity from 2014 (wells drilled, but not completed) in the northern Spraberry/Wolfcamp, Pioneer expects to place 85 to 90 horizontal wells on production during 2015 compared to 97 horizontal wells in 2014. Of these, 70% will be Wolfcamp B interval wells and the remainder will be split between Wolfcamp A, Wolfcamp D and Lower Spraberry Shale interval wells. The average cost to drill and complete a well in 2015 is expected to be approximately $9 million, assuming an average lateral length of 9,000 feet and an average 10% cost reduction compared to 2014. The 2015 drilling program is expected to generate EURs averaging approximately 900 thousand barrels oil equivalent (MBOE) with before-tax internal rates of return (IRRs) up to 55% at current strip prices (average oil price of $55 per barrel during 2015). The vertical drilling program is being shut down by the end of February.
In the southern Wolfcamp joint venture area, Pioneer’s horizontal rig count is being reduced to four rigs by the end of February. As in the northern Spraberry/Wolfcamp, drilling activity is being high-graded to the areas and intervals in the play with the highest EURs and net revenue interests. Activity will also be focused in areas where horizontal tank batteries already exist. The Company plans to spud approximately 45 new wells in 2015 utilizing two-well and three-well pads. More than 90% of these new wells will be drilled in the Wolfcamp B interval.
As a result of the carryover drilling activity from 2014 (wells drilled, but not completed) in the southern Wolfcamp joint venture area, Pioneer expects to place 75 to 80 horizontal wells on production during 2015 compared to 113 horizontal wells in 2014. Of these, 75% will be Wolfcamp B interval wells and the remainder will be split between Wolfcamp A and Wolfcamp D interval wells. The average cost to drill and complete a well in 2015 is expected to be approximately $8 million, assuming an average lateral length of 9,000 feet and an average 10% cost reduction compared to 2014. The 2015 drilling program is expected to generate EURs averaging approximately 750 MBOE with before-tax IRRs up to 55% at current strip prices (average oil price of $55 per barrel during 2015).
Sixty-nine horizontal wells were placed on production during the fourth quarter over the entire Spraberry/Wolfcamp. Of these, 43 wells were in the northern Spraberry/Wolfcamp and 26 were in the southern Wolfcamp joint venture area. Thirty vertical wells were also placed on production. As a result of this activity, fourth quarter production averaged 115 MBOEPD, an increase of 12 MBOEPD compared to the third quarter. Horizontal production increased by 17 MBOEPD, more than offsetting declines in vertical production of 5 MBOEPD. Oil production was up 10 MBOEPD from the third quarter to the fourth quarter. Full-year production averaged 99 MBOEPD, an increase of 26% compared to 2013.
Spraberry/Wolfcamp production is forecasted to increase by 20%+ in 2015 compared to 2014. Production growth is expected to be weighted toward the first half of the year as carryover wells from the fourth quarter of 2014 (drilled, but not completed) are placed on production in the first quarter combined with reduced drilling activity in 2015. As a result, production in the fourth quarter of 2015 is expected to be essentially flat with production in the fourth quarter of 2014. Production in 2015, as compared to 2014, is expected to be negatively impacted by (i) 1 MBOEPD (annual impact) of weather-related production curtailments experienced during January in the Spraberry/Wolfcamp and (ii) 2 MBOEPD associated with rejecting ethane due to weak market conditions that are expected to continue throughout the year.
Spraberry/Wolfcamp Infrastructure Plans
Pioneer’s long-term growth plan is focused on optimizing the development of the Spraberry/Wolfcamp, which includes ensuring that future infrastructure requirements are constructed. These requirements include the build-out of horizontal tank batteries, construction of additional gas processing facilities, expansion of the Brady sand mine and construction of a field-wide water distribution network. In response to the reduction in horizontal drilling activity, spending for this infrastructure is being curtailed significantly.
The Company expects to spend approximately $215 million for new large-scale tank batteries and saltwater disposal facilities during 2015. Most of this spending will support the high-graded drilling program.
Atlas Pipeline Partners L.P. (Atlas) remains committed to complete a new 200 million cubic feet per day (MMCFPD) gas processing plant in Martin County (Buffalo plant), but has deferred start-up from the third quarter of 2015 to 2016. The additional plant scheduled for 2016 has been deferred indefinitely. The Company plans to spend approximately $70 million in 2015 for (i) early construction activity on the Buffalo plant and (ii) gathering system investments for both the Atlas and West Texas Gas, Inc. (WTG) systems.
Recognizing that Pioneer’s proppant requirements will be reduced in response to the drilling slowdown, expansion of the Brady sand mine capacity from 750 thousand tons per year to 2.1 million tons per year is being deferred until at least 2016. The 2015 capital budget includes approximately $25 million for
maintenance capital, continued engineering work and site preparation associated with the Brady sand mine facilities.
Plans originally called for the initial phase of Pioneer’s field-wide water transport system to commence in 2015. As a result of the slowdown in Pioneer’s drilling program, 2015 capital spending is expected to be $100 million, with activity limited to the construction of a feeder line and the associated mainline segment that will allow water to be piped from an existing third-party Santa Rosa aquifer source to Pioneer’s high-graded drilling acreage in the southern Wolfcamp joint venture area. Well costs in the high-graded area will be reduced by $150 thousand per well as a result of this connection. System engineering and right-of-way acquisition will also continue during 2015. Pioneer is working with the City of Odessa to allow Pioneer to defer offtake of effluent water. Discussions are continuing with the City of Midland to purchase effluent water when drilling activity increases.
Eagle Ford Shale Operations Update and 2015 Outlook
In the liquids-rich area of the Eagle Ford Shale play in South Texas, Pioneer placed 128 horizontal wells on production in 2014. Of this total, 50 wells were in Upper targets as part of the Company’s downspacing and staggering program in the Lower and Upper Eagle Ford Shale. Wells are being downspaced from 500 feet to a range of 175 feet to 300 feet between staggered wells. Production results from these wells continue to be similar to offset Lower Eagle Ford Shale wells. Approximately 25% of Pioneer’s acreage is expected to be prospective for the Upper Eagle Ford Shale.
Pioneer’s fourth quarter production from the Eagle Ford Shale averaged 49 MBOEPD. Thirty horizontal wells were placed on production during the quarter, including 16 wells in Upper targets. Production was negatively impacted during the quarter by unplanned downtime at one of the Company’s central gathering plants, delays in placing a few wells on production and greater-than-anticipated shut-in production related to offset fracture stimulations on nearby wells. Production averaged 46 MBOEPD in 2014, an increase of 23% compared to 2013.
Pioneer’s horizontal rig count in the Eagle Ford Shale is being reduced to six rigs by the end of February. Drilling activity is being high-graded to Karnes and DeWitt counties where Pioneer has been drilling the most productive wells in the Eagle Ford Shale with EURs averaging approximately 1.3 MMBOE. Pioneer expects to place 95 to 100 horizontal wells on production during 2015, split evenly between Upper targets and Lower targets.
The average drilling and completion cost for the 2015 program in the Eagle Ford Shale is expected to be $7.0 million to $8.0 million per well, reflecting an average lateral length of 5,000 feet and an assumed 10% cost reduction compared to 2014. The high-graded 2015 drilling program is expected to generate before-tax IRRs up to 70% at current strip prices (average oil price of $55 per barrel during 2015).
Eagle Ford Shale production is forecasted to increase by 9%+ in 2015 compared to 2014. Production is expected to be relatively flat throughout the year compared to the fourth quarter of 2014, reflecting the timing of new wells placed on production. Production in 2015 is expected to be lower by approximately 2 MBOEPD compared to 2014 due to low ethane prices causing the Company to elect to reject ethane. Ethane rejection commenced in January and is expected to continue throughout the year as a result of weak market conditions.
Optimizing Returns in a Lower Price Environment
Pioneer is aggressively implementing initiatives to gain cost efficiencies and is soliciting cost reductions from suppliers and service companies. A 10% reduction in drilling costs in 2015 compared to 2014 has already been realized, with a reduction of at least 20% expected by the end of this year compared to 2014.
Examples of initiatives to gain efficiencies include:
• | completion optimization in the Spraberry/Wolfcamp where the testing of increased clusters per stage and optimized fluid chemistry and proppant concentrations continue to be encouraging, |
• | modified three-string and two-string casing design in the Upper Wolfcamp B and Wolfcamp A intervals in the southern Wolfcamp joint venture area, a potential savings of $500 thousand to $1 million per well; application of these designs is also being evaluated in Pioneer’s northern Spraberry/Wolfcamp acreage, and |
• | dissolvable plug technologies in the Spraberry/Wolfcamp and Eagle Ford Shale to reduce or eliminate coil tubing drillouts after fracture stimulations, a potential savings of $300 thousand per well. |
Areas of focus for cost reductions from suppliers and service companies include:
• | materials for drilling and fracture stimulation such as casing and tubing, drilling mud, chemicals and guar, |
• | freight rates, |
• | fuel charges for rigs, equipment and fleet vehicles, |
• | drilling rig contract rates, |
• | rental equipment such as blowout preventers and coil tubing, and |
• | wireline services. |
2015 Capital Budget
Pioneer’s capital program for 2015 of $1.85 billion (excludes acquisitions, asset retirement obligations, capitalized interest, geological and geophysical G&A) includes $1.6 billion for drilling and $0.25 billion related to the development of the Spraberry/Wolfcamp water infrastructure, vertical integration and facilities.
The following provides a breakdown of the drilling capital by asset:
• | Northern Spraberry/Wolfcamp - $1,050 million (includes $735 million for the horizontal drilling program, $20 million for the vertical drilling program, $225 million for infrastructure additions and land, and $70 million for gas processing facilities) |
• | Southern Wolfcamp joint venture area (net of carry) - $120 million (includes $90 million for the horizontal drilling program and $30 million for infrastructure additions and land) |
• | Eagle Ford Shale - $390 million (includes $335 million for the horizontal drilling program and $55 million for infrastructure additions and land) |
• | Other Assets - $40 million |
The 2015 capital budget is expected to be funded from forecasted operating cash flow of $1.7 billion (assuming commodity prices of $55 per barrel for oil and $3.00 per MCF for gas) and $1.0 billion of cash on the balance sheet at year-end 2014.
Pioneer’s year-end 2014 net debt was $1.6 billion with net debt-to-operating cash flow of less than 1.0 times and net debt-to-book capitalization of 16%. The Company will continue to target net debt-to-operating cash flow below 1.5 and a net debt-to-book capitalization below 35%.
Fourth Quarter 2014 Financial Review
Sales volumes from continuing operations for the fourth quarter of 2014 averaged 201 MBOEPD (excludes Barnett Shale and Hugoton production, which is reflected in discontinued operations). Oil sales averaged 101 MBPD, natural gas liquids (NGLs) sales averaged 43 MBPD and gas sales averaged 347 MMCFPD.
The average realized price for oil was $66.64 per barrel. The average realized price for NGLs was $18.50 per barrel, and the average realized price for gas was $3.60 per MCF. These prices exclude the effects of derivatives.
Production costs from continuing operations averaged $13.61 per BOE. Depreciation, depletion and amortization (DD&A) expense averaged $16.95 per BOE. Exploration and abandonment costs were $97 million, principally comprised of $71 million for the impairment of the Black Fox prospect and associated exploration costs in southeastern Colorado (unusual item), $4 million for seismic data and $14 million for personnel costs. General and administrative expense totaled $89 million. Interest expense was $46 million and other expense was $34 million, which included $9 million of drilling rig termination fees (unusual item).
First Quarter 2015 Financial Outlook
The Company’s first quarter 2015 outlook for certain operating and financial items is provided below.
Production is forecasted to average 192 MBOEPD to 197 MBOEPD. First quarter production guidance reflects an estimated production loss of (i) 3 MBOEPD in the Spraberry/Wolfcamp due to weather-related production curtailments experienced in January and (ii) 4 MBOEPD attributable to rejecting ethane due to weak market conditions.
Production costs are expected to average $13.25 per BOE to $15.25 per BOE. DD&A expense is expected to average $16.00 per BOE to $18.00 per BOE. Total exploration and abandonment expense is forecasted to be $25 million to $35 million.
General and administrative expense is expected to be $78 million to $83 million, interest expense is expected to be $45 million to $50 million and other expense is expected to be $30 million to $40 million, which includes $7 million to $11 million for stacked drilling rig charges. 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 $1 million to $5 million and are primarily attributable to 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, February 11, 2015, at 9:00 a.m. Central Time, Pioneer will discuss its financial and operating results for the quarter ended December 31, 2014 and 2015 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 (888) 855-5838 and confirmation code: 1285607 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 8, 2015, by dialing (888) 203-1112 and confirmation code: 1285607.
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, litigation, the costs and results of drilling and operations, availability of equipment, services, resources and personnel required to perform the Company’s drilling and operating activities, access to and availability of transportation, processing, fractionation and refining facilities, Pioneer's ability to replace reserves, implement its business plans or complete its development activities as scheduled, access to and cost of capital, uncertainties about estimates of reserves and resource potential and the ability to add proved reserves in the future, the assumptions underlying production forecasts, quality of technical data, and environmental and weather risks, including the possible impacts of climate change, and acts of war or terrorism. These and other risks are described in Pioneer's 10-K and 10-Q Reports and other filings with the U.S. Securities and Exchange Commission (SEC). In addition, Pioneer may be subject to currently unforeseen risks that may have a materially adverse impact on it. Pioneer undertakes no duty to publicly update these statements except as required by law.
Cautionary Note to U.S. Investors --The SEC prohibits oil and gas companies, in their filings with the SEC, from disclosing estimates of oil or gas resources other than “reserves,” as that term is defined by the SEC. In this news release, Pioneer includes estimates of quantities of oil and gas using certain terms, such as “resource potential,” “net recoverable resource potential,” “estimated ultimate recovery,” “EUR,” “oil-in-place” or other descriptions of volumes of reserves, which terms include quantities of oil and gas that may not meet the SEC’s definitions of proved, probable and possible reserves, and which the SEC's guidelines strictly prohibit Pioneer from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being recovered by Pioneer.
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 excludes vertical Spraberry/Wolfcamp PUDs removed and 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 excludes vertical Spraberry/Wolfcamp PUDs removed and price revisions.
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
Steven Cobb - 972-969-5679
Media and Public Affairs
Tadd Owens - 972-969-5760
Suzanne Hicks - 972-969-4020
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions)
December 31, 2014 | December 31, 2013 | |||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 1,025 | $ | 393 | ||||
Accounts receivable, net | 440 | 434 | ||||||
Income taxes receivable | 23 | 5 | ||||||
Inventories | 241 | 220 | ||||||
Prepaid expenses | 15 | 16 | ||||||
Assets held for sale | — | 584 | ||||||
Derivatives | 578 | 76 | ||||||
Other | 37 | 2 | ||||||
Total current assets | 2,359 | 1,730 | ||||||
Property, plant and equipment, at cost: | ||||||||
Oil and gas properties, using the successful efforts method of accounting | 15,821 | 13,529 | ||||||
Accumulated depletion, depreciation and amortization | (5,431 | ) | (4,903 | ) | ||||
Total property, plant and equipment | 10,390 | 8,626 | ||||||
Goodwill | 272 | 274 | ||||||
Other property and equipment, net | 1,391 | 1,224 | ||||||
Investment in unconsolidated affiliate | 239 | 225 | ||||||
Derivatives | 181 | 91 | ||||||
Other assets, net | 94 | 124 | ||||||
$ | 14,926 | $ | 12,294 | |||||
LIABILITIES AND EQUITY | ||||||||
Current liabilities: | ||||||||
Accounts payable | $ | 1,320 | $ | 1,060 | ||||
Interest payable | 40 | 62 | ||||||
Income taxes payable | 1 | — | ||||||
Deferred income taxes | 161 | 19 | ||||||
Liabilities held for sale | — | 39 | ||||||
Derivatives | 3 | 12 | ||||||
Other | 55 | 58 | ||||||
Total current liabilities | 1,580 | 1,250 | ||||||
Long-term debt | 2,665 | 2,653 | ||||||
Derivatives | 2 | 10 | ||||||
Deferred income taxes | 1,803 | 1,473 | ||||||
Other liabilities | 287 | 293 | ||||||
Equity | 8,589 | 6,615 | ||||||
$ | 14,926 | $ | 12,294 | |||||
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, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Revenues and other income: | ||||||||||||||||
Oil and gas | $ | 804 | $ | 792 | $ | 3,599 | $ | 3,088 | ||||||||
Sales of purchased oil and gas | 172 | 140 | 726 | 334 | ||||||||||||
Interest and other | (1 | ) | 14 | 9 | 17 | |||||||||||
Derivative gains, net | 693 | 4 | 712 | 4 | ||||||||||||
Gain (loss) on disposition of assets, net | (2 | ) | 3 | 9 | 209 | |||||||||||
1,666 | 953 | 5,055 | 3,652 | |||||||||||||
Costs and expenses: | ||||||||||||||||
Oil and gas production | 200 | 148 | 693 | 588 | ||||||||||||
Production and ad valorem taxes | 51 | 45 | 220 | 192 | ||||||||||||
Depletion, depreciation and amortization | 313 | 239 | 1,047 | 889 | ||||||||||||
Purchased oil and gas | 168 | 140 | 703 | 336 | ||||||||||||
Impairment of oil and gas properties | — | 1,495 | — | 1,495 | ||||||||||||
Exploration and abandonments | 97 | 31 | 177 | 97 | ||||||||||||
General and administrative | 89 | 96 | 333 | 296 | ||||||||||||
Accretion of discount on asset retirement obligations | 3 | 3 | 12 | 12 | ||||||||||||
Interest | 46 | 45 | 184 | 184 | ||||||||||||
Other | 33 | 73 | 89 | 137 | ||||||||||||
1,000 | 2,315 | 3,458 | 4,226 | |||||||||||||
Income (loss) from continuing operations before income taxes | 666 | (1,362 | ) | 1,597 | (574 | ) | ||||||||||
Income tax benefit (provision) | (237 | ) | 494 | (556 | ) | 213 | ||||||||||
Income (loss) from continuing operations | 429 | (868 | ) | 1,041 | (361 | ) | ||||||||||
Income (loss) from discontinued operations, net of tax | 2 | (490 | ) | (111 | ) | (438 | ) | |||||||||
Net income (loss) | 431 | (1,358 | ) | 930 | (799 | ) | ||||||||||
Net (income) loss attributable to noncontrolling interests | — | (9 | ) | — | (39 | ) | ||||||||||
Net income (loss) attributable to common stockholders | $ | 431 | $ | (1,367 | ) | $ | 930 | $ | (838 | ) | ||||||
Basic earnings per share attributable to common stockholders: | ||||||||||||||||
Income (loss) from continuing operations | $ | 2.91 | $ | (6.30 | ) | $ | 7.17 | $ | (2.94 | ) | ||||||
Income (loss) from discontinued operations | 0.01 | (3.52 | ) | (0.77 | ) | (3.22 | ) | |||||||||
Net income (loss) | $ | 2.92 | $ | (9.82 | ) | $ | 6.40 | $ | (6.16 | ) | ||||||
Diluted earnings per share attributable to common stockholders: | ||||||||||||||||
Income (loss) from continuing operations | $ | 2.90 | $ | (6.30 | ) | $ | 7.15 | $ | (2.94 | ) | ||||||
Income (loss) from discontinued operations | 0.01 | (3.52 | ) | (0.77 | ) | (3.22 | ) | |||||||||
Net income (loss) | $ | 2.91 | $ | (9.82 | ) | $ | 6.38 | $ | (6.16 | ) | ||||||
Weighted average shares outstanding: | ||||||||||||||||
Basic | 146 | 139 | 144 | 136 | ||||||||||||
Diluted | 147 | 139 | 144 | 136 | ||||||||||||
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Cash flows from operating activities: | ||||||||||||||||
Net income (loss) | $ | 431 | $ | (1,358 | ) | $ | 930 | $ | (799 | ) | ||||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||||||||
Depletion, depreciation and amortization | 313 | 239 | 1,047 | 889 | ||||||||||||
Impairment of oil and gas properties | — | 1,495 | — | 1,495 | ||||||||||||
Impairment of inventory and other property and equipment | 1 | 54 | 8 | 62 | ||||||||||||
Exploration expenses, including dry holes | 79 | 12 | 90 | 21 | ||||||||||||
Deferred income taxes | 237 | (499 | ) | 552 | (224 | ) | ||||||||||
(Gain) loss on disposition of assets, net | 2 | (3 | ) | (9 | ) | (209 | ) | |||||||||
Accretion of discount on asset retirement obligations | 3 | 3 | 12 | 12 | ||||||||||||
Discontinued operations | 4 | 519 | 251 | 633 | ||||||||||||
Interest expense | 4 | 4 | 17 | 17 | ||||||||||||
Derivative related activity | (570 | ) | 42 | (609 | ) | 164 | ||||||||||
Amortization of stock-based compensation | 21 | 18 | 84 | 71 | ||||||||||||
Other noncash items | (9 | ) | 2 | 34 | (6 | ) | ||||||||||
Change in operating assets and liabilities: | ||||||||||||||||
Accounts receivable, net | 48 | (34 | ) | (29 | ) | (123 | ) | |||||||||
Income taxes receivable | (1 | ) | 5 | (18 | ) | 3 | ||||||||||
Inventories | (10 | ) | (11 | ) | (37 | ) | (39 | ) | ||||||||
Prepaid expenses | 8 | 7 | (3 | ) | (1 | ) | ||||||||||
Other current assets | 2 | 2 | 1 | 4 | ||||||||||||
Accounts payable | 8 | 24 | 104 | 209 | ||||||||||||
Interest payable | 4 | 26 | (22 | ) | (6 | ) | ||||||||||
Income taxes payable | — | — | 1 | — | ||||||||||||
Other current liabilities | (8 | ) | (5 | ) | (38 | ) | (27 | ) | ||||||||
Net cash provided by operating activities | 567 | 542 | 2,366 | 2,146 | ||||||||||||
Net cash used in investing activities | (1,070 | ) | (678 | ) | (2,699 | ) | (2,140 | ) | ||||||||
Net cash provided by (used in) financing activities | 978 | (215 | ) | 965 | 158 | |||||||||||
Net increase (decrease) in cash and cash equivalents | 475 | (351 | ) | 632 | 164 | |||||||||||
Cash and cash equivalents, beginning of period | 550 | 744 | 393 | 229 | ||||||||||||
Cash and cash equivalents, end of period | $ | 1,025 | $ | 393 | $ | 1,025 | $ | 393 | ||||||||
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUMMARY PRODUCTION AND PRICE DATA
Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Average Daily Sales Volumes from Continuing Operations: | ||||||||||||||||
Oil (Bbls) | 100,532 | 72,129 | 87,034 | 69,527 | ||||||||||||
Natural gas liquids ("NGL") (Bbls) | 42,582 | 31,818 | 38,646 | 29,910 | ||||||||||||
Gas (Mcf) | 347,035 | 319,508 | 339,341 | 331,003 | ||||||||||||
Total (BOE) | 200,953 | 157,198 | 182,237 | 154,604 | ||||||||||||
Average Realized Prices from Continuing Operations: | ||||||||||||||||
Oil (per Bbl) | $ | 66.64 | $ | 90.88 | $ | 85.29 | $ | 92.62 | ||||||||
NGL (per Bbl) | $ | 18.50 | $ | 30.18 | $ | 27.06 | $ | 29.99 | ||||||||
Gas (per Mcf) | $ | 3.60 | $ | 3.39 | $ | 4.10 | $ | 3.39 | ||||||||
Total (BOE) | $ | 43.48 | $ | 54.70 | $ | 54.11 | $ | 54.71 | ||||||||
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY EARNINGS PER SHARE INFORMATION
The Company uses the two-class method of calculating basic and diluted earnings per share. Under the two-class method of calculating earnings per share, generally acceptable accounting principles ("GAAP") provide that share-based awards with guaranteed dividend or distribution participation rights qualify as "participating securities" during their vesting periods. The Company's basic net income (loss) per share attributable to common stockholders is computed as (i) net income (loss) attributable to common stockholders, (ii) less participating share-based basic earnings (iii) divided by weighted average basic shares outstanding. The Company's diluted net income (loss) per share attributable to common stockholders is computed as (i) basic net income (loss) attributable to common stockholders, (ii) plus the reallocation of participating earnings, if any, (iii) divided by weighted average diluted shares outstanding. During periods in which the Company realizes a loss from continuing operations attributable to common stockholders, securities or other contracts to issue common stock would be dilutive to loss per share; therefore, conversion into common stock is assumed not to occur.
The following table is a reconciliation of the Company's net income (loss) attributable to common stockholders to basic and diluted net income (loss) attributable to common stockholders for the three and twelve months ended December 31, 2014 and 2013:
Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
(in millions) | ||||||||||||||||
Net income (loss) attributable to common stockholders | $ | 431 | $ | (1,367 | ) | $ | 930 | $ | (838 | ) | ||||||
Participating basic earnings | (5 | ) | — | (10 | ) | — | ||||||||||
Basic and diluted net income (loss) attributable to common stockholders | $ | 426 | $ | (1,367 | ) | $ | 920 | $ | (838 | ) | ||||||
The following table is a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three and twelve months ended December 31, 2014 and 2013:
Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||
2014 | 2013 (a) | 2014 | 2013 (b) | |||||||||
(in millions) | ||||||||||||
Weighted average common shares outstanding: | ||||||||||||
Basic | 146 | 139 | 144 | 136 | ||||||||
Contingently issuable performance unit shares | 1 | — | — | — | ||||||||
Diluted | 147 | 139 | 144 | 136 | ||||||||
_______________
(a) | The following common share equivalents were excluded from the weighted average diluted shares for the quarter ended December 31, 2013 because they would have been anti-dilutive: (i) 118,988 of outstanding options to purchase the Company's common stock and (ii) 250,145 of common shares attributable to unvested performance awards. |
(b) | The following common share equivalents were excluded from the weighted average diluted shares for the year ended December 31, 2013 because they would have been anti-dilutive: (i) 135,190 of outstanding options to purchase the Company's common stock, (ii) 200,360 of common shares attributable to unvested performance awards and (iii) 1,087,401 common shares related to the 2013 redemption of the Convertible Senior Notes, representing the weighted average portion of the year that is not included in the basic weighted average common shares outstanding. |
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES
(in millions)
EBITDAX and discretionary cash flow ("DCF") (as defined below) are presented herein, and reconciled to the GAAP measures of net income (loss) and net cash provided by operating activities, because of their wide acceptance by the investment community as financial indicators of a company's ability to internally fund exploration and development activities and to service or incur debt. The Company also views the non-GAAP measures of EBITDAX and DCF as useful tools for comparisons of the Company's financial indicators with those of peer companies that follow the full cost method of accounting. EBITDAX and DCF should not be considered as alternatives to net income (loss) or net cash provided by operating activities, as defined by GAAP.
Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Net income (loss) | $ | 431 | $ | (1,358 | ) | $ | 930 | $ | (799 | ) | ||||||
Depletion, depreciation and amortization | 313 | 239 | 1,047 | 889 | ||||||||||||
Exploration and abandonments | 97 | 31 | 177 | 97 | ||||||||||||
Impairment of oil and gas properties | — | 1,495 | — | 1,495 | ||||||||||||
Impairment of inventory and other property and equipment | 1 | 54 | 8 | 62 | ||||||||||||
Accretion of discount on asset retirement obligations | 3 | 3 | 12 | 12 | ||||||||||||
Interest expense | 46 | 45 | 184 | 184 | ||||||||||||
Income tax (benefit) provision | 237 | (494 | ) | 556 | (213 | ) | ||||||||||
(Gain) loss on disposition of assets, net | 2 | (3 | ) | (9 | ) | (209 | ) | |||||||||
(Income) loss from discontinued operations, net of tax | (2 | ) | 490 | 111 | 438 | |||||||||||
Derivative related activity | (570 | ) | 42 | (609 | ) | 164 | ||||||||||
Amortization of stock-based compensation | 21 | 18 | 84 | 71 | ||||||||||||
Other | (9 | ) | 2 | 34 | (6 | ) | ||||||||||
EBITDAX (a) | 570 | 564 | 2,525 | 2,185 | ||||||||||||
Cash interest expense | (42 | ) | (41 | ) | (167 | ) | (167 | ) | ||||||||
Current income tax provision | — | (5 | ) | (4 | ) | (11 | ) | |||||||||
Discretionary cash flow (b) | 528 | 518 | 2,354 | 2,007 | ||||||||||||
Discontinued operations cash activity | 6 | 29 | 140 | 195 | ||||||||||||
Cash exploration expense | (18 | ) | (19 | ) | (87 | ) | (76 | ) | ||||||||
Changes in operating assets and liabilities | 51 | 14 | (41 | ) | 20 | |||||||||||
Net cash provided by operating activities | $ | 567 | $ | 542 | $ | 2,366 | $ | 2,146 | ||||||||
_______________
(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; (income) 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 gains, and adjusted income excluding noncash MTM derivative gains 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 December 31, 2014, as determined in accordance with GAAP, to adjusted income excluding noncash MTM derivative gains and adjusted income excluding noncash MTM derivative gains and unusual items for that quarter.
After-tax Amounts | Amounts Per Share | ||||||
Net income attributable to common stockholders | $ | 431 | $ | 2.91 | |||
Noncash MTM derivative gains | (364 | ) | (2.45 | ) | |||
Adjusted income excluding noncash MTM derivative gains | 67 | 0.46 | |||||
Income associated with discontinued operations | (2 | ) | (0.01 | ) | |||
Southeast Colorado (Black Fox prospect) unproved acreage and exploration impairment | 45 | 0.31 | |||||
Drilling rig termination fees | 6 | 0.04 | |||||
Adjusted income excluding noncash MTM derivative gains and unusual items | $ | 116 | $ | 0.80 | |||
PIONEER NATURAL RESOURCES COMPANY
SUPPLEMENTAL INFORMATION
Open Commodity Derivative Positions as of February 6, 2015
Twelve Months Ending December 31, | ||||||||||||
2015 | 2016 | 2017 | ||||||||||
Average Daily Oil Production Associated with Derivatives (Bbl): | ||||||||||||
Swap contracts: | ||||||||||||
Volume | 82,000 | — | — | |||||||||
NYMEX price | $ | 71.18 | $ | — | $ | — | ||||||
Collar contracts with short puts (a): | ||||||||||||
Volume | 13,767 | 73,000 | — | |||||||||
NYMEX price: | ||||||||||||
Ceiling | $ | 97.13 | $ | 80.67 | $ | — | ||||||
Floor | $ | 82.78 | $ | 70.70 | $ | — | ||||||
Short put | $ | 69.19 | $ | 49.41 | $ | — | ||||||
Rollfactor swap contracts (b): | ||||||||||||
Volume | 36,575 | — | — | |||||||||
NYMEX roll price | $ | 0.06 | $ | — | $ | — | ||||||
Average Daily NGL Production Associated with Derivatives (Bbl): | ||||||||||||
Ethane Swap contracts (c): | ||||||||||||
Volume | 4,575 | 4,000 | — | |||||||||
Index price | $ | 7.83 | $ | 12.29 | $ | — | ||||||
Propane Swap contracts (c): | ||||||||||||
Volume | 7,778 | 2,000 | — | |||||||||
Index price | $ | 21.48 | $ | 21.63 | $ | — | ||||||
Average Daily Gas Production Associated with Derivatives (MMBtu): | ||||||||||||
Swap contracts: | ||||||||||||
Volume | 20,000 | 70,000 | — | |||||||||
NYMEX price | $ | 4.31 | $ | 4.06 | $ | — | ||||||
Collar contracts with short puts: | ||||||||||||
Volume | 285,000 | 20,000 | — | |||||||||
NYMEX price: | ||||||||||||
Ceiling | $ | 5.07 | $ | 5.36 | $ | — | ||||||
Floor | $ | 4.00 | $ | 4.00 | $ | — | ||||||
Short put | $ | 3.00 | $ | 3.00 | $ | — | ||||||
Basis swap contracts (d): | ||||||||||||
Gulf Coast index swap volume | 20,000 | — | — | |||||||||
Price differential ($/MMBtu) | $ | — | $ | — | $ | — | ||||||
Permian Basin index swap volume | 10,000 | — | — | |||||||||
Price differential ($/MMBtu) | $ | (0.13 | ) | $ | — | $ | — | |||||
Mid-Continent index swap volume | 95,000 | 15,000 | 30,000 | |||||||||
Price differential ($/MMBtu) | $ | (0.24 | ) | $ | (0.32 | ) | $ | (0.34 | ) | |||
_______________
(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 swap contracts that reduce the price volatility of ethane and propane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices. |
(d) | Represent swaps that fix the basis differentials between the index prices at which the Company sells its Gulf Coast, Mid-Continent and Permian Basin gas, respectively, and the NYMEX Henry Hub index price used in gas swap and collar contracts with short puts. |
Interest rate derivatives. As of February 6, 2015, the Company was a party to interest rate derivative contracts whereby the Company will receive the 10-year Treasury rate in exchange for paying average fixed rates of 2.43 percent on a notional amount of $200 million on June 30, 2015 and 2.37 percent on a notional amount of $150 million on September 15, 2015.
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 February 6, 2015, the Company had oil index swap contracts totaling 10,000 Bbls per day for 2015 with a price differential of $2.99 per Bbl between Cushing WTI and Louisiana Light Sweet oil.
Derivative Gains, Net
(in millions)
Three Months Ended December 31, 2014 | Twelve Months Ended December 31, 2014 | |||||||
Noncash changes in fair value: | ||||||||
Oil derivative gains | $ | 486 | $ | 514 | ||||
NGL derivative gains | 3 | 4 | ||||||
Gas derivative gains | 81 | 91 | ||||||
Marketing derivative gains | 3 | 3 | ||||||
Interest rate derivative losses | (3 | ) | (3 | ) | ||||
Total noncash derivative gains, net | 570 | 609 | ||||||
Net cash receipts (payments) on settled derivative instruments: | ||||||||
Oil derivative receipts | 117 | 104 | ||||||
NGL derivative receipts | 5 | 8 | ||||||
Gas derivative receipts (payments) | 2 | (27 | ) | |||||
Marketing derivative payments | (1 | ) | — | |||||
Interest rate derivative receipts | — | 18 | ||||||
Total cash receipts on settled derivative instruments, net | 123 | 103 | ||||||
Total derivative gains, net | $ | 693 | $ | 712 | ||||