UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of
the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): February 13, 2013
PIONEER NATURAL RESOURCES COMPANY
(Exact name of registrant as specified in its charter)
Delaware | 1-13245 | 75-2702753 | ||
(State or other jurisdiction of incorporation) |
(Commission File Number) |
(I.R.S. Employer Identification No.) | ||
5205 N. OConnor Blvd., Suite 200, Irving, Texas | 75039 | |||
(Address of principal executive offices) | (Zip Code) |
Registrants telephone number, including area code: (972) 444-9001
Not applicable
(Former name or former address, if changed since last report)
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the Registrant under any of the following provisions:
¨ | Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) |
¨ | Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) |
¨ | Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) |
¨ | Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) |
Item 2.02. | Results of Operations and Financial Condition |
On February 13, 2013, Pioneer Natural Resources Company (the Company) issued the news release, with financial statements and schedules, that is attached hereto as Exhibit 99.1. In the news release, the Company announced its financial and operating results for the quarter ended December 31, 2012 and provided an operations update, the Companys financial and operational outlook and information regarding its 2013 capital budget.
Item 7.01. | Regulation FD Disclosure |
On February 14, 2013, at 9:00 a.m., Central Time, the Company will hold a conference call to discuss these financial results. The slide presentation that will accompany the call is attached hereto as Exhibit 99.2. The slide presentation can also be viewed at the Companys website, www.pxd.com, by first selecting Investors, then Investor Presentations.
Item 9.01. | Financial Statements and Exhibits |
(d) | Exhibits |
99.1 | | News Release, dated February 13, 2013, titled Pioneer Natural Resources Reports Fourth Quarter 2012 Financial and Operating Results and Announces 2013 Capital Budget. | ||
99.2 | | Presentation, dated February 14, 2013, titled Fourth Quarter 2012 EarningsFebruary 14, 2013. |
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
PIONEER NATURAL RESOURCES COMPANY | ||
By: | /s/ Frank W. Hall | |
Frank W. Hall | ||
Vice President and Chief Accounting Officer |
Dated: February 13, 2013
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EXHIBIT INDEX
PIONEER NATURAL RESOURCES COMPANY
EXHIBIT INDEX
Exhibit No. |
Description | |
99.1(a) | News Release, dated February 13, 2013, titled Pioneer Natural Resources Reports Fourth Quarter 2012 Financial and Operating Results and Announces 2013 Capital Budget. | |
99.2(a) | Presentation, dated February 14, 2013, titled Fourth Quarter 2012 EarningsFebruary 14, 2013. |
(a) | Furnished herewith. |
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Exhibit 99.1
News Release |
Pioneer Natural Resources Reports Fourth Quarter 2012
Financial and Operating Results and Announces 2013 Capital Budget
Dallas, Texas, February 13, 2013 Pioneer Natural Resources Company (NYSE:PXD) (Pioneer or the Company) today announced financial and operating results for the quarter ended December 31, 2012, and announced its 2013 capital budget.
Pioneer reported fourth quarter net income attributable to common stockholders of $29 million, or $0.22 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 $107 million after tax, or $0.83 per diluted share.
Fourth quarter and other recent highlights included:
| producing 165 thousand barrels oil equivalent per day (MBOEPD) in the fourth quarter, including Barnett Shale production (the Barnett Shale properties were reclassified from discontinued operations to continuing operations after the decision was made to discontinue efforts to divest of these properties), |
| producing 156 MBOEPD in the fourth quarter, excluding Barnett Shale production, which was in the middle of the Companys fourth quarter guidance range of 154 MBOEPD to 158 MBOEPD (fourth quarter guidance excluded Barnett Shale production since it was classified as discontinued operations when the fourth quarter guidance was provided), |
| producing 156 MBOEPD from continuing operations in 2012 (includes Barnett Shale production), an increase of 29% compared to 2011 and at the top end of Pioneers full-year 2012 guidance; the strong production growth in 2012 was driven by the Companys drilling programs in the Spraberry vertical, horizontal Wolfcamp Shale, Eagle Ford Shale and Barnett Shale Combo areas, |
| delivering 264% drillbit reserve replacement (161 million barrels oil equivalent) at a drillbit finding and development cost, excluding pricing revisions, of $17.72 per barrel oil equivalent (BOE), |
| placing on production Pioneers first horizontal Wolfcamp Shale well in the B interval in Midland County, Texas, (24-hour peak initial flow rate of 1,693 barrels oil equivalent per day (BOEPD) and peak 20-day average natural flow rate of 1,510 BOEPD with approximately 75% oil content), which demonstrates the prospectivity of Pioneers northern Wolfcamp/Spraberry acreage that encompasses more than 600,000 gross acres, |
| initiating a two-year $1.0 billion horizontal drilling appraisal program of Pioneers northern Wolfcamp/Spraberry acreage, of which $0.4 billion is included in the 2013 drilling budget of $2.75 billion and the remainder is expected to be spent in 2014, |
| forecasting annual production growth of 12% to 16% from 2012 to 2013, |
| targeting 13% to 18% compound annual production growth for 2013 to 2015, |
| signing a $1.74 billion horizontal Wolfcamp Shale joint interest agreement with Sinochem, which equates to $21,000 per acre for approximately 10% of Pioneers aggregate Wolfcamp/Spraberry gross acreage position, |
| continuing to deliver improving horizontal Wolfcamp Shale results in the joint interest area, including: |
| placing on production Pioneers first horizontal Wolfcamp Shale well with a 10,000-foot lateral in the Upper B interval in Reagan County (24-hour peak flow rate of 1,203 BOEPD and peak 20-day average flow rate of 1,022 BOEPD with approximately 80% oil content); |
| placing on production Pioneers first Wolfcamp Shale Lower B interval well and a successful Wolfcamp Shale A interval well in Reagan County (both currently producing above type curve expectations); |
| well performance from existing wells continuing to meet type curve expectations; and |
| achieving targeted year-end 2012 horizontal Wolfcamp Shale production exit rate of 5 MBOEPD; and |
| increasing the Companys estimated net resource potential from 6.7 billion barrels oil equivalent (BBOE) to greater than 8.0 BBOE, which includes 1.6 BBOE from the southern horizontal Wolfcamp Shale joint interest area and 3.0 BBOE from Pioneers northern Wolfcamp/Spraberry acreage. |
Scott Sheffield, Chairman and CEO, stated, Pioneer had another great year in 2012. We delivered strong production and reserve growth, while continuing to be among the top performers in our peer group in total shareholder return. Our extensive Midland Basin geologic analysis has identified multiple prospective horizontal targets throughout Pioneers extensive 900,000-acre Wolfcamp/Spraberry leasehold position with an aggregate estimated resource potential of more than 4.6 BBOE. During 2012, we focused on appraising and developing the southern 200,000 acres of the play. This culminated in the signing of the joint interest agreement with Sinochem that will allow horizontal development of the Wolfcamp Shale in this area to be accelerated. We were also able to begin drilling horizontal wells on our northern acreage to appraise the potential of the horizontal Wolfcamp Shale in this area. Early results are extremely encouraging, and we are initiating a $1 billion dollar appraisal program for 2013 and 2014 to confirm the estimated 3.0 BBOE of resource potential we believe exists in our northern acreage, which should add substantial net asset value to the Company.
Mark-To-Market Derivative Gains and Unusual Items Included in Fourth Quarter 2012 Earnings
Pioneers fourth quarter earnings included unrealized mark-to-market gains on derivatives of $14 million after tax, or $0.11 per diluted share.
Fourth quarter earnings also included a net charge of $92 million after tax, or $0.72 per diluted share, related to the following unusual items:
| a noncash impairment charge of $101 million after tax, or $0.78 per diluted share, to reduce the proved and unproved property basis of the Companys Barnett Shale assets in Texas that were previously held for sale, partially offset by |
| Alaska production tax credit recoveries of $9 million after tax, or $0.06 per diluted share. |
Operations Update and Drilling Program
Pioneers successful horizontal Wolfcamp Shale and Jo Mill drilling results in the Spraberry Trend Area field have led the Company to shift a significant portion of its 2013 drilling activity from vertical drilling to more capital efficient horizontal drilling. Pioneer is the largest acreage holder in the Spraberry Trend Area field, where the Company believes it has greater than 4.6 BBOE of estimated resource potential from horizontal drilling based on its extensive geologic data and its successful drilling results to date.
The Company recently signed an agreement with Sinochem to sell 40% of Pioneers interest in 207,000 net acres leased by the Company in the southern portion of the Spraberry Trend Area field for total consideration of $1.74 billion. At closing, Sinochem will pay $522 million in cash to Pioneer, before normal closing adjustments, and will pay the remaining $1.2 billion by carrying a portion of Pioneers share of future drilling and facilities costs. The transaction is estimated to close by June 1, 2013, subject to governmental and third-party approvals.
Under the agreement, Sinochem will acquire 82,800 net acres of leasehold held by Pioneer in the Wolfcamp horizon. Pioneer retains 60% of its interest in the Wolfcamp depths and deeper horizons, with Sinochem receiving 40% of Pioneers interest. Pioneer will continue as operator and will conduct all leasing, drilling, operations and marketing activities in the joint interest area. The joint interest area covers defined portions of Upton, Reagan, Irion, Crockett and Tom Green Counties in Texas. Pioneer retains its current working interests in all horizons shallower than the Wolfcamp horizon.
In addition to funding its own drilling obligations for the horizontal Wolfcamp Shale, Sinochem has agreed to fund 75% of Pioneers portion of drilling and facilities costs after closing until the $1.2 billion of drilling carry is fully utilized. At closing, Sinochem will pay its 40% share of net expenditures in the joint interest area from the December 1, 2012 effective date of the transaction to the closing date. Pioneer and Sinochem have agreed to a development plan which forecasts the drilling of 86 horizontal Wolfcamp Shale wells during 2013, increasing to 120 wells in 2014 and 165 wells in 2015.
Pioneer successfully drilled and completed 39 horizontal wells in the Wolfcamp Shale joint interest area during 2012, of which 26 wells were placed on production. Of the 26 wells on production, 22 wells were completed in the B interval and 4 wells were completed in the A interval. Pioneers net horizontal Wolfcamp Shale production in the joint interest area averaged 2 MBOEPD in 2012, with a year-end exit rate of 5 MBOEPD.
The thickness of the Wolfcamp B interval in the southern joint interest area provides the opportunity to complete two stacked laterals in the interval (referred to as Upper B interval and Lower B interval). The Company placed its first Lower B interval well on production in the fourth quarter, which had an initial 24-hour peak flow rate of 696 BOEPD. A Wolfcamp A interval well was also placed on production in the fourth quarter with initial 24-hour peak flow rate of 442 BOEPD. Both wells had an oil content of approximately 80% and continue to produce above the 575 thousand barrel oil equivalent (MBOE) average estimated ultimate recovery (EUR) type curve for horizontal Wolfcamp Shale wells in the southern joint interest area.
Pioneer also placed its first horizontal Wolfcamp Shale well with a 10,000-foot lateral on production during January 2013. It had an initial peak 24-hour production rate of 1,203 BOEPD and an average peak 20-day flow rate of 1,022 BOEPD. The oil content of this well is approximately 80%. The performance of this well is substantially above the 650 MBOE EUR type curve that reflects the performance of the two horizontal Wolfcamp Shale B interval wells that were drilled in the Giddings area of Upton County by Pioneer in 2011.
Pioneer expects to run 7 rigs in the southern joint interest area during 2013, with an increase of 3 rigs per year expected in 2014 and 2015. The 2013 drilling program will continue to focus on delineating acreage and testing the Wolfcamp A, Upper B, Lower B and D intervals, while the program in 2014 and beyond will primarily focus on development drilling and accelerating production growth. Approximately 50% of the wells drilled in this area during 2013 will be from pads, increasing to approximately 75% in 2014. The Company has included $20 million in the 2013 southern joint interest area drilling budget for coring, open-hole logging, micro-seismic and 3-D seismic (science). The cost for drilling development wells is targeted at $7.5 million to $8.0 million for a 7,800-foot lateral well. The Company expects to continue testing laterals as long as 10,000 feet at an additional cost of approximately $1.5 million. Completion techniques will continue to be optimized and downspacing opportunities will be evaluated. In particular, slickwater fracture stimulations will be tested, which could save approximately $1.0 million per well when compared to gel-conveyed fracture stimulations.
During the fourth quarter of 2012, Pioneer completed two highly successful horizontal Jo Mill wells. The two wells had an average 24-hour initial production rate of 503 BOEPD with short laterals of approximately 2,500 feet. The peak 30-day rates for these two wells averaged 434 BOEPD, with approximately 80% oil content, and when normalized to 5,000 feet, the wells have outperformed the 650 MBOE EUR type curve since being placed on production.
Pioneers extensive Midland Basin geologic analysis, based upon data from thousands of wells, has identified multiple prospective horizontal targets with substantial oil in place throughout the Companys northern Wolfcamp/Spraberry acreage position of more than 600,000 gross acres. These horizontal targets include the Jo Mill interval and the Wolfcamp and Spraberry Shales. Prospectivity is defined by several geologic properties, including original oil in place, kerogen content, thermal maturity, porosity and brittle mineral fraction (increased fracability due to reduced clay content). The depth of the targets is also important as reservoir pressure increases with depth. Pioneers northern Wolfcamp/Spraberry acreage is located in the deepest part of the Midland Basin, which should make this area very prospective for horizontal targets.
The Company is currently operating one horizontal rig focused on delineating its northern acreage position. The rig recently drilled the Companys first two horizontal Wolfcamp Shale wells in Midland County. The first well (DL Hutt C #1H) was completed in the Wolfcamp B interval and had a lateral length of 7,380 feet. It had an initial peak 24-hour production rate of 1,693 BOEPD and an average peak 20-day rate flowing naturally of 1,510 BOEPD. The oil content of this well is approximately 75%. The performance of this well is substantially above the 650 MBOE EUR type curve.
The second well in Midland County is scheduled to be completed in the Wolfcamp A interval later in February. The rig is now drilling the first of two horizontal Wolfcamp Shale delineation wells targeting the B interval in Martin County.
To accelerate the delineation and appraisal of the northern Wolfcamp/Spraberry acreage, the Company is initiating a $1 billion capital program over the next two years to confirm the estimated 3.0 BBOE of resource potential that the Company believes exists in its northern acreage, which has the potential to add substantial net asset value. The 2013 drilling program, which is expected to cost $400 million, is scheduled to ramp up to four rigs early in the second quarter and drill a total of 30 to 40 wells targeting six different stacked intervals. The six stacked intervals across the Companys 600,000 prospective gross acres equates to greater than 3 million prospective gross acres. Fifteen wells to 20 wells will be completed in the Wolfcamp A, B and D intervals. Another 15 wells to 20 wells will be completed in the Jo Mill, Middle Spraberry Shale and the Lower Spraberry Shale. The drilling cost for these wells is expected to range from $7.5 million per well to $8.5 million per well assuming 7,000-foot laterals. This cost excludes $80 million of estimated science and infrastructure costs. The 2013 horizontal drilling program is expected to deliver a year-end exit rate for horizontal production from the northern acreage ranging from 5 MBOEPD to 7 MBOEPD.
Pioneer expects to increase the rig count on its northern Wolfcamp/Spraberry acreage to 6 rigs to 8 rigs in 2014 and invest another $600 million to fund the remainder of the two-year appraisal program. The 2014 program may also include testing horizontal drilling in deeper intervals below the Wolfcamp Shale.
Pioneer reduced its vertical drilling program in the Spraberry field from 40 rigs in the first quarter of 2012 to 20 rigs at the end of the year as horizontal drilling activity increased. The Company drilled 132 vertical wells in the fourth quarter and 631 wells over the entire year. Over the second half of 2012, the number of vertical wells awaiting completion increased by 57 wells as the Company shifted its expenditures to more horizontal drilling.
Pioneer continued to successfully drill vertically to deeper intervals in the Spraberry field below the Wolfcamp interval during 2012 (vertical Wolfcamp 40-acre type curve EUR of 140 MBOE with typical 24-hour initial production (IP) rate of 90 BOEPD). Production from this deeper drilling has exceeded expectations and is the primary contributor to the production outperformance by this asset during 2012. The deeper drilling includes the Strawn, Atoka and Mississippian intervals. The original 2012 drilling program called for the Wolfcamp to be the deepest interval completed in approximately 50% of the wells, with the remaining 50% of the wells to be drilled deeper to intervals below the Wolfcamp interval. Approximately 65% of the wells drilled in 2012 were actually deepened below the Wolfcamp interval.
Pioneer placed 208 vertical commingled Strawn wells on production during 2012, with an average 24-hour IP rate of 145 BOEPD. Production data continues to support an incremental gross EUR per well from the Strawn interval of 30 MBOE. Pioneer estimates that 85% of its Spraberry acreage position is prospective for the Strawn interval, up from the previous estimate of 70%.
The Company placed 134 commingled vertical Atoka wells on production during 2012, with an average 24-hour IP rate of 180 BOEPD. Results from well tests continue to support an incremental gross EUR of 50 MBOE to 70 MBOE for wells completed in the Atoka interval. Pioneer continues to believe the Atoka interval is prospective in 40% to 50% of its Spraberry acreage position.
The Company also placed 55 commingled vertical wells on production through the Mississippian interval during 2012, with an average initial 24-hour IP rate of 140 BOEPD. Data from Mississippian wells drilled to date continues to support an incremental gross EUR per well of 15 MBOE to 40 MBOE from this interval. Pioneer continues to believe the Mississippian interval is prospective in 20% of its Spraberry acreage.
Fourth quarter production from the Spraberry field averaged 69 MBOEPD. This included production from the Strawn, Atoka and Mississippian intervals in vertical Spraberry wells and horizontal production from the Wolfcamp Shale and Jo Mill intervals. Fourth quarter production was negatively impacted by 1,700 BOEPD due to reduced ethane recoveries resulting from Spraberry gas processing facilities operating above capacity due to greater-than-anticipated industry production growth.
Spraberry production for 2012 averaged 66 MBOEPD, an increase of 46% compared to 2011. Horizontal production averaged 2 MBOEPD during 2012 and exited the year at 5 MBOEPD. For 2013, Spraberry production is forecasted to grow to 75 MBOEPD to 80 MBOEPD, an increase of 14% to 21% compared to 2012. This reflects the vertical rig count decreasing from an average of 32 rigs in 2012 to 15 rigs in 2013, while the horizontal rig count is expected to increase from an average of 3 rigs in 2012 to 11 rigs in 2013. This shift to more horizontal and less vertical drilling is in response to the capital efficiencies that Pioneer is gaining from drilling more horizontal wells. Pioneer expects horizontal production to increase from an average of 2 MBOEPD in 2012 to 11 MBOEPD to 14 MBOEPD in 2013. This forecast assumes that more than 4 MBOEPD of horizontal production on an annualized basis will be conveyed to Sinochem after the closing of the joint interest transaction which is assumed to occur on June 1, 2013.
Pioneers 2013 production forecast assumes that the inventory of vertical wells awaiting completion will be drawn down by 60 wells to 70 wells over the year. It also takes into account that the gas processing capacity shortfall in the Spraberry area will continue into the second quarter until the new Driver gas processing plant comes online in April and provides an additional 200 million cubic feet per day of processing capacity, thereby alleviating the current bottleneck that is impacting ethane recoveries. Pioneer estimates that the ongoing processing capacity limitations will continue to negatively impact ethane recoveries and will decrease the Companys first quarter production by 2 MBOEPD to 3 MBOEPD.
In the liquids-rich Eagle Ford Shale in South Texas, the Company drilled 30 wells in the fourth quarter and placed 37 wells on production. Pioneer increased its Eagle Ford Shale production from 29 MBOEPD in the third quarter of 2012 to 35 MBOEPD in the fourth quarter, achieving another record production level. Strong well performance continues to drive this growth. Full-year 2012 production averaged 28 MBOEPD. The Company expects 2013 production to range from 38 MBOEPD to 42 MBOEPD, an increase of 36% to 50% compared to 2012.
Pioneer expects to drill approximately 130 Eagle Ford Shale wells in 2013 at a cost of $7 million to $8 million per well. Essentially all of these wells will be liquids-rich wells, with minimal dry gas drilling expected during the year. Pioneers drilling operations in the Eagle Ford Shale continue to become more
efficient. The number of wells drilled from pads, as opposed to single-well locations, is expected to increase from 45% of the wells drilled in 2012 to 80% of the wells drilled in 2013, reflecting that most of Pioneers acreage is now held by production. Pad drilling saves $600 thousand to $700 thousand per well and will result in Pioneer being able to drill 130 wells with 10 rigs in 2013 compared to drilling essentially the same number of wells in 2012 with 12 rigs.
Pioneer has been using lower-cost white sand instead of ceramic proppant to fracture stimulate wells drilled in shallower areas of the field. The Company is now expanding the use of white sand proppant to deeper areas of the field to further define its performance limits. The Company tested 97 wells with white sand proppant in 2011 and 2012, with a savings of approximately $700 thousand per well. Early well performance has been similar to direct offset ceramic-stimulated wells. Pioneer is continuing to monitor the performance of these wells and expects that greater than 50% of its 2013 drilling program will use the lower-cost white sand proppant. The Company also expects to improve well performance, EURs and well economics by increasing the average lateral length of its wells from 5,700 feet in 2012 to 6,200 feet in 2013, which will add approximately $500 thousand to the cost of drilling and completing a well.
Eleven central gathering plants (CGPs) are now operational as part of the joint ventures Eagle Ford Shale midstream business. One additional CGP is scheduled to be on line by the end of 2013. Pioneers share of its Eagle Ford Shale joint venture midstream activities is conducted through a partially-owned, unconsolidated entity. Operating cash flow from the midstream business is expected to be able to fund ongoing midstream infrastructure build-out costs. Cash flow from the services provided by the midstream operations is not included in Pioneers forecasted operating cash flow.
In the liquids-rich Barnett Shale Combo play, Pioneer drilled 8 wells in the fourth quarter and placed 8 wells on production. Pioneer is operating one rig in the play but plans to increase to two rigs in the second quarter to hold acreage in the highest-return areas of the Companys 82 thousand net acreage position. These areas have been identified from drilling data and petrophysical and seismic analysis. Pioneer currently holds approximately 20% of its acreage position by production, or 16 thousand net acres, and expects to hold an additional 45 thousand net acres by production over the next three years with a two-rig drilling program.
Production in the fourth quarter for the Barnett Shale Combo play was 9 MBOEPD, up from 7 MBOEPD in the third quarter. The Company expects production to increase from an average of 7 MBOEPD in 2012 to 9 MBOEPD to 12 MBOEPD in 2013. Production is comprised of approximately 60% liquids (oil and natural gas liquids) and 40% gas.
On the North Slope of Alaska, Pioneer continues to operate one rig and drill development wells from its island drill site targeting the Nuiqsut and Torok intervals. The Companys fourth quarter production was four thousand barrels oil per day (BOPD). During the first quarter of 2012, the Company completed its first successful mechanically diverted fracture stimulation of a Nuiqsut interval well. Based on the success of this mechanically diverted fracture stimulation, the Company has drilled four more wells and is planning similar stimulations during the current winter drilling season. Three of these wells will be in the Nuiqsut interval and one will be in the Torok interval.
During the first quarter of 2012, the Company also drilled a successful onshore appraisal well to test the southern extent of the Torok interval. The production and subsurface data provided by this successful well supported the addition of 50 million barrels of oil to the resource potential of the Torok interval within Pioneers acreage. The well has been flow tested for the second time and produced at a facility-limited rate of 2,800 BOPD, significantly higher than the rates achieved in 2012. The well has been shut in until permanent onshore production facilities are constructed for which an onshore development FEED study is being progressed. Pioneer is currently drilling a second onshore Torok well to further appraise this interval.
2013 Capital Budget
Pioneers capital program for 2013 of $3.0 billion (excludes acquisitions, asset retirement obligations, capitalized interest and geological and geophysical G&A) includes $2.75 billion for drilling, $25 million for vertical integration, $70 million for the expansion of the Brady, Texas sand mine and $145 million for Pioneers new Midland office building and several new field buildings.
The following provides a breakdown of the drilling capital by asset:
| Northern Wolfcamp/Spraberry area$1,225 million (includes $400 million for the horizontal drilling program, $625 million for the vertical drilling program and $200 million for infrastructure additions and automation projects) |
| Southern Wolfcamp joint interest area$425 million |
| Eagle Ford Shale$575 million |
| Barnett Shale Combo$185 million |
| Alaska$190 million |
| Other$150 million, including land capital for existing assets |
The 2013 capital budget is expected to be funded from forecasted operating cash flow of $2.0 billion, assuming commodity prices of $85 per barrel for oil and $3.25 per thousand cubic feet (MCF) for gas, proceeds of $600 million from Pioneers joint interest transaction with Sinochem (includes reimbursement by Sinochem of capital expenditures less operating cash flow from the December 1, 2012 effective date to the estimated June 1, 2013 closing date) and $400 million from capital market activities.
Pioneers year-end 2012 net debt was $3.5 billion and net debt-to-book capitalization was 37%. The Company will continue to target a net debt-to-book capitalization below 35% and net debt-to-operating cash flow below 1.75 times.
Fourth Quarter 2012 Financial Review
The following financial results from continuing operations for the fourth quarter of 2012 include the Barnett Shale assets that were reclassified to continuing operations in the fourth quarter after the decision was made to discontinue efforts to divest of these properties.
Liquids and gas sales averaged 165 MBOEPD, consisting of oil sales averaging 67 thousand barrels per day (MBPD), natural gas liquids (NGL) sales averaging 32 MBPD and gas sales averaging 395 million cubic feet per day.
The average price for oil was $85.60 per barrel including $1.71 per barrel related to deferred revenue from volumetric production payments (VPPs) for which production was not recorded. The Companys remaining VPP expired on its own terms at the end of 2012. The average reported price for NGLs was $30.69 per barrel and the average reported price for gas was $3.20 per MCF.
Production costs from continuing operations averaged $14.62 per BOE. Depreciation, depletion and amortization (DD&A) expense averaged $14.54 per BOE. An impairment charge of $88 million was recorded to reduce the carrying value of the Barnett Shale proved properties to their estimated fair value as part of the reclassification of the assets to continuing operations. Exploration and abandonment costs were $89 million, principally comprised of $72 million associated with the impairment of unproved Barnett Shale acreage and $14 million for personnel costs. General and administrative expense totaled $68 million, including performance-based compensation awards for 2012. Interest expense was $54 million, and other expense was $27 million.
First Quarter 2013 Financial Outlook
The Companys first quarter 2013 outlook for certain operating and financial items is provided below.
Production is forecasted to average 165 MBOEPD to 170 MBOEPD. This forecast assumes that first quarter production will be negatively impacted by 2,000 BOEPD to 3,000 BOEPD as a result of continuing reduced ethane recoveries associated with gas processing facilities in the Spraberry field operating above capacity as described above. New gas processing capacity of 200 million cubic feet per day is expected to come on line during April and eliminate the reduced ethane recoveries thereafter. The guidance for the first quarter excludes the effects of potential ethane rejection to the extent the Company decides to do so in the future.
Production costs are expected to average $14.00 to $16.00 per BOE. DD&A expense is expected to average $13.50 to $15.50 per BOE. Total exploration and abandonment expense is forecasted to be $25 million to $35 million.
General and administrative expense is expected to be $60 million to $65 million, interest expense is expected to be $53 million to $58 million and other expense is expected to be $25 million to $35 million. Accretion of discount on asset retirement obligations is expected to be $2 million to $4 million.
Noncontrolling interest in consolidated subsidiaries income, excluding unrealized derivative mark-to-market adjustments, is expected to be $8 million to $11 million, primarily reflecting the public ownership in Pioneer Southwest Energy Partners L.P.
The Companys effective income tax rate is expected to range from 35% to 40%, based on current capital spending plans and the assumption of no significant unrealized derivative mark-to-market changes in the Companys derivative position. Current income taxes are expected to be $2 million to $7 million and are primarily attributable to state taxes.
The Companys financial and derivative mark-to-market results and open derivatives positions are outlined on the attached schedules.
Earnings Conference Call
On Thursday, February 14, 2013, at 9:00 a.m. Central Time, Pioneer will discuss its financial and operating results for the quarter ended December 31, 2012, and its 2013 capital budget, 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) 718-5108 confirmation code: 7431932 five minutes before the call. View the presentation via Pioneers internet address above.
A replay of the webcast will be archived on Pioneers website. A telephone replay will be available through March 11, 2013, by dialing (888) 203-1112 confirmation code: 7431932.
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 Pioneers 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 Pioneers 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, the receipt of approvals required to consummate the Companys Southern Wolfcamp joint venture transaction, litigation, the costs and results of drilling and operations, availability of equipment, services, resources and personnel required to complete the Companys operating activities, access to and availability of transportation, processing, fractionation and refining facilities, Pioneers ability to replace reserves, implement its business plans or complete its development activities as scheduled, access to and cost of capital, the financial strength of counterparties to Pioneers credit facility and derivative contracts and the purchasers of Pioneers oil, NGL and gas production, uncertainties about estimates of reserves and resource potential and the ability to add proved reserves in the future, the assumptions underlying production forecasts, quality of technical data, environmental and weather risks, including the possible impacts of climate change, the risks associated with the ownership and operation of an industrial sand mining business and acts of war or terrorism. These and other risks are described in Pioneers 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, estimated ultimate recovery, EUR or other descriptions of volumes of reserves, which terms include quantities of oil and gas that may not meet the SECs definitions of proved, probable and possible reserves, and which the SECs 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 Companys periodic filings with the SEC. Such filings are available from the Company at 5205 N. OConnor Blvd., Suite 200, Irving, Texas 75039, Attention: Investor Relations, and the Companys website at www.pxd.com. These filings also can be obtained from the SEC by calling 1-800-SEC-0330.
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 Companys Annual Report on Form 10-K for a general description of the concepts included in the SPEs 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 technical revisions of previous estimates, discoveries and extensions and improved recovery. 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 technical revisions of previous estimates, discoveries and extensions and improved recovery divided by annual production of oil, NGLs and gas, on a BOE basis.
Pioneer Natural Resources Contacts:
Investors
Frank Hopkins 972-969-4065
Eric Pregler 972-969-5756
Josh Jones 972-969-5822
Media and Public Affairs
Susan Spratlen 972-969-4018
Suzanne Hicks 972-969-4020
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands)
December 31, 2012 |
December 31, 2011 |
|||||||
ASSETS | ||||||||
Current assets: |
||||||||
Cash and cash equivalents |
$ | 229,396 | $ | 537,484 | ||||
Accounts receivable, net |
320,153 | 283,813 | ||||||
Income taxes receivable |
7,447 | 3 | ||||||
Inventories |
197,056 | 241,609 | ||||||
Prepaid expenses |
13,438 | 14,263 | ||||||
Discontinued operations held for sale |
| 73,349 | ||||||
Derivatives |
279,119 | 238,835 | ||||||
Other current assets, net |
3,746 | 12,936 | ||||||
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Total current assets |
1,050,355 | 1,402,292 | ||||||
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Property, plant and equipment, at cost: |
||||||||
Oil and gas properties, using the successful efforts method of accounting |
14,491,263 | 12,249,332 | ||||||
Accumulated depletion, depreciation and amortization |
(4,412,913 | ) | (3,648,465 | ) | ||||
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Total property, plant and equipment |
10,078,350 | 8,600,867 | ||||||
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Goodwill |
298,142 | 298,142 | ||||||
Other property and equipment, net |
1,217,694 | 573,075 | ||||||
Investment in unconsolidated affiliate |
204,129 | 169,532 | ||||||
Derivatives |
55,257 | 243,240 | ||||||
Other assets, net |
165,103 | 160,008 | ||||||
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$ | 13,069,030 | $ | 11,447,156 | |||||
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LIABILITIES AND EQUITY | ||||||||
Current liabilities: |
||||||||
Accounts payable |
$ | 826,877 | $ | 716,211 | ||||
Interest payable |
68,083 | 57,240 | ||||||
Income taxes payable |
208 | 9,788 | ||||||
Current deferred income taxes |
86,481 | 57,713 | ||||||
Discontinued operations held for sale |
| 75,901 | ||||||
Deferred revenue |
| 42,069 | ||||||
Derivatives |
13,416 | 74,415 | ||||||
Other current liabilities |
39,725 | 36,174 | ||||||
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Total current liabilities |
1,034,790 | 1,069,511 | ||||||
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Long-term debt |
3,721,193 | 2,528,905 | ||||||
Deferred income taxes |
2,140,416 | 1,942,446 | ||||||
Derivatives |
12,307 | 33,561 | ||||||
Other liabilities |
293,016 | 221,595 | ||||||
Equity |
5,867,308 | 5,651,138 | ||||||
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$ | 13,069,030 | $ | 11,447,156 | |||||
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PIONEER NATURAL RESOURCES COMPANY
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
Three Months Ended December 31, |
Twelve Months Ended December 31, |
|||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
Revenues and other income: |
||||||||||||||||
Oil and gas |
$ | 734,640 | $ | 664,776 | $ | 2,811,660 | $ | 2,294,063 | ||||||||
Interest and other |
(3,140 | ) | 19,962 | 28,310 | 66,880 | |||||||||||
Derivative gains, net |
86,683 | 6,634 | 330,251 | 392,752 | ||||||||||||
Hurricane activity, net |
| 36 | | 1,454 | ||||||||||||
Gain (loss) on disposition of assets, net |
503 | (2,205 | ) | 58,087 | (3,644 | ) | ||||||||||
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818,686 | 689,203 | 3,228,308 | 2,751,505 | |||||||||||||
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Costs and expenses: |
||||||||||||||||
Oil and gas production |
174,095 | 130,038 | 635,644 | 447,142 | ||||||||||||
Production and ad valorem taxes |
47,687 | 39,962 | 187,757 | 147,664 | ||||||||||||
Depletion, depreciation and amortization |
220,454 | 171,921 | 810,191 | 578,268 | ||||||||||||
Impairment of oil and gas properties |
87,709 | 354,408 | 532,589 | 354,408 | ||||||||||||
Exploration and abandonments |
88,787 | 64,078 | 206,291 | 121,320 | ||||||||||||
General and administrative |
67,691 | 55,347 | 248,282 | 193,215 | ||||||||||||
Accretion of discount on asset retirement obligations |
2,516 | 2,092 | 9,887 | 8,256 | ||||||||||||
Interest |
53,915 | 45,878 | 204,222 | 181,660 | ||||||||||||
Other |
27,119 | 16,195 | 113,388 | 63,166 | ||||||||||||
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|||||||||
769,973 | 879,919 | 2,948,251 | 2,095,099 | |||||||||||||
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Income (loss) from continuing operations before income taxes |
48,713 | (190,716 | ) | 280,057 | 656,406 | |||||||||||
Income tax benefit (provision) |
(9,153 | ) | 75,272 | (92,384 | ) | (197,644 | ) | |||||||||
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Income (loss) from continuing operations |
39,560 | (115,444 | ) | 187,673 | 458,762 | |||||||||||
Income from discontinued operations, net of tax |
142 | 2,256 | 55,149 | 423,152 | ||||||||||||
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|||||||||
Net income (loss) |
39,702 | (113,188 | ) | 242,822 | 881,914 | |||||||||||
Net (income) loss attributable to noncontrolling interests |
(10,868 | ) | 2,042 | (50,537 | ) | (47,425 | ) | |||||||||
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Net income (loss) attributable to common stockholders |
$ | 28,834 | $ | (111,146 | ) | $ | 192,285 | $ | 834,489 | |||||||
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Basic earnings per share: |
||||||||||||||||
Income (loss) from continuing operations attributable to common stockholders |
$ | 0.23 | $ | (0.95 | ) | $ | 1.10 | $ | 3.45 | |||||||
Income from discontinued operations attributable to common stockholders |
| 0.02 | 0.44 | 3.56 | ||||||||||||
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Net income (loss) attributable to common stockholders |
$ | 0.23 | $ | (0.93 | ) | $ | 1.54 | $ | 7.01 | |||||||
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Diluted earnings per share: |
||||||||||||||||
Income (loss) from continuing operations attributable to common stockholders |
$ | 0.22 | $ | (0.95 | ) | $ | 1.07 | $ | 3.39 | |||||||
Income from discontinued operations attributable to common stockholders |
| 0.02 | 0.43 | 3.49 | ||||||||||||
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Net income (loss) attributable to common stockholders |
$ | 0.22 | $ | (0.93 | ) | $ | 1.50 | $ | 6.88 | |||||||
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Weighted average shares outstanding: |
||||||||||||||||
Basic |
123,240 | 119,223 | 122,966 | 116,904 | ||||||||||||
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Diluted |
126,945 | 119,223 | 126,320 | 119,215 | ||||||||||||
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PIONEER NATURAL RESOURCES COMPANY
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
Three Months Ended December 31, |
Twelve Months Ended December 31, |
|||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
Cash flows from operating activities: |
||||||||||||||||
Net income (loss) |
$ | 39,702 | $ | (113,188 | ) | $ | 242,822 | $ | 881,914 | |||||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
||||||||||||||||
Depletion, depreciation and amortization |
220,454 | 171,921 | 810,191 | 578,268 | ||||||||||||
Impairment of oil and gas properties |
87,709 | 354,408 | 532,589 | 354,408 | ||||||||||||
Exploration expenses, including dry holes |
72,749 | 41,223 | 125,376 | 47,231 | ||||||||||||
Deferred income taxes |
9,279 | (76,423 | ) | 85,459 | 188,579 | |||||||||||
(Gain) loss on disposition of assets, net |
(503 | ) | 2,205 | (58,087 | ) | 3,644 | ||||||||||
Accretion of discount on asset retirement obligations |
2,516 | 2,092 | 9,887 | 8,256 | ||||||||||||
Discontinued operations |
(46 | ) | 9,436 | (19,344 | ) | (376,717 | ) | |||||||||
Interest expense |
8,751 | 8,071 | 35,563 | 31,483 | ||||||||||||
Derivative related activity |
(24,485 | ) | 47,847 | 68,604 | (221,899 | ) | ||||||||||
Amortization of stock-based compensation |
15,668 | 9,917 | 62,567 | 41,442 | ||||||||||||
Amortization of deferred revenue |
(10,575 | ) | (11,331 | ) | (42,069 | ) | (44,951 | ) | ||||||||
Other noncash items |
(18,600 | ) | 3,245 | (39,599 | ) | 6,725 | ||||||||||
Change in operating assets and liabilities, net of effects from acquisitions and dispositions: |
||||||||||||||||
Accounts receivable, net |
(20,260 | ) | (12,079 | ) | (28,206 | ) | (47,331 | ) | ||||||||
Income taxes receivable |
2,679 | 818 | (5,953 | ) | 29,406 | |||||||||||
Inventories |
39,406 | (21,440 | ) | 33,059 | (137,401 | ) | ||||||||||
Prepaid expenses |
8,219 | 4,143 | 1,447 | (3,415 | ) | |||||||||||
Other current assets |
6,393 | (6,563 | ) | 14,291 | 1,957 | |||||||||||
Accounts payable |
22,484 | 52,664 | 46,038 | 136,296 | ||||||||||||
Interest payable |
27,144 | 23,285 | 10,842 | (1,768 | ) | |||||||||||
Income taxes payable |
(14 | ) | (5,816 | ) | (9,580 | ) | (7,623 | ) | ||||||||
Other current liabilities |
(8,563 | ) | 15,241 | (38,320 | ) | 61,210 | ||||||||||
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Net cash provided by operating activities |
480,107 | 499,676 | 1,837,577 | 1,529,714 | ||||||||||||
Net cash used in investing activities |
(740,321 | ) | (705,934 | ) | (3,256,410 | ) | (1,560,787 | ) | ||||||||
Net cash provided by financing activities |
155,724 | 533,177 | 1,110,745 | 457,397 | ||||||||||||
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Net increase (decrease) in cash and cash equivalents |
(104,490 | ) | 326,919 | (308,088 | ) | 426,324 | ||||||||||
Cash and cash equivalents, beginning of period |
333,886 | 210,565 | 537,484 | 111,160 | ||||||||||||
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Cash and cash equivalents, end of period |
$ | 229,396 | $ | 537,484 | $ | 229,396 | $ | 537,484 | ||||||||
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PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUMMARY PRODUCTION AND PRICE DATA
Three Months Ended December 31, |
Twelve Months Ended December 31, |
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2012 | 2011 | 2012 | 2011 | |||||||||||||||
Average Daily Sales Volumes from Continuing Operations: |
||||||||||||||||||
Oil (Bbls) |
U.S. | 67,070 | 50,231 | 62,645 | 40,618 | |||||||||||||
Natural gas liquids (NGL) (Bbls) |
U.S. | 31,939 | 26,163 | 29,816 | 22,487 | |||||||||||||
Gas (Mcf) |
U.S. | 394,817 | 361,829 | 378,369 | 343,879 | |||||||||||||
Total (BOE) |
U.S. | 164,812 | 136,699 | 155,522 | 120,418 | |||||||||||||
Average Daily Sales Volumes from Discontinued Operations: |
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Oil (Bbls) |
South Africa | | 452 | 428 | 530 | |||||||||||||
Tunisia | | | | 547 | ||||||||||||||
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Total | | 452 | 428 | 1,077 | ||||||||||||||
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Gas (Mcf) |
South Africa | | 15,186 | 10,340 | 20,570 | |||||||||||||
Tunisia | | | | 496 | ||||||||||||||
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Total | | 15,186 | 10,340 | 21,066 | ||||||||||||||
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Total (BOE) |
South Africa | | 2,983 | 2,151 | 3,958 | |||||||||||||
Tunisia | | | | 630 | ||||||||||||||
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Total | | 2,983 | 2,151 | 4,588 | ||||||||||||||
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Average Reported Prices (a): |
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Oil (per Bbl) |
U.S. | $ | 85.60 | $ | 95.75 | $ | 90.89 | $ | 96.60 | |||||||||
NGL (per Bbl) |
U.S. | $ | 30.69 | $ | 45.70 | $ | 33.75 | $ | 46.27 | |||||||||
Gas (per Mcf) |
U.S. | $ | 3.20 | $ | 3.37 | $ | 2.60 | $ | 3.84 | |||||||||
Total (BOE) |
U.S. | $ | 48.45 | $ | 52.86 | $ | 49.40 | $ | 52.19 |
(a) | Average reported prices are attributable to continuing operations and include the results of hedging activities and amortization of VPP deferred revenue. |
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) provides that share- and unit-based awards with guaranteed dividend or distribution participation rights qualify as participating securities during their vesting periods. The Companys 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- and unit-based basic earnings (iii) divided by weighted average basic shares outstanding. The Companys 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 (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 Companys net income (loss) attributable to common stockholders to basic net income (loss) attributable to common stockholders and to diluted net income (loss) attributable to common stockholders for the three and twelve months ended December 31, 2012 and 2011:
Three Months Ended December 31, |
Twelve Months Ended December 31, |
|||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
(in thousands) | ||||||||||||||||
Net income (loss) attributable to common stockholders |
$ | 28,834 | $ | (111,146 | ) | $ | 192,285 | $ | 834,489 | |||||||
Participating basic earnings |
(516 | ) | (116 | ) | (3,029 | ) | (15,178 | ) | ||||||||
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Basic net income (loss) attributable to common stockholders |
28,318 | (111,262 | ) | 189,256 | 819,311 | |||||||||||
Reallocation of participating earnings |
24 | | 161 | 385 | ||||||||||||
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Diluted net income (loss) attributable to common stockholders |
$ | 28,342 | $ | (111,262 | ) | $ | 189,417 | $ | 819,696 | |||||||
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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, 2012 and 2011:
Three Months Ended December 31, |
Twelve Months Ended December 31, |
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2012 | 2011 | 2012 | 2011 | |||||||||||||
(in thousands) | ||||||||||||||||
Weighted average common shares outstanding: |
||||||||||||||||
Basic |
123,240 | 119,223 | 122,966 | 116,904 | ||||||||||||
Dilutive common stock options (a) |
143 | | 183 | 190 | ||||||||||||
Contingently issuable performance unit shares |
196 | | 180 | 424 | ||||||||||||
Convertible senior notes dilution |
3,366 | | 2,991 | 1,697 | ||||||||||||
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Diluted |
126,945 | 119,223 | 126,320 | 119,215 | ||||||||||||
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(a) | Options to purchase 98,819 shares and 129,918 shares of the Companys common stock were excluded from the diluted income per share calculations for the quarter and year ended December 31, 2012, respectively, because they would have been anti-dilutive to the calculation. |
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES
(in thousands)
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 companys 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 Companys 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, |
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2012 | 2011 | 2012 | 2011 | |||||||||||||
Net income (loss) |
$ | 39,702 | $ | (113,188 | ) | $ | 242,822 | $ | 881,914 | |||||||
Depletion, depreciation and amortization |
220,454 | 171,921 | 810,191 | 578,268 | ||||||||||||
Exploration and abandonments |
88,787 | 64,078 | 206,291 | 121,320 | ||||||||||||
Impairment of oil and gas properties |
87,709 | 354,408 | 532,589 | 354,408 | ||||||||||||
Hurricane activity, net |
| (36 | ) | | (1,454 | ) | ||||||||||
Accretion of discount on asset retirement obligations |
2,516 | 2,092 | 9,887 | 8,256 | ||||||||||||
Interest expense |
53,915 | 45,878 | 204,222 | 181,660 | ||||||||||||
Income tax (benefit) provision |
9,153 | (75,272 | ) | 92,384 | 197,644 | |||||||||||
(Gain) loss on disposition of assets, net |
(503 | ) | 2,205 | (58,087 | ) | 3,644 | ||||||||||
Income from discontinued operations |
(142 | ) | (2,256 | ) | (55,149 | ) | (423,152 | ) | ||||||||
Derivative related activity |
(24,485 | ) | 47,847 | 68,604 | (221,899 | ) | ||||||||||
Amortization of stock-based compensation |
15,668 | 9,917 | 62,567 | 41,442 | ||||||||||||
Amortization of deferred revenue |
(10,575 | ) | (11,331 | ) | (42,069 | ) | (44,951 | ) | ||||||||
Other noncash items |
(18,600 | ) | 3,245 | (39,599 | ) | 6,725 | ||||||||||
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EBITDAX (a) |
463,599 | 499,508 | 2,034,653 | 1,683,825 | ||||||||||||
Cash interest expense |
(45,164 | ) | (37,807 | ) | (168,659 | ) | (150,177 | ) | ||||||||
Current income tax benefit (provision) |
126 | (1,151 | ) | (6,925 | ) | (9,065 | ) | |||||||||
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Discretionary cash flow (b) |
418,561 | 460,550 | 1,859,069 | 1,524,583 | ||||||||||||
Cash hurricane activity |
| 36 | | 1,454 | ||||||||||||
Discontinued operations cash activity |
96 | 11,692 | 35,805 | 46,435 | ||||||||||||
Cash exploration expense |
(16,038 | ) | (22,855 | ) | (80,915 | ) | (74,089 | ) | ||||||||
Changes in operating assets and liabilities |
77,488 | 50,253 | 23,618 | 31,331 | ||||||||||||
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|
|
|
|
|
|
|
|||||||||
Net cash provided by operating activities |
$ | 480,107 | $ | 499,676 | $ | 1,837,577 | $ | 1,529,714 | ||||||||
|
|
|
|
|
|
|
|
(a) | EBITDAX represents earnings before depletion, depreciation and amortization expense; exploration and abandonments; impairment of oil and gas properties; net hurricane activity; accretion of discount on asset retirement obligations; interest expense; income taxes; net gain or loss on the disposition of assets, net; income from discontinued operations; noncash derivative related activity; amortization of stock-based compensation; amortization of deferred revenue and other noncash items. |
(b) | Discretionary cash flow equals cash flows from operating activities before changes in operating assets and liabilities and cash activity reflected in discontinued operations, hurricane activity and exploration expense. |
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES (continued)
(in thousands, except per share data)
Adjusted income excluding unrealized mark-to-market (MTM) derivative gains, and adjusted income excluding unrealized MTM derivative gains and unusual items, as presented in this press release, are presented and reconciled to Pioneers net income attributable to common stockholders and diluted common shares outstanding (determined in accordance with GAAP) because Pioneer believes that these non-GAAP financial measures reflect an additional way of viewing aspects of Pioneers 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 Pioneers 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 Pioneers consolidated financial statements prepared in accordance with GAAP. Unrealized 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 tables below reconcile Pioneers net income attributable to common stockholders and diluted shares outstanding for the three months ended December 31, 2012, as determined in accordance with GAAP, to income adjusted for unrealized MTM derivative gains and adjusted income excluding unrealized MTM derivative gains and unusual items for that quarter.
After-tax Amounts |
Amounts Per Share |
|||||||
Net income attributable to common stockholders |
$ | 28,834 | $ | 0.22 | ||||
Unrealized MTM derivative gains |
(13,835 | ) | (0.11 | ) | ||||
|
|
|
|
|||||
Income adjusted for unrealized MTM derivative gains |
14,999 | 0.11 | ||||||
Income from discontinued operations |
(142 | ) | | |||||
Impairment of Barnett shale assets previously held for sale |
100,511 | 0.78 | ||||||
Alaska petroleum production tax credit income |
(8,516 | ) | (0.06 | ) | ||||
|
|
|
|
|||||
Adjusted income excluding unrealized MTM derivative gains and unusual items |
$ | 106,852 | $ | 0.83 | ||||
|
|
|
|
PIONEER NATURAL RESOURCES COMPANY
SUPPLEMENTAL INFORMATION
Open Commodity Derivative Positions as of February 8, 2013
(Volumes are average daily amounts)
Twelve Months Ending December 31, | ||||||||||||
2013 | 2014 | 2015 | ||||||||||
Average Daily Oil Production Associated with Derivatives (Bbls): |
||||||||||||
Collar contracts with short puts: |
||||||||||||
Volume |
71,029 | 69,000 | 26,000 | |||||||||
NYMEX price: |
||||||||||||
Ceiling |
$ | 119.76 | $ | 114.05 | $ | 104.45 | ||||||
Floor |
$ | 92.27 | $ | 93.70 | $ | 95.00 | ||||||
Short put |
$ | 74.28 | $ | 77.61 | $ | 80.00 | ||||||
Swap contracts: |
||||||||||||
Volume |
3,000 | | | |||||||||
NYMEX price |
$ | 81.02 | $ | | $ | | ||||||
Rollfactor swap contracts: |
||||||||||||
Volume |
6,000 | 15,000 | | |||||||||
NYMEX roll price (a) |
$ | 0.43 | $ | 0.38 | $ | | ||||||
Basis swap contracts: |
||||||||||||
Midland-Cushing index swap volume |
2,055 | | | |||||||||
Price (b) |
$ | (5.75 | ) | $ | | $ | | |||||
Cushing-LLS index swap volume |
252 | | | |||||||||
Price (c) |
$ | (7.60 | ) | $ | | $ | | |||||
Average Daily NGL Production Associated with Derivatives (Bbls): |
||||||||||||
Collar contracts with short puts: |
||||||||||||
Volume |
1,064 | 1,000 | | |||||||||
Index price |
||||||||||||
Ceiling |
$ | 105.28 | $ | 109.50 | $ | | ||||||
Floor |
$ | 89.30 | $ | 95.00 | $ | | ||||||
Short put |
$ | 75.20 | $ | 80.00 | $ | | ||||||
Average Daily Gas Production Associated with Derivatives (MMBtu): |
||||||||||||
Collar contracts with short puts: |
||||||||||||
Volume |
| 25,000 | 225,000 | |||||||||
NYMEX price: |
||||||||||||
Ceiling |
$ | | $ | 4.70 | $ | 5.09 | ||||||
Floor |
$ | | $ | 4.00 | $ | 4.00 | ||||||
Short put |
$ | | $ | 3.00 | $ | 3.00 | ||||||
Collar contracts: |
||||||||||||
Volume |
150,000 | | | |||||||||
NYMEX price: |
||||||||||||
Ceiling |
$ | 6.25 | $ | | $ | | ||||||
Floor |
$ | 5.00 | $ | | $ | | ||||||
Swap contracts: |
||||||||||||
Volume |
162,500 | 105,000 | | |||||||||
NYMEX price (d) |
$ | 5.13 | $ | 4.03 | $ | | ||||||
Basis swap contracts: |
||||||||||||
Permian Basin index swap volume (e) |
52,500 | | | |||||||||
Price differential ($/MMBtu) |
$ | (0.23 | ) | $ | | $ | | |||||
Mid-Continent index swap volume (e) |
50,000 | 10,000 | | |||||||||
Price differential ($/MMBtu) |
$ | (0.30 | ) | $ | (0.19 | ) | $ | | ||||
Gulf Coast index swap volume (e) |
60,000 | | | |||||||||
Price differential ($/MMBtu) |
$ | (0.14 | ) | $ | | $ | |
(a) | Represent swaps that fix the difference between (i) each days 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 days price per Bbl of WTI for the first nearby month less (iv) the price per Bbl of WTI for the third nearby NYMEX month, multiplied by .3333. |
(b) | Represent swaps that fix the basis differential between Midland WTI and Cushing WTI. |
(c) | Represent swaps that fix the basis differential between Cushing WTI and Louisiana Light Sweet crude LLS. |
(d) | Represents the NYMEX Henry Hub index price on the derivative trade date. |
(e) | Represent swaps that fix the basis differentials between the indices price at which the Company sells its Permian Basin, Mid-Continent and Gulf Coast gas and the NYMEX Henry Hub index price used in gas swap and collar contracts. |
Interest rate derivatives. As of February 8, 2013, the Company had interest rate derivative contracts that lock in a fixed forward annual interest rate of 3.21 percent, for a 10-year period ending in December 2025, on a notional amount of $250 million. These derivative contracts mature and settle by their terms during December 2015.
Marketing and basis transfer derivatives. Periodically, the Company enters into gas buy and sell marketing arrangements to fulfill firm pipeline transportation commitments. Associated with these gas marketing arrangements, the Company may enter into gas index swaps to mitigate price risk. The following table presents Pioneers open marketing derivative positions as of February 8, 2013:
2013 | ||||||||
First Quarter | Second Quarter | |||||||
Average Daily Gas Production Associated with Marketing Derivatives (MMBtu): |
||||||||
Basis swap contracts: |
||||||||
Index swap volume |
40,000 | 8,242 | ||||||
Price differential ($/MMBtu) |
$ | 0.25 | $ | 0.35 |
Derivative Gains, Net
(in thousands)
Three Months Ended December 31, |
Twelve Months Ended December 31, |
|||||||
Noncash changes in fair value: |
||||||||
Oil derivative gains |
$ | 23,921 | $ | 217,765 | ||||
NGL derivative gains (losses) |
(3,886 | ) | 1,209 | |||||
Gas derivative gains (losses) |
2,553 | (290,058 | ) | |||||
Diesel derivative losses |
| (270 | ) | |||||
Marketing derivative gains (losses) |
88 | (22 | ) | |||||
Interest rate derivative gains |
1,809 | 5,930 | ||||||
|
|
|
|
|||||
Total noncash derivative gains (losses), net (a) |
24,485 | (65,446 | ) | |||||
|
|
|
|
|||||
Cash settled changes in fair value: |
||||||||
Oil derivative gains |
13,462 | 4,139 | ||||||
NGL derivative gains |
2,311 | 13,403 | ||||||
Gas derivative gains (b) |
46,578 | 402,981 | ||||||
Diesel derivative gains (b) |
| 3,497 | ||||||
Marketing derivative gains (losses) |
(153 | ) | 36 | |||||
Interest rate derivative losses (b) |
| (28,359 | ) | |||||
|
|
|
|
|||||
Total cash derivative gains, net |
62,198 | 395,697 | ||||||
|
|
|
|
|||||
Total derivative gains, net |
$ | 86,683 | $ | 330,251 | ||||
|
|
|
|
(a) | Total noncash derivative gains (losses), net includes $2.5 million and $16.2 million of net gains attributable to noncontrolling interests in consolidated subsidiaries during the three and twelve months ended December 31, 2012, respectively. |
(b) | During the twelve months ended December 31, 2012, the Company terminated (i) swap, collar, three-way and basis swap derivative contracts for 2014 and 2015 gas production, (ii) swap derivative contracts for 2013 diesel fuel and (iii) $200 million notional amount of interest rate derivative contracts. As a result of these transactions, the Company realized $116.4 million of net proceeds during the twelve months ended December 31, 2012. |
Fourth
Quarter 2012 Earnings February 14, 2013
Exhibit 99.2 |
2
Forward-Looking Statements
Except for historical information contained herein, the statements, charts and graphs in
this presentation 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 third parties on mutually acceptable terms, the receipt of
approvals required to consummate the Companys Southern Wolfcamp joint interest
transaction, litigation, the costs and results of drilling and operations,
availability of equipment, services, resources and personnel required to complete
the Company's operating activities, access to and availability of transportation,
processing, fractionation and refining facilities, Pioneer's ability to replace
reserves, implement its business plans or complete its development activities as scheduled,
access to and cost of capital, the financial strength of counterparties to Pioneer's
credit facility and derivative contracts and the purchasers of Pioneer's oil, NGL
and gas production, uncertainties about estimates of reserves and resource
potential and the ability to add proved reserves in the future,
the
assumptions
underlying
production
forecasts,
quality
of
technical
data,
environmental
and weather risks, including the possible impacts of climate change, the risks associated
with the ownership and operation of an industrial sand mining business and acts of
war or terrorism. These and other risks are described in Pioneer's 10-K
and 10-Q Reports and other filings with the Securities and Exchange
Commission. In addition, Pioneer may be subject to currently unforeseen risks that
may have a materially adverse impact on it. Pioneer undertakes no duty to publicly
update these statements except as required by law.
Please see the supplemental information slides included in this presentation for other
important information. |
3
Financial and Operating Highlights
Q4 2012 adjusted income
of $107 MM, or $0.83 per adjusted share
Q4 2012 production: 165 MBOEPD (including Barnett Shale production)
Q4 2012 production: 156 MBOEPD excluding Barnett Shale production
, mid-point of Q4 guidance range
(154 MBOEPD
158 MBOEPD)
FY 2012 production averaged 156 MBOEPD
(including Barnett Shale production), up 29%
vs. FY 2011 (+54% oil growth)
Top end of full-year guidance range
Strong growth primarily related to successful Spraberry vertical, horizontal Wolfcamp
Shale, Eagle Ford Shale and Barnett Shale Combo drilling programs
Delivered 264% drillbit reserve replacement (161 MMBOE) in 2012 at drillbit F&D cost
of $17.72 per BOE
4
Initiating $1 B horizontal drilling appraisal program of Pioneers northern
Wolfcamp/Spraberry acreage for 2013 and 2014
$0.4 B included in 2013 drilling budget of $2.75 billion; remainder expected to be
spent in 2014 Forecasting annual production growth of 12% to 16% from 2012 to
2013 Targeting 13% to 18% compound annual production growth for 2013 to 2015
1)
Adjusted income and the adjusted per share amount are non-GAAP financial
measures. See reconciliation in supplemental information slides 2)
Barnett Shale properties were moved to discontinued operations in Q3 in conjunction
with the divestment announcement; however, they were reclassified to continuing
operations in Q4 after electing to retain these properties 3)
Reflects South Africa as discontinued operations
4)
Excludes price revisions
1
1
2
2
3 |
4
Drilling Highlights
First
PXD
horizontal
Wolfcamp
Shale
well
(B
interval)
in
Midland
County
highly
successful;
demonstrates prospectivity of Pioneers northern Wolfcamp/Spraberry acreage
position (>600,000 gross acres)
Announced $1.74 B horizontal Wolfcamp Shale joint interest transaction with
Sinochem Horizontal
Wolfcamp
Shale
results
continuing
to
improve
in
joint
interest
area
Includes 1.6 BBOE from southern horizontal Wolfcamp Shale joint interest area and 3.0
BBOE from horizontal drilling in northern Wolfcamp/Spraberry acreage
Drilled first ~10,000-foot lateral horizontal Wolfcamp Shale well (Upper B
interval) in Reagan County o
24-hour IP rate of 1,203 BOEPD; peak 20-day average rate of 1,022 BOEPD; oil
content ~80%
Drilled first horizontal Wolfcamp Shale Lower B interval well and successful horizontal
Wolfcamp Shale A interval well in Reagan County; both currently above 575 MBOE
type curve
Well performance from existing wells continuing to meet type curve expectations
Achieved targeted year-end 2012 horizontal Wolfcamp Shale production exit rate of
~5 MBOEPD Increasing companywide net resource potential from 5.7 BBOE to >8
BBOE
24-hour
IP
rate
of
1,693
BOEPD;
peak
20-day
average
natural
flow
rate
of
1,510
BOEPD;
oil
content
~75%
25 miles
north
of
highly
successful
Giddings
horizontal
Wolfcamp
Shale
wells
Equates to ~$21,000 per acre on ~10% of Pioneers total Wolfcamp/Spraberry acreage
position |
$425 MM southern Wolfcamp joint interest area
2
$575 MM Eagle Ford Shale
$185 MM Barnett Shale Combo
$190 MM Alaska
$150
MM
Other
(includes
land
capital
for
existing assets)
$2.0 B operating cash flow
$0.6 B joint interest cash proceeds
$0.4 B capital markets
NYMEX Oil Price ($/Bbl)
2013 capital program based on
$85/Bbl oil and $3.25/MMBtu gas
Sensitivity to Commodity Prices ($ MM)
5
2013E Capital Spending and Cash Flow
1
1)
Capital spending excludes acquisitions, asset retirement obligations, capitalized
interest and G&G G&A 2)
Pioneer
incurs
100%
of
capital
costs
from
January
1
st
through
estimated
closing
date
of
June
1
st
;
Pioneer
will
be
reimbursed
by
Sinochem
for
40%
of
this amount as an adjustment at closing (not credited to cost incurred); Sinochem pays
40% of capital costs and carries Pioneer for 75% of Pioneers 60% of
capital costs post closing 1.00
2.00
3.00
4.00
5.00
6.00
60.00
70.00
80.00
90.00
100.00
110.00
120.00
2
$240 MM Other Capital
Capital program funded from:
Capital program of $3.0 B includes:
Drilling Capital: $2.75 B
$1,225 MM northern Wolfcamp/Spraberry area
$400 MM for horizontal program
$625 MM for vertical program
$200 MM for infrastructure & automation
$25 MM vertical integration
$70 MM sand mine expansion
$145 MM buildings, field offices and other |
High end
of 2013-2015 growth range assumes $100 oil / $3.75 gas; low end assumes $85 oil / $3.25 gas
6
Targeting 13% -
18% Compound
Annual
Production
Growth
for
2013
-
2015
MBOEPD
147
160
165
58%
Liquids
60%
Liquids
175 -
181
156 MBOEPD
(+29% vs. 2011)
1)
Assumes $85/Bbl oil price and $3.25/MMBtu gas price
2)
Excludes production attributable to the 40% joint interest transaction with Sinochem in
the southern Wolfcamp area assuming a June 1, 2013 closing 3)
Assumes
no
ethane
rejected
into
the
gas
stream
due
to
low
ethane
prices
3
Q1
Q2
Q3
Q4
2013E
2014E
2015E
Excludes annualized 4+ MBOEPD
conveyed
to
Sinochem
post
June
1
st
2,3
2012
151
3 |
Horizontal
Wolfcamp Shale Well Results Continue to Improve 7
650 MBOE Type Curve
Giddings Wells Average
(southern joint interest area;
2 wells, 5,300
laterals)
Days
University 10-1 #4H (southern joint interest area)
First ~10,000
lateral
24-hr IP of 1,203 BOEPD
Peak 20-day average rate of 1,022 BOEPD; ~80% oil
DL Hutt C #1H (Midland County)
First northern acreage horizontal, 7,380
lateral
24-hr IP natural flow rate of 1,693 BOEPD
Peak 20-day average natural flow rate of 1,510 BOEPD; ~75% oil
Giddings horizontal Wolfcamp Shale B interval wells drilled late
2011/early 2012 tracking 650 MBOE type curve
First
northern
acreage
well
in
Midland
County
and
first
10,000
lateral
well in Reagan County both substantially above 650 MBOE type curve
2,000
1,000
100
Artificial lift
commenced
0
30
60
90
120
150
180
210
240
270
300
330
360 |
Horizontal
Jo Mill Wells Outperforming 650 MBOE Type Curve 8
Days
2,000
1,000
100
650 MBOE Type Curve
Initial 2 horizontal Jo Mill wells drilled in Q4 2012
(average
production
normalized
to
5,000
lateral) |
Wolfcamp B
Interval Prospectivity Map 9
Tier 1
Tier 1
Tier 2
Tier 2
Pioneer Land
Pioneer Land
DL Hutt C #1H
24-hr IP: 1,693 BOEPD
Peak 20-day natural flow
rate: 1,510 BOEPD; ~75% oil
7,380
lateral length
First Martin County B well drilling
7,200
lateral length
Tier 1 is highest prospectivity
acreage, as determined by several
geologic properties, including:
Original oil in place (OOIP)
Kerogen content
Thermal maturity
Porosity
Brittle mineral fraction (fracability,
low clay content)
Vast majority of Pioneers
acreage position is in Tier 1
Reservoir pressure increases with
depth to the north and west
Numerous wells have proven Tier
2 acreage to be productive and
economic
2 Giddings Wells
Avg. 24-hr IP: 845 BOEPD
Avg. peak 20-day natural flow rate:
702 BOEPD: >75% oil
5,300
avg. lateral length
Third-party well
Peak IP: 892 BOEPD
~3,700
lateral length
Pioneer Wolfcamp B wells
Pioneer Wolfcamp B wells
Wolfcamp B depth contour
Wolfcamp B depth contour |
10
12/31/12 Proved Reserves: 1.1 BBOE
Additional Net Resource Potential: >8 BBOE
1)
All drilling locations shown on a gross basis
2)
SEC pricing of $94.84/Bbl for oil and $2.76/MMBtu for gas (NYMEX)
3)
Primarily reflects Alaska, Raton and South Texas
4)
Includes vertical well potential from Wolfcamp and deeper intervals
5)
Assumes average EUR of 500 MBOE per well, >600,000 gross acres, 140-acre
spacing, Wolfcamp A, B & D and Jo Mill intervals (excludes Spraberry Shale
interval potential) and 20% royalty 6)
Assumes average EUR of 575 MBOE per well, 5,600 locations, 207,000 net
acres , 140-acre spacing, laterals in all intervals (A, B, C & D),
25% royalty and Pioneers 60% share (reduced by ~1 BBOE associated with
joint interest transaction) Permian >7 BBOE
Significant Proved Reserves and Resource Potential
1
2
Proved Reserves + Estimated Net Resource Potential of >9 BBOE and >40,000
Drilling Locations |
11
Southern Wolfcamp Joint Interest Area Drilling Program
Currently running 7 rigs; expect to increase
to 10 rigs in 2014 and 13 rigs in 2015
Equates to 86 wells in 2013, 120 wells in 2014 and
165 wells in 2015
2013 drilling program continues to focus on
delineating acreage
Testing multiple Wolfcamp
intervals
(A, Upper B, Lower B and D)
Targeting $7.5 MM -
$8.0 MM gross development
well cost for 7,800
lateral
o
Testing laterals as long as 10,000; ~$1.5 MM additional cost
Expect 50% pad drilling
Optimizing completion techniques
o
Testing slickwater fracs; potential savings of ~$1.0 MM/well
Expect gross science costs of ~$20 MM
Drilling program for 2014 and beyond
primarily focused on development drilling
and accelerating production growth
Expect 75% pad drilling
Expect to evaluate downspacing opportunities
Noteworthy 24-hr IP rates in University Area
10-14 #6H
712 BOEPD; First Lower B well
10-1#4H
1,203 BOEPD; First 10,000
lateral well
10-13#6H
442 BOEPD; Successful A well
Joint Interest Area
(Wolfcamp and deeper intervals) |
Pioneers Highly Prospective Northern Wolfcamp/Spraberry Acreage
12
1 rig currently focused on delineating
northern acreage (>600,000 gross acres)
Drilled first two horizontal Wolfcamp Shale
wells in Midland County
~25 miles north of highly successful Giddings horizontal
Wolfcamp Shale wells
First well completed in B interval (DL Hutt C #1H)
Second well to be completed shortly in the A interval
Rig now drilling first of two Wolfcamp B
interval wells in Martin County
Pioneers extensive Midland Basin geologic
analysis, based upon data from thousands of
wells, has identified multiple prospective
horizontal targets with substantial oil in place
throughout Pioneers northern acreage
2013 northern Wolfcamp/Spraberry drilling
program accelerates appraisal and delineation
of these targets (Wolfcamp Shales, Jo Mill and
Spraberry Shales) with 4 rigs
Currently drilling first of
two wells in Martin County
Pioneers northern
Wolfcamp/Spraberry Acreage
First two Midland
County wells
First two Giddings wells
Joint Interest Area
(Wolfcamp and deeper intervals) |
13
Northern Wolfcamp/Spraberry Acreage
2013 Drilling Plan
Wolfcamp
A
Wolfcamp
B
Wolfcamp
D
Jo Mill
M. Spraberry
Shale
L. Spraberry
Shale
15 to 20 wells
15 to 20 wells
2013 northern Wolfcamp/Spraberry
acreage horizontal drilling program
Running 1 rig currently; ramping to 4 rigs
in Q2
Plan to drill a total of 30 to 40 wells
targeting 6 different intervals
Targeting $7.5 MM -
$8.5 MM well cost
for 7,000
laterals depending on depth
Excludes science and facilities capital
of ~$80 MM
U. Spraberry
M. Spraberry
Shale
L. Spraberry
Jo Mill
L. Spraberry
Shale
Dean
Wolfcamp A
Wolfcamp Lower B
Wolfcamp C1
Wolfcamp C2
Wolfcamp D
Strawn
Wolfcamp Upper B
Miss/Atoka |
14
Northern
Wolfcamp/Spraberry
Acreage
Initiating
$1
B
Appraisal
Program
2013 drilling program expected to cost ~$400 MM
Program expected to:
Appraise prospective acreage and confirm additional
resource potential across 6 stacked intervals on >600,000
gross acres; totals >3 MM gross acres
o
Resource potential in Wolfcamp A, B and D intervals and Jo Mill
interval across northern Wolfcamp/Spraberry acreage estimated
to be 3 BBOE
Deliver year-end 2013 horizontal production exit rate of
5 MBOEPD to 7 MBOEPD
Improve capital efficiency compared to vertical drilling
Expect to ramp up to 6 -
8 rigs during 2014 at a
cost of ~$600 MM
Continue appraisal program and commence development
drilling
May also test horizontal drilling in deeper intervals below
the Wolfcamp Shale
Spending $1 B over 2 years to confirm ~3 BBOE
of resource potential and add substantial NAV
2013 Appraisal Areas
Planned 2013 appraisal
areas; 6 intervals |
Spraberry
Vertical Drilling Program 15
Limestone Pay
Sandstone Pay
Non-Organic Shale Non-Pay
Organic Rich Shale Pay
Commingled Wells
Placed on
Production in 2012
2012 Average
24-hour IP (BOEPD)
Potential Incremental
EUR (MBOE)
Prospective PXD Acreage
Strawn
208
145
30
up from ~70% to ~85%
Atoka
134
180
50
70
40% -
50%
Mississippian
55
140
15
40
~20%
1)
Compares to average vertical well completed through the Lower Wolfcamp with an average
EUR of 140 MBOE and an average 24-hour IP of 90 BOEPD
Deeper drilling accounted for 65% of 2012 vertical drilling program; expected to
increase to 90% in 2013
Vertical rig count reduced during 2012 from 40 rigs in Q1 to 20 rigs at year-end as
horizontal activity increased
Drilled 132 vertical wells in Q4 and 631 wells in 2012
Built frac bank by 57 vertical wells over 2H 2012
2013 drilling program runs 15 vertical rigs and drills ~300 wells
Majority of rigs required to meet continuous drilling obligations
15 rigs to 20 rigs required to keep vertical production flat
Expect
to
draw
down
frac
bank
by
60
-
70
vertical
wells
during
2013
Dean
Deeper drilling provides potential to add up to 100 MBOE to vertical Wolfcamp well
1
1 |
Continuing to Successfully Grow Wolfcamp/Spraberry Production
16
Wolfcamp/Spraberry Net Production
1
(MBOEPD)
1) Includes production from Strawn, Atoka and Mississippian intervals in Spraberry
vertical wells and horizontal Wolfcamp Shale and Jo Mill wells 45
62
2012
64
69
69
75-80
66 MBOEPD
Q4 production flat compared to Q3 due to:
~1,700 BOEPD negative impact related to reduced
ethane recoveries resulting from Spraberry gas
processing facilities operating above capacity due
to greater-than-anticipated industry production
growth
Vertical wells awaiting completion increased by 57
wells during 2H
Reduced ethane recoveries expected to
continue into Q2 2013 until new Driver
plant comes online in April providing
additional capacity of 200 MMCFPD
Negative impact to Pioneers Q1 production
expected to be 2,000 BOEPD to 3,000 BOEPD
Vertical rig count decreasing from average
of 32 rigs in 2012 to 15 rigs in 2013
Horizontal rig count increasing from
average of 3 rigs in 2012 to 11 rigs in 2013
Expect horizontal production to increase
from an average of 2 MBOEPD in 2012 to
11 MBOEPD to 14 MBOEPD in 2013
2
2,3
Top end of original FY guidance
range (63 MBOEPD
67 MBOEPD)
Horizontal production
exit rate: ~5 MBOEPD
2) Production
reduced
after
June
1
st
to
reflect
the
divested
volumes
associated
with
the
southern
Wolfcamp
joint
interest
transaction
3) Assumes no ethane rejected into the gas stream due to low ethane prices
|
Eagle
Ford Shale Operational Update 17
Drilled 30 wells in Q4 2012; 37 wells placed on production
2013 drilling program
Expanding use of white sand proppant to deeper areas to further
define its performance limits (>50% of 2013 program)
~97 wells stimulated using white sand in 2011 and 2012; early well
performance similar to direct offset ceramic-stimulated wells
Reduces frac cost by ~$700 M
Expect to increase lateral length from 5,700
in 2012 to 6,200
in
2013; increases cost by $500 M per well
Well cost: $7 MM to $8 MM
11 CGPs on line; adding 12
by end of 2013
th
Expect to drill ~130 wells
Drilling essentially all liquids-rich wells ~80% pad
drilling, up from 45% in 2012; saves $600 M to $700 M per well and allows
130 wells to be drilled with 10 rigs vs. 12 rigs last year |
Eagle
Ford Shale Continues to Set New Production Records 18
Eagle Ford Shale Net Production
(MBOEPD)
12
1)
Reflects Pioneers ~35% share of total gross production
2)
Assumes
no
ethane
rejected
into
the
gas
stream
due
to
low
ethane
prices
28 MBOEPD
2012
Top end of original FY guidance
range (25 MBOEPD
29 MBOEPD)
2
2011
Q1
Q2
Q3
Q4
2013E
1
38 -
42
35
29
24
23 |
Continuing to Grow Barnett Shale Combo Production
19
Barnett Shale Net Production
(MBOEPD)
4
6
2012
7
9 -
12
7
9
7 MBOEPD
Drilled 8 wells in Q4; 8 wells placed on
production
Expect to increase rig count from 1 rig to 2
rigs in Q2 2013 to hold high-graded acreage
~20% of 82,000 net acreage position currently HBP
Drilling data and petrophysical and seismic analysis
have identified highest-return areas across Pioneers
acreage (reflects ~45,000 net acres of remaining
~65,000 non-HBP net acres)
Increase in drilling efficiencies requires fewer rigs to
hold acreage
2-rig drilling program required to hold the higher-
return acreage over next 3 years
Well cost for 5,000
lateral: ~$3 MM
Gross EUR: ~400 MBOE (16% oil, 42% NGLs, 42% gas)
1)
Assumes
no
ethane
rejected
into
the
gas
stream
due
to
low
ethane
prices
1 |
20
Alaska
Q4 net production: ~4 MBOPD
1-rig development program
continues from the Oooguruk island
drill site targeting Nuiqsut and Torok
intervals
Following first successful mechanically
diverted frac on a Nuiqsut well in 2012,
planning similar fracs for 1 Torok and 3
Nuiqsut wells during Q1
2
onshore
Torok
appraisal
well
being drilled
Will be completed with mechanically
diverted frac
Initial onshore Torok well added 50 MMBO
resource potential in 2012; currently
being flow tested and is producing at a
facility-limited rate of 2,800 BOPD gross
Progressing onshore development FEED
study for Torok production
PXD Acreage
Island
Development
Area
Island drill site
(Oooguruk)
Torok Area
1 well to be
fracd from island
drill site and 1
well to be fracd
from onshore drill
site
Nuiqsut Area
3 wells to be fracd
from island drill site
Nuiqsut Wells
Torok Wells
nd
Second onshore
Torok appraisal well
Torok onshore
drill site |
Net
income attributable to common stockholders 29
0.22
Unrealized mark-to-market (MTM) derivative gains ($22 MM before tax)
(14)
(0.11)
Adjusted income excluding unrealized MTM derivative gains
15
0.11
Unusual items included in adjusted income:
Impairment of Barnett Shale assets previously held for sale ($160 MM before tax)
101
0.78
Alaska Petroleum Production Tax credit income ($14 MM before tax)
(9)
(0.06)
Adjusted income excluding unrealized MTM derivative gains and unusual items
107
0.83
21
Q4 2012 Earnings Summary
$ Per Share
$ Millions
(After Tax)
Guidance
Q4 2012 Results Excluding
Unrealized MTM Derivative
Gains, Unusual Items and
Barnett Shale Activity
Q4 2012 Results from
Continuing Operations
Daily Production
(MBOEPD)
154
158
156
165
Production Costs Including Taxes ($/BOE)
$14.50 -
$16.50
$ 14.48
$ 14.62
Exploration & Abandonment
($ MM)
$25 -
$35
$ 16
$ 89
DD&A ($/BOE)
$13.50 -
$15.50
$ 14.63
$ 14.54
G&A
4
($ MM)
$60 -
$65
$ 68
$ 68
Interest Expense ($ MM)
$53 -
$58
$ 54
$ 54
Other Expense ($ MM)
$25 -
$35
$ 27
$ 27
Accretion of Discount on ARO ($ MM)
$2 -
$4
$ 2
$ 3
Noncontrolling Interest ($ MM)
$8 -
$11
$ 8
5
$ 11
Current Income Taxes /(Benefits) ($ MM)
$2 -
$7
-
-
Effective Tax Rate
6
(%)
35% -
40%
34%
24%
Q4 2012 Guidance vs. Results
1)
Non-GAAP financial measure. See reconciliation in supplemental information
slides 2)
3)
Exploration and abandonments in continuing operations included $72 MM of unproved
impairments on Barnett Shale assets (included in unusual items above) 4)
Includes additional performance-related compensation
5)
Excludes unrealized MTM derivative gains attributable to noncontrolling interest of $ 3
MM in Q4 2012 6)
Excludes income attributable to noncontrolling interest of $ 11 MM in Q4 2012
1
1
2
3
Q4 production was negatively impacted by a total of ~1,700 BOEPD due to reduced ethane
recoveries at Spraberry gas processing facilities |
22
Price Realizations
1
Oil ($/BBL)
NGL ($/BBL)
Gas ($/MCF)
Derivative impact included
in price
1.79
(0.15)
(0.42)
-
-
-
-
-
-
-
-
-
-
-
-
Derivative impact not
included in price
Price
92.74
99.73
87.94
89.77
87.78
44.20
42.57
34.48
32.49
31.48
4.81
4.49
4.43
4.48
4.48
VPP and derivative impact
1.23
0.58
1.07
1.68
3.89
(1.50)
0.76
1.86
1.53
0.79
1.44
1.98
2.43
1.86
1.28
VPPs and Derivatives
Realized Prices (excludes VPPs and derivatives)
Price including VPPs and
all derivatives
VPPs
2.45
1.99
1.87
1.79
1.71
-
-
-
-
-
-
-
-
-
-
1) All periods presented have been restated to exclude discontinued operations
2) Represents cash settlements recorded in net derivative gains or losses excluding
liquidated derivatives 91.51
45.70
3.37
99.15
41.81
2.51
86.87
32.62
2.00
88.09
83.89
30.96
30.69
2.62
3.20
Q4 11
Q1 12
Q2 12
Q3 12
Q4 12
Q4 11
Q1 12
Q2 12
Q3 12
Q4 12
Q4 11
Q1 12
Q2 12
Q3 12
Q4 12
(3.01)
(1.26)
(0.38)
(0.11)
2.18
(1.50)
0.76
1.86
1.53
0.79
1.44
1.98
2.43
1.86
1.28
2 |
23
Production Costs (per BOE)
1
VPP-Adjusted
Production Cost
1)
2)
See supplemental information slides
$13.16
$12.99
$13.88
$15.27
$14.32
Q4 production cost decrease vs.
Q3 primarily due to the following
LOE items:
Lower salt water disposal costs
Lower electricity costs
Lower repair and maintenance costs
All periods presented have been restated to exclude discontinued operations and
intercompany eliminations Production
&
Ad Valorem Taxes
Workovers
LOE
Third Party
Transportation
Natural Gas
Processing
Q4 11
$13.52
Q1 12
$0.30
$13.30
$0.24
Q2 12
$14.21
$0.64
Q3 12
$0.59
Q4 12
$0.42
$15.61
$14.62
$0.68
$3.18
$1.36
$8.00
$7.70
$8.08
$9.61
$8.68
$1.24
$1.28
$1.28
$1.40
$3.43
$3.25
$3.38
$3.14
$0.69
$0.96
$0.75
$0.98 |
24
Q1 2013 Guidance
Daily Production (MBOEPD)
165
170
Production Costs ($/BOE)
$14.00
$16.00
Exploration & Abandonment ($ MM)
$25
$35
Drilling and Acreage
$15
Personnel
and
Seismic
$20
DD&A ($/BOE)
$13.50
$15.50
G&A ($ MM)
$60
$65
Interest Expense ($ MM)
$53
$58
Other Expense ($ MM)
$25
$35
Accretion of Discount on ARO ($ MM)
$2
$4
Noncontrolling Interest (principally PSE) ($ MM)
$8
$11
Current Income Taxes ($ MM)
$2
$7
Effective Tax Rate (%)
35%
40%
Guidance
1
1)
Excludes MTM derivative changes due to increases or decreases in future commodity
prices |
25
Supplemental Information
Supplemental Information Slides
Slide #
2012 Reserve Additions
26
2012 Drilling Capital
27
Liquidity Position
28
Historic Production
29 -
30
Oil and Gas Revenue
31
Derivative Position
32 -
34
Oil, NGL and Gas Differentials
35 -
37
General & Administrative Costs
38
Interest Costs
39
Exploration and Abandonments
40
Income Taxes
41
Supplemental Non-GAAP Financial Measures
42
Supplemental Earnings Per Share Information
43
Supplemental Non-GAAP Financial Measures
44 -
45
VPP -
Adjusted Production Costs
46
Reserves Audit, F&D Costs and Reserve Replacement
47
Certain Reserve Information
48 |
Added
161 MMBOE from the drillbit, or 264% of full-year production, at a drillbit
F&D cost of $17.72 per BOE Reflects significant drilling campaigns in
horizontal Wolfcamp Shale, Spraberry vertical, Eagle Ford Shale and
Barnett Shale Combo plays
All-in reserve replacement of 87 MMBOE, or 144% of full-
year production at an all-in F&D cost of $34.46 per BOE,
including:
Negative pricing revisions of 82 MMBOE due to significant
decline in gas prices
Negative technical revisions of 27 MMBOE; performance
improvements of 53 MMBOE offset by 80 MMBOE of vertical
Spraberry PUDs moved to the probable category as the
Company shifts to more horizontal drilling in the Spraberry
field based on successful horizontal Wolfcamp Shale
drilling results
Reserve mix
100% U.S.
45% oil / 21% NGLs / 34% gas
58% PD / 42% PUD
Proved Reserves / Production: ~18 years
PD Reserves / Production: ~10 years
26
Strong 2012 Reserve Additions
1
Year-end 12
Proved Reserves
(MMBOE)
627
119
116
101
55
44
23
1
1,086
1)
Reflects 2012 SEC pricing (12-month average) of $94.84/Bbl for oil and $2.76/MMBtu
for gas (NYMEX) as compared to 2011 SEC pricing of $96.13/Bbl for oil and
$4.12/MMBtu for gas (NYMEX) Spraberry
Raton
Eagle Ford
Mid-Continent
Barnett Shale
Alaska
South Texas
Other
Total |
27
2012 Drilling Capital
1
1)
Excludes
acquisitions,
asset
retirement
obligations,
capitalized
interest
and
G&G
G&A
$ Millions
$741
$678
$639
$670
$2,728
Q1 2012
Q2 2012
Q3 2012
Q4 2012
FY 2012 |
28
Liquidity Position (12/31/12)
1
Net debt (net of cash balance of $229 MM):
$3.4 B
Unsecured credit facility availability:
$1.0 B
Net debt-to-book capitalization:
37%
1)
Excludes $126 MM of borrowings under PSEs $300 MM credit facility that matures in
March 2017 2)
Excludes net discounts and deferred hedge losses of ~$49 MM
3)
Convertible senior notes due 2038; based on trading value, interest rate reduced to
2.375% from 2.875% effective January 15, 2013; holders of $241 MM in principal
amount exercised their right to convert in Q1
4)
Excludes ~$2 MM of outstanding letters of credit on credit facility; credit facility
balance as of January 31, 2013 was $750 MM Maturities
and
Balances
2
Unsecured credit facility matures in 2017
Investment grade rated
Expect to call convertible senior notes due 2038 for redemption during 2013
2012
2016
$600 MM
3.95%
2017
$455 MM
5.875%
2022
$450 MM
6.875%
$474 MM
4
of
$1.5 B unsecured credit facility
2018
$485 MM
6.65%
2013
$480 MM
3
2.375%
$450 MM
7.50%
2020
$250 MM
7.20%
2028 |
29
Production (MBOEPD)
1
Q4 11
Q1 12
Q2 12
Q3 12
Q4 12
Spraberry
53
62
64
2
69
3
69
4
Eagle Ford Shale
20
23
24
29
35
Raton
26
26
25
25
24
South Texas
7
7
6
6
6
Mid-Continent
19
18
18
18
17
Barnett
6
6
7
7
9
Alaska
4
4
5
5
4
Other
2
1
2
1
1
Total
137
147
151
160
165
1)
2)
Q2 12 production negatively impacted by ~4,800 BOEPD due to unplanned third party
fractionation capacity shortfalls at Mont Belvieu 3)
continuing
ethane
rejection
and
3
rd
party
fractionation
capacity
constraints
at
Mont
Belvieu
4)
All periods presented have been restated to exclude discontinued operations Q4 production was negatively impacted by a total of
~1,700 BOEPD due to reduced ethane recoveries at Spraberry gas processing facilities
Q3 12 production benefited by ~1,800 BPD from partial NGL inventory drawdown at
Mont Belvieu, but offset by a production loss of ~4,000 BOEPD due to |
PXD
Production
By
Commodity
By
Area
1
30
1)
All periods presented have been restated to exclude discontinued operations |
31
Oil and Gas Revenue
1
$ Millions
VPP Deferred
Revenue
$665
$719
$642
$716
$735
$654
$710
$632
$706
$725
$11
$9
$10
$10
$10
Q4 '11
Q1 '12
Q2 '12
Q3 '12
Q4 '12
1)
All periods presented have been restated to exclude discontinued operations |
32
Swaps
WTI (BPD)
3,000
3,000
3,000
3,000
-
-
NYMEX WTI Price ($/BBL)
$ 81.02
$ 81.02
$ 81.02
$ 81.02
-
-
Three
Way
Collars
(BPD)
1
66,750
68,750
72,750
75,750
69,000
26,000
NYMEX Call Price ($/BBL)
$ 119.31
$ 119.42
$ 119.74
$ 120.47
$ 114.05
$ 104.45
NYMEX Put Price ($/BBL)
$ 92.30
$ 92.38
$ 92.53
$ 91.90
$ 93.70
$ 95.00
NYMEX Short Put Price ($/BBL)
$ 74.01
$ 74.19
$ 74.51
$ 74.39
$ 77.61
$ 80.00
% Total Oil Production
~95%
~95%
~95%
~95%
~75%
~25%
Three
Way
Collars
(BPD)
1
1,064
1,064
1,064
1,064
1,000
-
NYMEX Call Price ($/BBL)
$ 105.28
$ 105.28
$ 105.28
$ 105.28
$ 109.50
-
NYMEX Put Price ($/BBL)
$ 89.30
$ 89.30
$ 89.30
$ 89.30
$ 95.00
-
NYMEX Short Put Price ($/BBL)
$ 75.20
$ 75.20
$ 75.20
$ 75.20
$ 80.00
-
% Total NGL Production
<5%
<5%
<5%
<5%
<5%
-
% Total Liquids
~65%
~65%
~65%
~65%
~55%
~15%
Midland/Cushing Swaps (BPD)
3,278
5,000
-
-
-
-
Price Differential ($/BBL)
$ (5.75)
$ (5.75)
-
-
-
-
Cushing/LLS Swaps (BPD)
-
-
-
1,000
-
-
Price Differential ($/BBL)
-
-
-
$(7.60)
-
-
Spraberry Fixed Differential
2
24,000
26,000
28,000
30,000
33,000
35,000
Price Differential ($/BBL)
$ (1.75)
$ (1.75)
$ (1.75)
$ (1.75)
$ (1.75)
$ (1.75)
Oil Basis Protection
Q1 2013
Q2 2013
Q3 2013
Q4 2013
2014
2015
Natural Gas Liquids
Q1 2013
Q2 2013
Q3 2013
Q4 2013
2014
2015
Q1 2013
Q2 2013
Q3 2013
Q4 2013
2014
2015
Oil
PXD Open Commodity Derivative Positions as of 2/8/2013 (includes
PSE)
1) When NYMEX price is above call price, PXD receives call price. When NYMEX
price is between put price and call price, PXD receives NYMEX price. When NYMEX price is between the put price and the
short put price, PXD receives put price. When NYMEX price is below the short put
price, PXD receives NYMEX price plus the difference between the short put price and put price
2) Market transaction representing Midland/Cushing differential; not a derivative |
33
Swaps -
(MMBTUPD)
162,500
162,500
162,500
162,500
105,000
-
NYMEX Price ($/MMBTU)
1
$ 5.13
$ 5.13
$ 5.13
$ 5.13
$ 4.03
-
Collars -
(MMBTUPD)
150,000
150,000
150,000
150,000
-
-
NYMEX Call Price ($/MMBTU)
1
$ 6.25
$ 6.25
$ 6.25
$ 6.25
-
-
NYMEX Put Price ($/MMBTU)
1
$ 5.00
$ 5.00
$ 5.00
$ 5.00
-
-
Three
Way
Collars
(MMBTUPD)
1,2
-
-
-
-
25,000
225,000
NYMEX Call Price ($/MMBTU)
-
-
-
-
$4.70
$ 5.09
NYMEX Put Price ($/MMBTU)
-
-
-
-
$4.00
$ 4.00
NYMEX Short Put Price ($/MMBTU)
-
-
-
-
$3.00
$ 3.00
% Total Gas Production
~80%
~80%
~80%
~80%
~30%
~55%
Spraberry
(MMBTUPD)
52,500
52,500
52,500
52,500
-
-
Price Differential ($/MMBTU)
$ (0.23)
$ (0.23)
$ (0.23)
$ (0.23)
-
-
Mid-Continent (MMBTUPD)
50,000
50,000
50,000
50,000
10,000
-
Price Differential ($/MMBTU)
$ (0.30)
$ (0.30)
$ (0.30)
$ (0.30)
$ (0.19)
-
Gulf Coast
(MMBTUPD)
60,000
60,000
60,000
60,000
-
-
Price Differential ($/MMBTU)
$ (0.14)
$ (0.14)
$ (0.14)
$ (0.14)
-
-
Gas Basis Swaps
Q1 2013
Q2 2013
Q3 2013
Q4 2013
2014
2015
Q1 2013
Q2 2013
Q3 2013
Q4 2013
2014
2015
Gas
PXD Open Commodity Derivative Positions as of 2/8/2013 (includes
PSE)
1) Represents the NYMEX Henry Hub index price or approximate NYMEX price based on
historical differentials to the index price at the time the derivative was entered into
2) When NYMEX price is above call price, PXD receives call price. When NYMEX
price is between put price and call price, PXD receives NYMEX price. When NYMEX price is
between the put price and the short put price, PXD receives put price. When NYMEX
price is below the short put price, PXD receives NYMEX price plus the difference
between short put price and put price |
34
1)
When NYMEX price is above call price, PSE receives call price. When NYMEX price
is between put price and call price, PSE receives NYMEX price. When NYMEX price is between the put price and the short put price,
2) Approximate NYMEX price based on differentials to index prices at the date the
derivative was entered into Oil
Q1 2013
Q2 2013
Q3 2013
Q4 2013
2014
2015
Swaps
(BPD)
3,000
3,000
3,000
3,000
-
-
NYMEX Price ($/BBL)
$81.02
$81.02
$81.02
$81.02
-
-
Three-Way
Collars
(BPD)
1,750
1,750
1,750
1,750
5,000
-
NYMEX Call Price ($/BBL)
$116.00
$116.00
$116.00
$116.00
$105.74
-
NYMEX Put Price ($/BBL)
$88.14
$88.14
$88.14
$88.14
$100.00
-
NYMEX Short Put Price ($/BBL)
$73.14
$73.14
$73.14
$73.14
$80.00
-
% Oil Production
~85%
~85%
~85%
~85%
~85%
-
Gas
Swaps
(MMBTUPD)
2,500
2,500
2,500
2,500
5,000
-
NYMEX Price ($/MMBTU)
$6.89
$6.89
$6.89
$6.89
$4.00
-
Three-Way
Collars
(MMBTUPD)
-
-
-
-
-
5,000
NYMEX Call Price ($/MMBTU)
-
-
-
-
-
$5.00
NYMEX Put Price ($/MMBTU)
-
-
-
-
-
$4.00
NYMEX Short Put Price ($/MMBTU)
-
-
-
-
-
$3.00
% Gas Production
~35%
~35%
~35%
~35%
~70%
~65%
% Total Production
~65%
~65%
~65%
~65%
~70%
~10%
Gas Basis Swaps
Q1 2013
Q2 2013
Q3 2013
Q4 2013
2014
2015
Spraberry
(MMBTUPD)
2,500
2,500
2,500
2,500
-
-
Price Differential ($/MMBTU)
(0.31)
(0.31)
(0.31)
(0.31)
-
-
PSE Derivative Position as of 2/8/2013
1,
2
2
1
PSE receives put price. When NYMEX price is below the short put price, PSE
receives NYMEX price plus the difference between the short put price and put price |
Q4
11 Q1 12
Q2 12
Q3 12
Q4 12
NYMEX calendar month average
$ 94.06
$ 102.93
$ 93.49
$ 92.22
$ 88.18
NYMEX differential
(2.55)
(3.78)
(6.62)
(4.13)
(4.29)
Realized prices excluding
VPPs and derivatives
91.51
99.15
86.87
88.09
83.89
Impact of VPPs and derivatives included in price
VPPs
2.45
1.99
1.87
1.79
1.71
Derivatives included in price
1.79
(0.15)
(0.42)
-
-
Reported prices including
VPPs and derivatives
included in price
95.75
100.99
88.32
89.88
85.60
Derivatives not included in price
(3.01)
(1.26)
(0.38)
(0.11)
2.18
Price including VPPs and all derivatives
$ 92.74
$ 99.73
$ 87.94
$ 89.77
$ 87.78
35
Oil Differentials (per BBL)
2
1
1)
All periods presented have been restated to exclude discontinued operations
2)
Represents cash settlements recorded in net derivative gains or losses excluding
liquidated derivatives |
36
NGL
Differentials
(per
BBL)
Q4 11
Q1 12
Q2 12
Q3 12
Q4 12
NYMEX oil calendar month average
$ 94.06
$ 102.93
$ 93.49
$ 92.22
$ 88.18
NYMEX differential
(48.36)
(61.12)
(60.87)
(61.26)
(57.49)
Realized prices excluding derivatives
45.70
41.81
32.62
30.96
30.69
Impact of derivatives included in price
-
-
-
Reported prices including derivatives included in price
45.70
41.81
32.62
30.96
30.69
Derivatives
not
included
in
price
(1.50)
0.76
1.86
1.53
0.79
Price including all derivatives
$ 44.20
$ 42.57
$ 34.48
$ 32.49
$ 31.48
Realized NGL prices excluding derivatives as a
percentage of NYMEX oil calendar month average
49%
41%
35%
34%
35%
1
2
1)
All periods presented have been restated to exclude discontinued operations 2) Represents cash settlements recorded in net derivative
gains or losses excluding liquidated derivatives |
37
Gas Differentials (per MCF)
1
Q4 11
Q1 12
Q2 12
Q3 12
Q4 12
NYMEX bid week average
$ 3.55
$ 2.72
$ 2.21
$ 2.80
$ 3.41
NYMEX differential
(0.18)
(0.21)
(0.21)
(0.18)
(0.21)
Realized prices excluding
derivatives
3.37
2.51
2.00
2.62
3.20
Impact of derivatives included in price
-
-
-
-
-
Reported prices including
derivatives included in price
3.37
2.51
2.00
2.62
3.20
Derivatives not included in price
2
1.44
1.98
2.43
1.86
1.28
Price including all derivatives
$ 4.81
$ 4.49
$ 4.43
$ 4.48
$ 4.48
1)
All
periods
presented
have
been
restated
to
exclude
discontinued
operations
2)
Represents cash settlements recorded in net derivative gains or losses excluding
liquidated derivatives |
38
General & Administrative Costs
1
$ Millions
Noncash
Q4
2011
1) All periods presented have been restated to exclude discontinued operations
Q1
2012
$55
Q2
2012
$63
Q3
2012
$55
Q4
2012
$63
$68
Includes performance-based
compensation awards for 2012 |
39
Interest Costs
1
$ Millions
Q4
2011
1) All periods presented have been restated to exclude discontinued operations
$46
Q1
2012
Q2
2012
$47
$49
Q3
2012
Q4
2012
$54
Noncash
$54 |
40
Exploration & Abandonments
Drilling & Acreage
Barnett Shale
$ 72
Acreage & Other
1
73
Geological & Geophysical
Seismic
2
Personnel & Other
14
16
4
th
Quarter 2012 Total
$ 89
$ Millions |
41
Quarter Ended December 31, 2012
($ Millions)
Current tax benefit
Deferred tax provision
Income Taxes Attributable to Continuing Operations $ -
(9)
$ (9) |
Net
Income $ 40
Depletion, depreciation and amortization
220
Exploration and abandonments
89
Impairment
88
Accretion of discount on asset retirement obligations
3
Interest expense
54
Income tax provision
9
Gain on disposition of assets, net
(1)
Derivative related activity
(24)
Amortization of stock-based compensation
16
Amortization of deferred revenue
(11)
Other noncash items
(19)
EBITDAX
464
Cash interest expense
(45)
Discretionary cash flow
419
Cash exploration expense
(16)
Changes in operating assets and liabilities
77
Net cash provided by operating activities
$ 480
42
Supplemental Non-GAAP Financial Measures
EBITDAX and discretionary cash flow (DCF) are disclosed by Pioneer, and
reconciled to the generally accepted accounting principle (GAAP)
measures of net income and net cash provided by operating activities because of their
wide acceptance by the investment community as financial indicators of a
companys 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
Companys
financial
indicators
with
those
of
peer
companies
that
follow
the
full
cost
method
of
accounting.
EBITDAX
and
DCF
should
not
be
considered
as
alternatives
to
net
income
or
net
cash
provided
by
operating
activities,
as
defined
by
GAAP.
Q4 12
($ Millions) |
Weighted
average basic and diluted common shares outstanding Basic
123,240
Dilutive common stock options
143
Contingently issuable performance unit shares
196
Convertible senior notes dilution
3,366
Diluted
126,945
43
Supplemental Earnings Per Share Information
Q4 2012
Q4 2012
Net income attributable to common stockholders
$ 28,834
Participating share-
and unit-based basic earnings
(516)
Basic net income attributable to common stockholders
Diluted effect of participating securities
24
Diluted net income attributable to common stockholders
$ 28,342
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,
GAAP provides that share- and unit-based awards with guaranteed dividend or distribution participation rights qualify as participating securities
during their vesting periods. The Companys basic net income per share
attributable to common stockholders is computed as (i) net income attributable to
common stockholders, (ii) less participating share- and unit-based basic earnings (iii) divided by weighted average basic shares outstanding. The
Companys diluted net income per share attributable to common stockholders is
computed as (i) basic net income attributable to common stockholders, (ii) plus
the dilutive effect, if any, of participating securities (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 are dilutive to loss per
share; therefore, conversion into common stock is assumed not to occur.
The following table is a reconciliation of the Companys net income attributable to
common stockholders to basic net income attributable to common stockholders and to
diluted net income attributable to common stockholders for the three months ended December 31, 2012 (in thousands):
28,318 |
44
Supplemental Non-GAAP Financial Measures
$ Per Share
$ Millions
(After Tax)
Net income attributable to common stockholders
29
0.22
Unrealized MTM derivative gains ($22 MM before tax)
(14)
(0.11)
Adjusted income excluding unrealized MTM derivative gains
15
0.11
Unusual items included in adjusted income:
Impairment of Barnett Shale assets previously held for sale ($160 MM before tax)
101
0.78
Alaska Petroleum Production Tax credit income ($14 MM before tax)
(9)
(0.06)
Adjusted income excluding unrealized MTM derivative gains and unusual items
Adjusted income excluding unrealized MTM derivative gains and adjusted income
excluding unrealized MTM derivative gains and unusual items, as presented in the Q4 2012
Earnings Summary slide, is presented and reconciled to Pioneers net income
attributable to common stockholders and diluted common shares outstanding (determined in
accordance with GAAP) because Pioneer believes that these non-GAAP financial measures
reflect an additional way of viewing aspects of Pioneers 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
Pioneers historical and future financial performance. These non-GAAP financial measures are not
intended to be substitutes for the comparable GAAP measures and should be read only in
conjunction with Pioneers consolidated financial statements prepared in accordance
with GAAP. Unrealized 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 Pioneers net income attributable to common
stockholders for the three months ended December 31, 2012, as determined in
accordance with GAAP, to adjusted income excluding unrealized MTM derivative gains and
adjusted income excluding unrealized MTM derivative gains and unusual items for
that quarter.
0.83
107 |
Supplemental Non-GAAP Financial Measures
Q4 2012 Results from
Continuing Operations
Adjustments to Exclude
Barnett Shale Q4 2012
Operating Results
(1)
Adjustments to Exclude
Unrealized MTM Derivative
Gains and Unusual Items
Q4 2012 Results Excl.
Unrealized MTM Derivative
Gains, Unusual Items and
Barnett Shale Activity
Daily Production (MBOEPD)
165
(9)
156
Production Costs ($/BOE)
14.62
(0.14)
14.48
Exploration & Abandonment ($ MM)
89
(73)
16
DD&A ($/BOE)
14.54
0.09
14.63
G&A ($ MM)
68
68
Interest Expense ($ MM)
54
54
Other Expense ($ MM)
27
27
Accretion of Discount on ARO ($ MM)
3
(1)
2
Noncontrolling Interest
11
(3)
8
Current Tax Provision (Benefit)
-
-
Effective Tax Rate
2
(%)
24%
(10%)
34%
(1)
The Companys Barnett Shale properties were reclassified to discontinued
operations during the third quarter of 2012 as a result of the Companys decision to
divest of these properties
(2) The effective tax rates in the adjustment columns represent the
effective tax rates attributable to the results or adjustments applicable to that column
45
Selected Q4 2012 results excluding Barnett Shale activity and excluding unrealized MTM derivative gains
and unusual items, as presented in the Q4 2012 Earnings Summary Slide, are presented and
reconciled to the comparable GAAP results in the table below because Pioneer believes that these
non-GAAP financial measures reflect an additional way of viewing aspects of Pioneers
business that, when viewed together with its financial results computed in accordance with GAAP, provide 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 Pioneers 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 Pioneers consolidated financial statements prepared
in accordance with GAAP. |
46
VPP
Adjusted Production Costs
Pioneer presents VPP-Adjusted Production Costs (per BOE) to assist
investors in considering the Companys costs in relation to the total BOEs
(reported sales volumes plus VPP delivered volumes) in connection with
which those costs were incurred. VPP-Production Costs (per BOE) are
calculated as follows:
Q4 11
Q1 12
Q2 12
Q3 12
Q4 12
Production costs as reported (thousands)
$ 170,000
$ 177,579
$ 194,574
$ 229,467
$ 221,781
Production (MBOE):
As reported
12,576
13,352
13,696
14,710
15,163
VPP deliveries
345
319
319
322
322
VPP-adjusted production
12,921
13,671
14,015
15,032
15,485
Production costs per BOE:
As reported
$ 13.52
$ 13.30
$ 14.21
$ 15.61
$14.62
VPP-adjusted
$ 13.16
$ 12.99
$ 13.88
$ 15.27
$14.32
1) All periods presented have been restated to exclude discontinued operations and
intercompany eliminations 1 |
47
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. "Finding and development cost per BOE," or all-in F&D
cost per BOE, means total costs incurred divided by the
summation of annual proved reserves, on a BOE basis, attributable to revisions of
previous estimates, purchases of minerals-in-place, discoveries and
extensions and improved recovery. Consistent with industry practice, future
capital costs to develop proved undeveloped reserves are not included in costs
incurred. "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 technical revisions of previous estimates,
discoveries and extensions and improved recovery. Consistent with industry
practice, future capital costs to develop proved undeveloped reserves are not included in
costs incurred. Reserve replacement
is the summation of annual proved reserves, on a BOE basis, attributable to revisions of
previous estimates, purchases of minerals-in-place, discoveries and
extensions and improved recovery divided by annual production of oil, NGLs and
gas, on a BOE basis. Drillbit reserve replacement
is the summation of annual proved reserves, on a BOE basis, attributable to technical
revisions of previous estimates, discoveries and extensions and improved recovery
divided by annual production of oil, NGLs and gas, on a BOE basis.
Reserves
Audit,
F&D
Costs
and
Reserve
Replacement |
48
Certain Reserve Information
Cautionary Note to U.S. Investors --The U.S. Securities and Exchange Commission
(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 presentation, Pioneer includes estimates of quantities of oil and gas using
certain
terms,
such
as
resource,
resource
potential,
EUR,
oil
in
place
or
other
descriptions of volumes of reserves, which terms include quantities of oil and gas that
may not meet the SECs 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 Companys
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 Companys website at www.pxd.com. These filings also can be obtained
from the SEC by calling 1-800-SEC- 0330. |
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