Pioneer Natural Resources Reports Second Quarter 2015 Financial and Operating Results

DALLAS--()--Pioneer Natural Resources Company (NYSE:PXD) (“Pioneer” or “the Company”) today announced financial and operating results for the quarter ended June 30, 2015.

Pioneer reported a second quarter net loss attributable to common stockholders of $218 million, or $1.46 per diluted share. Without the effect of noncash derivative mark-to-market losses and other unusual items, adjusted income for the second quarter was $15 million after tax, or $0.10 per diluted share.

Second quarter and other recent highlights included:

  • producing 197 thousand barrels oil equivalent per day (MBOEPD) in the second quarter, of which 51% was oil; second quarter production reflected strong Spraberry/Wolfcamp production growth driven by Pioneer’s successful horizontal drilling program partially offset by lower-than-expected production in the Eagle Ford Shale and the West Panhandle field;
  • maintaining a production growth forecast for 2015 of 10%+, reflecting an increase in forecasted Spraberry/Wolfcamp production growth from 20%+ to 22% to 24% offset by a reduction in the full-year growth rate for the Eagle Ford Shale;
  • closing the sale of the Eagle Ford Shale Midstream business in July for $2.15 billion (gross); Pioneer received net sale proceeds of $530 million at the closing and will receive an additional $500 million in July 2016; Pioneer will also benefit from fee reductions under existing downstream processing and transportation contracts by approximately $100 million on a net present value (NPV) basis;
  • realizing significant service cost reductions and efficiency gains that have resulted in (i) a 20% to 25% decrease in drilling and completion costs compared to 2014, (ii) a 20% reduction in horizontal tank battery construction costs compared to 2014 and (iii) a 17% reduction in lease operating expenses per barrel oil equivalent (BOE) compared to 2014; the Company expects to achieve additional cost reductions and efficiency gains by early 2016, with drilling and completion costs and horizontal tank battery construction costs expected to decline by more than 30% and 25%, respectively, compared to 2014;
  • placing 28 horizontal wells on production during the second quarter in the northern Spraberry/Wolfcamp; early production results from 16 wells in the Wolfcamp B interval are on average tracking estimated ultimate recoveries (EURs) of more than 1 million barrels oil equivalent (MMBOE), with average 24-hour peak production rates of approximately 1,900 barrels oil equivalent per day (BOEPD) and 79% oil content; early production results from five wells placed on production (POP) in the Lower Spraberry Shale interval are on average tracking EURs of 1 MMBOE, with average 24-hour peak production rates of approximately 1,100 BOEPD and 81% oil content; seven of the horizontal wells (six Wolfcamp B interval and one Lower Spraberry Shale interval) benefited from completion optimization testing;
  • delivering an average EUR of 1 MMBOE from all Wolfcamp B and Wolfcamp A interval wells drilled in the northern Spraberry/Wolfcamp since 2013;
  • exporting 20 thousand barrels oil per day (MBOPD) gross (7 MBOPD net) of Eagle Ford Shale processed condensate in the second quarter under term contracts that significantly improved pricing compared to domestic condensate sales; also exported 6 MBOPD gross on a spot basis in June; and
  • continuing education efforts on the benefits of lifting the U.S. oil export ban.

Pioneer’s latest plans for 2015 include:

  • continuing to protect the Company’s cash flow through the use of commodity derivatives, including (i) maintaining coverage for 2015 forecasted oil production at approximately 90%, with most of the volumes protected by swaps at $71 per barrel, (ii) increasing coverage for 2016 forecasted oil production to approximately 75% using three-way collars and (iii) maintaining coverage for forecasted gas production of approximately 85% for 2015 and approximately 65% in 2016 using a combination of swaps and three-way collars to protect volumes in both years;
  • maintaining a strong balance sheet; net debt-to-book capitalization was 23% at the end of the second quarter and, with the closing of the Eagle Ford Shale Midstream sale in July, cash on hand at the end of July was approximately $700 million;
  • planning to add an average of two horizontal rigs per month in the northern Spraberry/Wolfcamp during the second half of 2015; four rigs have already been added; the Company is also planning to add eight horizontal rigs in the first quarter of 2016, of which six rigs will be added in the northern Spraberry/Wolfcamp and two rigs will be added in the Eagle Ford Shale; this rig ramp is expected to bring horizontal drilling activity back to the level it was at prior to the oil price collapse in late 2014;
  • delivering internal rates of return (IRRs) in the northern Spraberry/Wolfcamp and Eagle Ford Shale ranging from 45% to 60% at current strip commodity prices (includes capital costs for tank batteries and salt water disposal facilities); and
  • forecasting compound annual production growth of 15%+ (oil growth of 20%+) over the 2016 through 2018 period based on the Company’s planned increase in drilling activity; the increased drilling activity will have a minimal impact on 2015 production due to the time required to drill and complete multi-well pads.

Scott D. Sheffield, Chairman and CEO, stated, “Our horizontal drilling program in the Spraberry/Wolfcamp continues to generate strong margins and returns in a weak commodity price environment due to our aggressive pursuit of cost reductions and efficiency gains combined with our highly productive wells. As a result, we are putting rigs back to work and plan to return to an activity level during 2016 that can result in a similar growth trajectory that we were delivering in the second half of 2014 before the downturn. Our strong balance sheet, excellent returns and superior derivatives position through 2016 provide us the flexibility to adjust this rig ramp based on the Company’s commodity price outlook and continuing efficiency improvements.”

Mark-To-Market Derivative Losses and Unusual Items Included in Second Quarter 2015 Earnings

Pioneer’s second quarter earnings included noncash mark-to-market losses on derivatives of $222 million after tax, or $1.48 per diluted share.

Second quarter earnings also included a net loss of $11 million after tax, or $0.08 per diluted share, related to the following unusual items:

  • a restructuring charge of $10 million after tax, or $0.07 per diluted share, related to the closing of Pioneer’s Denver office and the streamlining of operations in the Raton Basin; and
  • a loss of $1 million after tax, or $0.01 per diluted share, related to discontinued operations.

Spraberry/Wolfcamp Operations Update and 2015 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. The Company believes it has greater than 10 billion barrels oil equivalent of net recoverable resource potential from horizontal drilling across its entire acreage position based on its extensive geologic data and successful drilling results to date.

In the northern Spraberry/Wolfcamp, the Company placed 28 horizontal wells on production during the second quarter. The majority of these wells were Wolfcamp B and Lower Spraberry Shale interval wells. Early production results from the 16 wells drilled in the Wolfcamp B interval are on average tracking EURs of more than 1 MMBOE. These wells delivered an average 24-hour peak production rate of approximately 1,900 BOEPD, with 79% oil content. Five Lower Spraberry Shale horizontal wells were also placed on production across the northern acreage during the second quarter. Early production results from these wells are on average tracking EURs of 1 MMBOE. These wells delivered an average peak production rate of approximately 1,100 BOEPD, with 81% oil content.

The remaining wells placed on production in the second quarter were in the Wolfcamp A interval (three wells), the Wolfcamp D interval (three wells) and the Middle Spraberry Shale interval (one well). On average, the Wolfcamp A interval wells are tracking EURs of 900 thousand barrels oil equivalent (MBOE), the Wolfcamp D interval wells are tracking EURs of 650 MBOE and the Middle Spraberry Shale interval well is tracking an EUR of 800 MBOE.

Six of the Wolfcamp B interval wells and one Lower Spraberry Shale interval well were the first seven wells of Pioneer’s current 25-well completion optimization program. This program includes optimizing stage length, clusters per stage, fluid volumes and proppant concentration. Early results from all seven wells are encouraging.

Pioneer has successfully placed 79 horizontal Wolfcamp B interval wells and 28 horizontal Wolfcamp A interval wells on production since it commenced drilling horizontal wells in this area in 2013. The average production from these wells is tracking a type curve that is expected to recover 1 MMBOE over the life of the well.

The Company commenced adding an average of two horizontal rigs per month in the northern Spraberry/Wolfcamp in July and plans to continue adding rigs at this pace through the first quarter of 2016. The drilling program in the northern Spraberry/Wolfcamp continues to deliver strong EURs and returns as a result of cost reductions, efficiencies and rock quality. Well productivity reflects EURs averaging approximately 1 MMBOE, with IRRs averaging 50% to 60% at current strip commodity prices. These returns include the cost for tank battery and salt water disposal facilities. The current cost to drill and complete a horizontal well is approximately $8.0 million to $8.5 million, assuming average lateral lengths of approximately 9,000 feet and a 20% to 25% cost reduction compared to 2014. A reduction of approximately 25 days in the average time between beginning to drill a well and placing it on production has contributed to the significant reduction in costs. This primarily reflects reduced drilling days resulting from rigs drilling one interval consistently and utilizing a modified three-string casing design. The 20% to 25% cost reduction has been partially offset by the higher costs associated with the larger completions that are now being used. Costs are expected to be reduced by more than 30% by early 2016 compared to 2014 levels as additional cost reductions and efficiency gains are achieved. Completion optimization, dissolvable plug technology testing and diversion technology testing are continuing. Pioneer expects its well costs in the northern Spraberry/Wolfcamp to decrease to $7.5 million to $8.0 million per well by early 2016.

Pioneer expects to place approximately 100 new horizontal wells on production in the northern Spraberry/Wolfcamp during 2015. Of these, 75% will be Wolfcamp B interval wells and the remainder will be split between Wolfcamp A, Wolfcamp D and Lower Spraberry Shale interval wells. Forty-three wells were placed on production during the first six months of 2015. The Company plans to spud approximately 100 new horizontal wells in 2015 in the northern Spraberry/Wolfcamp utilizing two-well and three-well pads. Approximately 80% of these new wells will be drilled in the Wolfcamp B interval and the remaining 20% in the Wolfcamp A and Lower Spraberry Shale intervals.

In the southern Wolfcamp joint venture area, Pioneer continues to operate four horizontal rigs. The drilling program in this area continues to deliver strong EURs and returns as a result of the Company’s cost reduction efforts, drilling and completion efficiency gains and drilling being focused in the northern part of the southern Wolfcamp joint venture area where the best rock quality is located.

Well performance reflects EURs averaging approximately 900 MBOE, with IRRs averaging 45% at current strip commodity prices. These returns exclude the carry that Pioneer is currently receiving from Sinochem, but include the cost of tank batteries and salt water disposal facilities. The current cost to drill and complete a horizontal well is approximately $7.5 million, assuming average lateral lengths of approximately 9,000 feet and a 20% to 25% cost reduction compared to 2014. Costs are expected to be reduced by more than 30% by early 2016 as additional cost reductions and efficiency gains are achieved. The joint venture drilling program is experiencing similar spud to POP time reductions and efficiency gains as the northern Spraberry/Wolfcamp. The Company expects its well costs in the southern Wolfcamp joint venture area to decrease to $6.5 million to $7.0 million per well by early 2016.

In the southern Wolfcamp joint venture area, Pioneer expects to place 75 to 80 horizontal wells on production during 2015. Of these, 75% will be Wolfcamp B interval wells. The remainder will be split between Wolfcamp A and Wolfcamp D interval wells. Fifty-eight wells were placed on production during the first six months of 2015. 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.

Total Spraberry/Wolfcamp production grew 7 MBOEPD in the second quarter to 119 MBOEPD, or 6%, compared to the first quarter of 2015, driven by the Company’s successful horizontal drilling program. Oil production grew 3 MBOEPD and represented 65% of total second quarter production. Gas and natural gas liquids (NGL) production increased 4 MBOEPD from the first quarter, benefitting from the improved recovery of field gas as a result of gathering system upgrades (e.g. field compression and line looping) and WTG’s (West Texas Gas) new Sale Ranch gas processing plant coming on-line. Fifty-five horizontal wells were placed on production during the second quarter. Horizontal production was 58 MBOEPD and vertical production was 61 MBOEPD. Second quarter production was negatively impacted by approximately 3 MBOEPD related to the Company’s continuing decision to reject ethane due to weak market conditions.

Production from the Spraberry/Wolfcamp is now forecasted to grow by 22% to 24% in 2015 compared to the 20%+ previously forecasted. This increase reflects the continuing strong performance of the horizontal drilling program, especially in Pioneer’s northern acreage. It also assumes that the Company will reject 3 MBOEPD of ethane over the remainder of 2015 due to continuing weak market conditions.

Spraberry/Wolfcamp Infrastructure Plans

Pioneer 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 and saltwater disposal facilities, construction of a field-wide water distribution system, construction of additional gas processing facilities and the expansion of the sand mine in Brady, Texas.

Pioneer’s large acreage position in the Spraberry/Wolfcamp field encompasses approximately 800,000 gross acres. Much of this acreage is contiguous, which allows for two 640-acre sections to be combined (1,280 acres) so that thirty 9,000-feet to 10,000-feet lateral wells can be drilled within these two sections assuming four intervals are drilled. The Company’s preferred optimized development approach is to combine four contiguous north-to-south 640-acre sections (2,560 acres) and drill 60 wells using three-well pads placed in the middle of the four sections (30 wells are drilled in a northerly direction and 30 wells are drilled in a southerly direction). The utilization of new centralized larger-scale tank batteries and saltwater disposal facilities enables this optimized field development. Approximately 75% of Pioneer’s acreage can be developed using this optimized approach. While the construction of these larger-scale facilities results in front-end loaded capital spending (approximately $10 million for the first six wells), it minimizes the facilities cost per well as future expansions take place. The total facilities cost for the 60 wells is approximately $25 million, or approximately $400 thousand per well on average. The tank battery and salt water facility costs represent approximately 5% of the total development costs for 60 wells.

Drilling activity on the XBC Giddings Estate in the southern Wolfcamp joint venture area provides a good example of this optimized field development using centralized facilities. A centralized tank battery and salt water disposal facility was constructed in early 2014 to ultimately handle 60 long-lateral wells running north and south. The facility was designed to initially handle six wells (on two 3-well pads) at a cost of approximately $10 million gross to the joint venture. Over the past year, 14 wells have been added to this facility at an average gross cost of approximately $300 thousand per well. An additional 12 wells are expected to be connected by the end of 2015 at an average gross cost of approximately $300 thousand per well, bringing the total to 32 wells connected in less than two years, or approximately 50% of total anticipated connections for this facility. The remaining 28 wells are expected to be connected over the next several years at an average gross cost of $300 thousand per well. The total gross cost for the facility is projected to be approximately $25 million, or an average of $400 thousand per well.

The Company has compared the use of centralized tank batteries and salt water disposal facilities to support its horizontal pad drilling program to other alternatives such as single-well pad drilling utilizing individual tank batteries and smaller salt water disposal systems. In all cases, utilizing centralized facilities and drilling three-well pads maximizes the NPV of drilling 60 horizontal wells over four contiguous north-to-south sections. In the comparison of three-well pad drilling with single-well pad drilling, the NPV benefit of using three-well pad drilling at a $60 per barrel oil price and a $3.00 per thousand cubic feet (MCF) gas price is $40 million ($280 million compared to $240 million). The possibility also exists that not all 60 wells could be drilled using the single-well pad approach due to surface limitations that would arise as a result of the extra facilities that are needed compared to the three-well pad drilling approach. If 10 well locations were lost, the NPV benefit of using the three-well pad approach would increase to $80 million. Besides benefitting from accelerated production associated with using three-well pads compared to single-well pads, the utilization of centralized, scalable facilities also results in lower capital requirements for the build-out of the facility ($25 million compared to $31 million). The utilization of three-well pad drilling also results in less shut-in production than developing the four sections using single-well pads.

Forecasted spending for the construction of tank batteries and salt water disposal facilities reflects a combination of building new facilities and expanding existing facilities. The Company expects to spend $155 million in 2015 for horizontal tank batteries and salt water disposal facilities in the northern Spraberry/Wolfcamp and the southern Wolfcamp joint venture areas. This amount is net of the carry that Pioneer currently receives from Sinochem. The spending level for these facilities is expected to increase to $250 million to $350 million per year as drilling activity increases and the carry that Pioneer receives from Sinochem is fully utilized (expected to be mid-2016).

Pioneer owns a 27% interest in Targa Resources’ (“Targa”) 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 hookup of Pioneer’s new horizontal wells and (iii) provide the Company with opportunities to benefit from third-party processing revenues. The $70 million that is being spent in 2015 includes the initial construction costs for Targa’s new 200 million cubic feet per day (MMCFPD) gas processing plant in Martin County (Buffalo plant). It also includes gathering system upgrades (e.g. field compression and line looping) and new connections. The system upgrades are resulting in the improved recovery of field gas that results in higher gas and NGL sales volumes. Spending in 2016 is expected to be similar to 2015, including capital to complete the Buffalo plant. Timing of the new plant will be dependent on volume growth. No new plants are expected to be required after the Buffalo plant is completed until there is a significant increase in the Midland Basin rig count.

The Company’s long-term plans call for the construction of 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 system is expected to be built out in phases based on the timing of adding new rigs and the economics associated with adding new water sources. The initial phase of the build-out in 2015 includes engineering, right-of-way acquisition, pipeline installation and connecting a third-party Santa Rosa brackish water source at a cost of approximately $70 million. The second phase will commence in the second half of 2015 and be completed in 2016. It includes the construction of a delivery line for 100 thousand barrels per day of effluent water that will be purchased from the City of Odessa. The line is targeted for completion by the end of 2015. Several subsystems and frac ponds to efficiently distribute the Odessa water to Pioneer drilling locations in Midland County will also be constructed and are targeted for completion during 2016. The total cost of the distribution system for the Odessa water supply is expected to be approximately $100 million, of which $60 million will be spent in 2015 and $40 million in 2016. Savings from this project include (i) purchasing water from Odessa at a significantly lower cost per barrel than third-party alternatives and (ii) constructing permanent subsystems and frac ponds instead of utilizing trucking and more expensive rental equipment. In aggregate, the distribution system will reduce water purchase and handling costs by $500 thousand per well and will have a payout of less than two years.

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. Engineering work and site preparation for the expansion of the mine from 750 thousand tons to 2.1 million tons was completed during the first half of 2015 at a cost of approximately $25 million. The timing for completing the expansion, which is expected to cost approximately $75 million, is not expected any earlier than 2017 and will depend on the timing of future horizontal rig additions by Pioneer beyond the 28 rigs planned to be in place in the first quarter of 2016.

Eagle Ford Shale Operations Update and 2015 Outlook

In the liquids-rich area of the Eagle Ford Shale play in South Texas, Pioneer’s horizontal rig count was reduced to six rigs in early 2015. Drilling activity is focused in 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. The Company has also been successfully implementing a downspacing and staggering program focused on drilling Upper targets in combination with Lower targets. 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 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 in the Eagle Ford Shale has been reduced to approximately $6.5 million, reflecting an average lateral length of 5,000 feet and a 20% cost reduction compared to 2014. A reduction in excess of 25% compared to 2014 is expected by year end as additional cost reduction initiatives and efficiencies are realized, which will reduce the well cost to approximately $6.0 million and generate IRRs averaging 60% at current strip commodity prices.

Pioneer’s second quarter production from the Eagle Ford Shale averaged 46 MBOEPD, of which 40% was condensate. Production for the second quarter was approximately 3 MBOEPD below the Company’s forecast for the quarter. The Company expected to place 42 wells on production in the Eagle Ford Shale during the second quarter. However, due to record rainfall and flooding in this area during the quarter, only 33 wells were placed on production in Karnes and DeWitt counties. Of this total, 16 wells were in Upper targets and 17 wells were in Lower targets. The reduced number of wells placed on production impacted second quarter production by approximately 2 MBOEPD.

Pioneer placed 15 Eagle Ford Shale wells on production in the Washburn Ranch lease (approximately 9,000 net acres) in LaSalle County during 2014. Due to a fire in May 2014 at the central gathering plant for this area, production from these wells was significantly curtailed until year end 2014. As a result of the fire, the production forecast that was developed for 2015 was based on limited production data and actual production for these 15 wells came in approximately 1 MBOEPD below the forecasted level in the second quarter. The Company has postponed any further drilling in this area until it has a better understanding of the well performance associated with these wells.

As a result of the delays in placing wells on production and performance issues during the first half of 2015, Eagle Ford Shale production is now forecasted to grow by 1% to 2% in 2015 compared to the previous forecast of 9%+. Ethane rejection of approximately 2 MBOEPD, which occurred during the first half of 2015, is expected during the second half of the year as a result of continuing weak market conditions.

West Panhandle Field

In the West Panhandle field, the Fain gas processing plant had a scheduled one-week turnaround in mid-May that actually lasted approximately four weeks before normal operations were restored. In addition, production was curtailed during part of the second quarter as a result of the record rainfall and flooding that occurred across Texas. The result of the extended turnaround and weather impacts was a production loss of approximately 1 MBOEPD for the second quarter.

2015 Capital Budget

As a result of Pioneer’s plan to increase its horizontal rig count in the northern Spraberry/Wolfcamp by an average of two rigs per month over the second half of 2015, the Company’s capital budget for 2015 has been increased from $1.85 billion to $2.2 billion (excludes acquisitions, asset retirement obligations, capitalized interest and geological and geophysical G&A). The budget includes $1.95 billion for drilling-related activities and $250 million 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 - $1.4 billion (includes $1,035 million for the horizontal drilling program, $20 million for the vertical drilling program, $275 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 $1.5 billion (assuming average 2015 estimated prices of $51.00 per barrel for oil and $2.90 per MCF for gas) and cash on the balance sheet.

Pioneer’s net debt at the end of the second quarter of 2015 was $2.5 billion, with net debt-to-book capitalization of 23%. The Company will continue to target net debt-to-operating cash flow below 1.5 and net debt-to-book capitalization below 35%.

Second Quarter 2015 Financial Review

Sales volumes for the second quarter of 2015 averaged 197 MBOEPD. Oil sales averaged 101 thousand barrels per day (MBPD), NGL sales averaged 37 MBPD and gas sales averaged 356 MMCFPD.

The average realized price for oil was $51.64 per barrel. The average realized price for NGLs was $14.03 per barrel, and the average realized price for gas was $2.37 per MCF. These prices exclude the effects of derivatives.

Production costs averaged $11.19 per BOE. Depreciation, depletion and amortization (DD&A) expense averaged $18.38 per BOE. Exploration and abandonment costs were $28 million, principally comprised of $10 million attributable to an unsuccessful exploration well in southeast Colorado (Black Fox prospect), $4 million for seismic data and $14 million for personnel costs. General and administrative expense totaled $83 million. Interest expense was $46 million, and other expense was $47 million (excluding unusual items), which included $28 million of stacked drilling rig charges.

Third Quarter 2015 Financial Outlook

The Company’s third quarter 2015 outlook for certain operating and financial items is provided below.

Production is forecasted to average 205 MBOEPD to 210 MBOEPD.

Production costs are expected to average $11.50 per BOE to $13.50 per BOE. The increase from the second quarter actual cost of $11.19 per BOE is primarily related to an increase to Pioneer’s Eagle Ford Shale production costs of approximately $3.00 per BOE as a result of the Eagle Ford Shale Midstream business sale (total impact on corporate production costs is expected to range from $0.75 per BOE to $1.00 per BOE). DD&A expense is expected to average $18.00 per BOE to $20.00 per BOE. Total exploration and abandonment expense is forecasted to be $25 million to $35 million.

General and administrative expense is expected to be $80 million to $85 million, interest expense is expected to be $45 million to $50 million and other expense is expected to be $45 million to $55 million. Other expense includes $20 million to $25 million for stacked drilling rig charges, but excludes approximately $10 million of additional restructuring charges to be recorded in the third quarter associated with the Denver office closing. 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 $45 million to $55 million and are primarily attributable to alternative minimum taxes that will be paid as a result of the Eagle Ford Shale Midstream sale.

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, August 5, 2015, at 9:00 a.m. Central Time, Pioneer will discuss its financial and operating results for the quarter ended June 30, 2015, with an accompanying presentation. Instructions for listening to the call and viewing the accompanying presentation are shown below.

Internet: www.pxd.com
Select “Investors,” then “Earnings & Webcasts” to listen to the discussion, view the presentation and see other related material.
Telephone: Dial (877) 879-6174 and confirmation code: 3672639 five minutes before the call. View the presentation via Pioneer’s internet address above.

A replay of the webcast will be archived on Pioneer’s website. A telephone replay will be available through August 30, 2015, by dialing (888) 203-1112 and confirmation code: 3672639.

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, the risks associated with the ownership and operation of the Company’s industrial sand mining and oilfield services businesses and acts of war or terrorism. These and other risks are described in Pioneer's 10-K and 10-Q Reports and other filings with the U.S. Securities and Exchange Commission (SEC). In addition, Pioneer may be subject to currently unforeseen risks that may have a materially adverse impact on it. Pioneer undertakes no duty to publicly update these statements except as required by law.

Cautionary Note to U.S. Investors --The SEC prohibits oil and gas companies, in their filings with the SEC, from disclosing estimates of oil or gas resources other than “reserves,” as that term is defined by the SEC. In this news release, Pioneer includes estimates of quantities of oil and gas using certain terms, such as “resource potential,” “net recoverable resource potential,” “estimated ultimate recovery,” “EUR,” “oil-in-place” or other descriptions of volumes of reserves, which terms include quantities of oil and gas that may not meet the SEC’s definitions of proved, probable and possible reserves, and which the SEC's guidelines strictly prohibit Pioneer from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being recovered by Pioneer.

U.S. investors are urged to consider closely the disclosures in the Company’s periodic filings with the SEC. Such filings are available from the Company at 5205 N. O'Connor Blvd., Suite 200, Irving, Texas 75039, Attention: Investor Relations, and the Company’s website at www.pxd.com. These filings also can be obtained from the SEC by calling 1-800-SEC-0330.

         
PIONEER NATURAL RESOURCES COMPANY
 
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions)
 

June 30,
2015

December 31,
2014

ASSETS
Current assets:
Cash and cash equivalents $ 219 $ 1,025
Accounts receivable, net 390 440
Income taxes receivable 22 23
Inventories 269 241
Prepaid expenses 16 15
Derivatives 354 578
Other   35   37
Total current assets   1,305   2,359
 
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting 16,539 15,821
Accumulated depletion, depreciation and amortization   (6,044)   (5,431)
Total property, plant and equipment   10,495   10,390
 
Goodwill 272 272
Other property and equipment, net 1,466 1,391
Investment in unconsolidated affiliate 277 239
Derivatives 89 181
Other assets, net   98   94
 
$ 14,002 $ 14,926
 
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable $ 829 $ 1,320
Interest payable 62 40
Income taxes payable 1
Deferred income taxes 81 161
Derivatives 3
Other   61   55
Total current liabilities   1,033   1,580
 
Long-term debt 2,672 2,665
Derivatives 1 2
Deferred income taxes 1,714 1,803
Other liabilities 274 287
Equity   8,308   8,589
 
$ 14,002 $ 14,926
 
         
PIONEER NATURAL RESOURCES COMPANY
 
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per share data)
 
Three Months Ended
June 30,
Six Months Ended
June 30,
2015     2014 2015     2014
Revenues and other income:
Oil and gas $ 596 $ 938 $ 1,113 $ 1,828
Sales of purchased oil and gas 236 205 339 353
Interest and other 11 3 17 7
Derivative gains (losses), net (197) (218) 44 (322)
Gain on disposition of assets, net   2   4   3   10
  648   932   1,516   1,876
Costs and expenses:
Oil and gas production 163 167 343 325
Production and ad valorem taxes 37 56 76 111
Depletion, depreciation and amortization 329 243 639 460
Purchased oil and gas 237 198 345 341
Impairment of oil and gas properties 138
Exploration and abandonments 28 28 54 59
General and administrative 83 82 165 163
Accretion of discount on asset retirement obligations 3 3 6 6
Interest 46 47 92 92
Other   62   21   110   36
  988   845   1,968   1,593
 
Income (loss) from continuing operations before income taxes (340) 87 (452) 283
Income tax benefit (provision)   123   (32)   160   (83)
Income (loss) from continuing operations (217) 55 (292) 200
Loss from discontinued operations, net of tax   (1)   (54)   (4)   (76)
Net income (loss) attributable to common stockholders $ (218) $ 1 $ (296) $ 124
 
Basic and diluted earnings per share attributable to common stockholders:
Income (loss) from continuing operations $ (1.45) $ 0.38 $ (1.95) $ 1.38
Loss from discontinued operations   (0.01)   (0.37)   (0.03)   (0.52)
Net income (loss) $ (1.46) $ 0.01 $ (1.98) $ 0.86
 
Basic and diluted weighted average shares outstanding   149   143   149   143
 
         
PIONEER NATURAL RESOURCES COMPANY
 
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
 
Three Months Ended
June 30,
Six Months Ended
June 30,
2015     2014 2015     2014
Cash flows from operating activities:
Net income (loss) $ (218) $ 1 $ (296) $ 124
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization 329 243 639 460
Impairment of oil and gas properties 138
Impairment of inventory and other property and equipment 3 4 9 4
Exploration expenses, including dry holes 10 3 15 10
Deferred income taxes (124) 26 (161) 65
Gain on disposition of assets, net (2) (4) (3) (10)
Accretion of discount on asset retirement obligations 3 3 6 6
Discontinued operations 77 (3) 179
Interest expense 4 5 9 9
Derivative related activity 347 212 312 298
Amortization of stock-based compensation 25 21 47 43
Other (6) 21 (6) 28
Change in operating assets and liabilities:
Accounts receivable, net (47) (22) 49 (59)
Income taxes receivable (7) 1 (2)
Inventories (10) 8 (44) (8)
Prepaid expenses 4 3 (1) 2
Other current assets (1) (1) (8) (4)
Accounts payable (25) 100 (275) 30
Interest payable 42 26 22
Income taxes payable (1) (8) (1) 1
Other current liabilities   (6)   7   (17)   7
Net cash provided by operating activities 327 718 432 1,183
Net cash used in investing activities (489) (477) (1,206) (1,103)
Net cash used in financing activities   (2)   (53)   (32)   (28)
Net increase (decrease) in cash and cash equivalents (164) 188 (806) 52
Cash and cash equivalents, beginning of period   383   257   1,025   393
Cash and cash equivalents, end of period $ 219 $ 445 $ 219 $ 445
 
         
PIONEER NATURAL RESOURCES COMPANY
 
UNAUDITED SUMMARY PRODUCTION AND PRICE DATA
 
Three Months Ended
June 30,
Six Months Ended
June 30,
2015     2014 2015     2014
Average Daily Sales Volumes:
Oil (Bbls) 100,569 79,780 99,567 79,188
Natural gas liquids ("NGL") (Bbls) 36,659 38,572 36,015 36,049
Gas (Mcf) 356,391 344,889 357,901 333,210
Total (BOE) 196,626 175,834 195,232 170,772
 
Average Prices:
Oil (per Bbl) $ 51.64 $ 95.87 $ 47.40 $ 94.15
NGL (per Bbl) $ 14.03 $ 30.24 $ 14.50 $ 31.43
Gas (per Mcf) $ 2.37 $ 4.33 $ 2.53 $ 4.53
Total (BOE) $ 33.32 $ 58.63 $ 31.50 $ 59.14
 

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 not be dilutive to loss per share; therefore, conversion into common stock is assumed not to occur.

The following table is a reconciliation of the Company's net income (loss) attributable to common stockholders to basic and diluted net income (loss) attributable to common stockholders for the three and six months ended June 30, 2015 and 2014:

         
Three Months Ended
June 30,
Six Months Ended
June 30,
2015     2014 2015     2014
(in millions)
 
Net income (loss) attributable to common stockholders $ (218) $ 1 $ (296) $ 124
Participating basic earnings         (1)
Basic and diluted net income (loss) attributable to common stockholders $ (218) $ 1 $ (296) $ 123
 

Basic and diluted weighted average common shares outstanding were 149 million for the three and six months ended June 30, 2015 and 143 million for the three and six months ended June 30, 2014.

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
June 30,
Six Months Ended
June 30,
2015     2014 2015     2014
 
Net income (loss) $ (218) $ 1 $ (296) $ 124
Depletion, depreciation and amortization 329 243 639 460
Exploration and abandonments 28 28 54 59
Impairment of oil and gas properties 138
Impairment of inventory and other property and equipment 3 4 9 4
Accretion of discount on asset retirement obligations 3 3 6 6
Interest expense 46 47 92 92
Income tax (benefit) provision (123) 32 (160) 83
Gain on disposition of assets, net (2) (4) (3) (10)
Loss from discontinued operations, net of tax 1 54 4 76
Derivative related activity 347 212 312 298
Amortization of stock-based compensation 25 21 47 43
Other   (6)   21   (6)   28
 
EBITDAX (a) 433 662 836 1,263
 
Cash interest expense (42) (42) (83) (83)
Current income tax provision   (1)   (6)   (1)   (18)
 
Discretionary cash flow (b) 390 614 752 1,162
 
Discontinued operations cash activity (1) 23 (7) 103
Cash exploration expense (18) (25) (39) (49)
Changes in operating assets and liabilities   (44)   106   (274)   (33)
Net cash provided by operating activities $ 327 $ 718 $ 432 $ 1,183
 

_____________

 
(a)   “EBITDAX” represents earnings before depletion, depreciation and amortization expense; exploration and abandonments; impairment of oil and gas properties; impairment of inventory and other property and equipment; accretion of discount on asset retirement obligations; interest expense; income taxes; net gain on the disposition of assets; loss from discontinued operations, net of tax; noncash derivative related activity; amortization of stock-based compensation and other 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 June 30, 2015, 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 $ (218) $ (1.46)

Noncash MTM derivative losses

  222   1.48

Adjusted income excluding noncash MTM derivative losses

4 0.02
 
Raton restructuring charges 10 0.07
Loss from discontinued operations   1   0.01
Adjusted income excluding noncash MTM derivative losses and unusual items $ 15 $ 0.10
 
         
PIONEER NATURAL RESOURCES COMPANY
 
SUPPLEMENTAL INFORMATION
 
Open Commodity Derivative Positions as of August 3, 2015
(Volumes are average daily amounts)
 
2015 Year Ending December 31,

Third
Quarter

   

Fourth
Quarter

2016     2017
 
Average Daily Oil Production Associated with Derivatives (Bbl):
Swap contracts:
Volume 82,000 82,000
NYMEX price $ 71.18 $ 71.18 $ $
Collar contracts with short puts (a):
Volume (a) 15,000 15,000 100,514 15,000
NYMEX price:
Ceiling $ 97.69 $ 97.69 $ 77.21 $ 73.01
Floor $ 82.97 $ 82.97 $ 66.92 $ 65.00
Short put $ 69.67 $ 69.67 $ 47.58 $ 55.00
Rollfactor swap contracts:
Volume 37,000 37,000
NYMEX roll price (b) $ 0.06 $ 0.06 $ $
Average Daily NGL Production Associated with Derivatives (Bbl):
Ethane swap contracts:
Volume 6,000 6,000 5,000
Index price $ 7.80 $ 7.80 $ 11.61 $
Propane swap contracts:
Volume 11,000 11,000 7,500
Index price $ 21.62 $ 21.62 $ 21.57 $
Average Daily Gas Production Associated with Derivatives (MMBtu):
Swap contracts:
Volume 20,000 20,000 70,000
NYMEX price $ 4.31 $ 4.31 $ 4.06 $
Collar contracts with short puts:
Volume 285,000 285,000 180,000
NYMEX price:
Ceiling $ 5.07 $ 5.07 $ 4.01 $
Floor $ 4.00 $ 4.00 $ 3.24 $
Short put $ 3.00 $ 3.00 $ 2.78 $
Basis swap contracts:
Gulf Coast index swap volume (c) 20,000 20,000 10,000
Price differential ($/MMBtu) $ $ $ $
Mid-Continent index swap volume (c) 95,000 95,000 15,000 45,000
Price differential ($/MMBtu) $ (0.24) $ (0.24) $ (0.32) $ (0.32)
Permian Basin index swap volume (c) 10,000 10,000
Price differential ($/MMBtu) $ (0.13) $ (0.13) $ $
Permian Basin index swap volume (d) 50,217 30,000
Price differential ($/MMBtu) $ 0.20 $ 0.19 $ $
 

_____________

 
(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 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.
(d) Represent swaps that fix the basis differentials between Permian Basin index prices and southern California index prices for Permian Basin gas forecasted for sale in southern California.
 

Interest rate derivatives. During the three months ended June 30, 2015, the Company terminated its interest rate derivative contracts for cash proceeds of $2 million.

Marketing and basis transfer derivatives. Periodically, the Company enters into buy and sell marketing arrangements to fulfill firm pipeline transportation commitments. Associated with these marketing arrangements, the Company may enter into index swaps to mitigate price risk. As of August 3, 2015, the Company had oil index swap contracts totaling 10,000 Bbl per day for the remainder of 2015 with a price differential of $2.99 per Bbl between Cushing WTI and Louisiana Light Sweet oil.

Derivative Gains (Losses), Net
(in millions)

The following table summarizes net derivative gains and losses that the Company has recorded in earnings for the three and six months ended June 30, 2015:

         

Three Months Ended
June 30, 2015

Six Months Ended
June 30, 2015

Noncash changes in fair value:
Oil derivative losses $ (338) $ (288)
NGL derivative gains 6 3
Gas derivative losses (32) (28)
Marketing derivative gains (losses) 4 (2)
Interest rate derivative gains   13   3
Total noncash derivative losses, net   (347)   (312)
 
Net cash receipts (payments) on settled derivative instruments:
Oil derivative receipts 118 299
NGL derivative receipts 3 2
Gas derivative receipts 30 56
Marketing derivative payments (3) (3)
Interest rate derivative receipts   2   2
Total cash derivative receipts, net   150   356
Total derivative gains (losses), net $ (197) $ 44

Contacts

Pioneer Natural Resources
Investors:
Frank Hopkins, 972-969-4065
or
Michael Bandy, 972-969-4513
or
Steven Cobb, 972-969-5679
or
Media and Public Affairs:
Tadd Owens, 972-969-5760
or
Robert Bobo, 972-969-4020

Contacts

Pioneer Natural Resources
Investors:
Frank Hopkins, 972-969-4065
or
Michael Bandy, 972-969-4513
or
Steven Cobb, 972-969-5679
or
Media and Public Affairs:
Tadd Owens, 972-969-5760
or
Robert Bobo, 972-969-4020