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Press release from Business Wire

Pioneer Natural Resources Reports First Quarter 2013 Financial and Operating Results

Wednesday, May 01, 2013

Pioneer Natural Resources Reports First Quarter 2013 Financial and Operating Results

16:10 EDT Wednesday, May 01, 2013

DALLAS (Business Wire) -- Pioneer Natural Resources Company (NYSE:PXD) (“Pioneer” or “the Company”) today announced financial and operating results for the quarter ended March 31, 2013.

Pioneer reported first quarter net income attributable to common stockholders of $101 million, or $0.75 per diluted share (see attached schedule for a description of the net income per diluted share calculation). Without the effect of noncash derivative mark-to-market losses and other unusual items, adjusted income for the first quarter was $136 million after tax, or $1.02 per diluted share.

First quarter and other recent highlights included:

  • producing 171 thousand barrels oil equivalent per day (MBOEPD) in the first quarter, an increase from the fourth quarter of 2012 of 6 MBOEPD, or 4%, as a result of continued strong production growth from the Company's drilling programs in the liquids-rich Spraberry vertical, horizontal Wolfcamp Shale and Eagle Ford Shale areas;
  • continuing to deliver strong horizontal drilling results in the southern Wolfcamp joint interest area, including nine new Wolfcamp B wells placed on production during the first quarter with an average peak 24-hour initial production rate of 911 barrels oil equivalent per day (BOEPD);
  • pumping more cost-efficient slickwater fracture stimulations on five Wolfcamp B wells in the southern Wolfcamp joint interest area (saving up to an estimated $1 million per well) with encouraging results;
  • nearing the expected early June closing date for the Sinochem joint interest transaction;
  • progressing the northern horizontal Spraberry/Wolfcamp drilling program, with Pioneer's first Wolfcamp B interval well in Martin County recently fracture stimulated;
  • increasing from one horizontal rig to five horizontal rigs in the northern Spraberry/Wolfcamp area during the second quarter; of the four-rig increase, three rigs were planned and one is being added to focus on developing the Hutt lease in Midland County (capital for the incremental rig is expected to be absorbed in the existing 2013 drilling budget of $2.75 billion);
  • focusing three rigs of the five-rig northern horizontal program on the Wolfcamp Shales and two rigs on the Jo Mill and Spraberry Shales;
  • continuing to deliver significant incremental production from deeper vertical drilling in the Spraberry field;
  • delivering record Eagle Ford Shale net production of 37 MBOEPD, an increase of 7% from the fourth quarter of 2012;
  • completing the Company's Alaska winter drilling program, including (i) the successful fracture stimulation of four horizontal wells from the Company's island drill site; the wells are currently being placed on production with the first two wells having achieved peak gross production rates to date of approximately 3,500 barrels oil per day (BOPD) and 3,000 BOPD (both wells still unloading), and (ii) the drilling of an appraisal well in the Torok interval from an onshore drill site, which increases Pioneer's original resource potential of 50 million barrels of oil (MMBO) for this interval to 75 MMBO to 100 MMBO; and
  • adding gas derivative positions for the 2013 through 2016 period.

Scott Sheffield, Chairman and CEO, stated, “As the third largest driller in the U.S., the Company delivered another strong quarter, with production exceeding expectations. Our three liquids and resource-rich core assets in Texas, the Spraberry vertical, the horizontal Wolfcamp Shale and the Eagle Ford Shale, were the drivers of this significant increase. Importantly, oil production grew 10% in the first quarter of 2013 compared to the fourth quarter of 2012.

“Our extensive geologic and engineering evaluation of the resource potential of the Spraberry/Wolfcamp area ranks it as the largest oil field in the United States. Pioneer's 900,000-acre leasehold position in the Spraberry/Wolfcamp holds multiple prospective horizontal targets with an aggregate estimated resource potential of more than 4.6 billion barrels oil equivalent (BBOE). Our joint interest agreement with Sinochem is allowing the horizontal development of the Wolfcamp Shale over our southern 200,000 acres to be accelerated, and we are now ramping up our appraisal activity of the Wolfcamp, Jo Mill and Spraberry Shales across our northern acreage. We are confident that Pioneer will add substantial net asset value as these plays are developed.”

Mark-To-Market Derivative Losses and Unusual Items Included in First Quarter 2013 Earnings

Pioneer's first quarter earnings included unrealized mark-to-market losses on derivatives of $60 million after tax, or $0.45 per diluted share.

First quarter earnings also included income of $25 million after tax, or $0.18 per diluted share, related to the following unusual items:

  • Net gain on the sale of unproved properties of $14 million after tax, or $0.10 per diluted share,
  • Alaska production tax credit recoveries of $12 million after tax, or $0.09 per diluted share and
  • Rig contract termination fees of $1 million after tax, or $0.01 per diluted share.

Operations Update and Drilling Program

Pioneer's 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 has signed an agreement with Sinochem to sell 40% of Pioneer's 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 Pioneer's share of future drilling and facilities costs. The transaction is estimated to close during June, subject to governmental approvals.

Under the agreement, Sinochem will acquire 82,800 net acres of Pioneer's leasehold in the Wolfcamp horizon. Pioneer retains 60% of its interest in the Wolfcamp and deeper horizons, with Sinochem receiving 40% of Pioneer's 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 Pioneer's 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.

The thickness of the Wolfcamp B interval in the southern joint interest area provides the opportunity to complete two stacked laterals in this interval (referred to as the Upper B and Lower B intervals). The Company placed nine new horizontal wells on production in the Upper B interval during the first quarter of 2013 with an average peak 24-hour initial production rate of 911 BOEPD, with oil comprising 82% of the production. Eight of the wells had an average lateral length of approximately 7,100 feet, while the ninth well was a longer lateral at approximately 9,600 feet. The performance of these nine wells coupled with the 28 horizontal wells previously placed on production by Pioneer in the southern Wolfcamp joint interest area reinforces the Company's estimate that wells in this area will deliver an average estimated ultimate recovery (EUR) of at least 575 thousand barrels oil equivalent (MBOE) over the life of the well.

Pioneer operated seven rigs in the southern Wolfcamp joint interest area during the first quarter of 2013 and plans to continue at this level through the end of the year. An increase of three rigs per year is expected in 2014 and 2015. The 2013 drilling program will continue to focus on delineating acreage and testing multiple Wolfcamp intervals, while the program in 2014 and beyond will primarily focus on development drilling and accelerating production growth. Approximately 70% of the wells drilled in this area during 2013 will be from pads. The Company has included “science” expenditures of $20 million in the 2013 southern Wolfcamp joint interest area drilling budget for coring, open-hole logging, micro-seismic and 3-D seismic. The cost for horizontal development wells is targeted at $7.5 million to $8.0 million for an 8,300-foot lateral well. The Company expects to drill more than 20 laterals that extend the lateral length to approximately 10,000 feet during 2013. These longer lateral wells are expected to generate an EUR increase of 40% to 60% at an incremental cost of 20%. Completion techniques will continue to be optimized and downspacing opportunities are being evaluated. In particular, slickwater fracture stimulations are being tested. The Company has pumped five Wolfcamp B slickwater fracture stimulations year-to-date in the southern Wolfcamp joint interest area with encouraging results. Slickwater fracture stimulations are expected to save up to $1 million per well compared to the hybrid fracture stimulations that Pioneer has been utilizing in this area.

During the fourth quarter of 2012, Pioneer completed two highly successful horizontal Jo Mill wells in Upton County. 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 oil comprising 80% of the production, and when normalized to 5,000 feet, the wells have continued to outperform 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.

During the first quarter, Pioneer announced that it would be initiating a $1 billion capital program for 2013 and 2014 to accelerate the horizontal appraisal of the Company's northern Spraberry/Wolfcamp acreage. The 2013 drilling program, which is estimated to cost $400 million, is expected to drill a total of 30 to 40 wells targeting six different “stacked” intervals. The six “stacked” intervals across the Company's 600,000 prospective gross acres equate 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 and the Lower Spraberry Shales. The cost for these wells is expected to range from $7.5 million to $8.5 million per well assuming 7,000-foot laterals. This cost excludes $80 million of estimated “science” and infrastructure costs.

Pioneer's initial rig in the northern acreage has drilled the Company's first three horizontal Wolfcamp Shale wells in this area – two in Midland County and one in Martin County. The first well (DL Hutt C #1H) was completed in the Wolfcamp B interval in Midland County during January and had a lateral length of 7,380 feet. It has been the best horizontal well drilled in the Wolfcamp Shale play to date, with an initial peak 24-hour production rate of 1,693 BOEPD and an average peak 30-day rate flowing naturally of 1,402 BOEPD. The well has been on production for a little more than one hundred days and has produced a total of 100 MBOE, with an oil content of 75%. The performance of this well is substantially above the 650 MBOE EUR type curve for the previously discussed Giddings area wells.

The second horizontal well in Midland County was drilled in the Wolfcamp A interval and is scheduled to be completed in late May/early June. Since this well was drilled in close proximity to the DL Hutt C #1H, its completion was intentionally delayed so that an extended production test could be done on the DL Hutt C #1H well. This well will have to be shut in during the fracture stimulation of the Wolfcamp A interval well to avoid any possible interference.

The initial rig moved from Midland County and drilled the Company's first horizontal Wolfcamp B well in Martin County. This well was recently fracture stimulated.

The Company is increasing its horizontal rig count in the northern drilling area from one rig to five rigs during the second quarter. Of the four additional rigs, three rigs were envisioned in the original plan. The incremental rig is being added as a result of the three planned rigs arriving later than originally anticipated. The cost for this rig is expected to be absorbed in the 2013 drilling budget.

During the second quarter, the five-rig program will be focused in Midland and Martin counties and consist of two rigs drilling Wolfcamp Shale appraisal wells, two rigs drilling Jo Mill and Spraberry Shale appraisal wells and one rig drilling Wolfcamp development wells on the Hutt lease. All wells will be drilled on two-well pads to gain efficiencies; therefore, the wells will not be completed until after the second well on each pad is drilled.

Pioneer expects to increase the rig count on its northern Spraberry/Wolfcamp acreage to six rigs to eight 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 is operating 15 vertical rigs in the Spraberry field during 2013, which are expected to drill approximately 300 wells. These rigs are required to meet continuous drilling obligations. The Company estimates that 15 rigs to 20 rigs are required to keep vertical production flat. Approximately 90% of the 300 wells in the 2013 vertical drilling program are expected to be completed in the deeper Strawn, Atoka and Mississippian intervals.

Pioneer drilled 75 vertical wells in the first quarter and placed 130 vertical wells on production as a result of decreasing the Company's vertical frac bank by 55 wells. Production from deeper drilling continues to exceed expectations and contribute to production growth.

First quarter production from the entire Spraberry/Wolfcamp area averaged 75 MBOEPD, an increase of 6 MBOEPD, or 10%, from the fourth quarter of 2012. This included horizontal production of 5 MBOEPD from the Wolfcamp and Jo Mill intervals and vertical production of 70 MBOEPD from the Spraberry, Wolfcamp and deeper Strawn, Atoka and Mississippian intervals. First quarter production included the benefit of approximately 2,000 BOEPD as a result of the reduction in the vertical frac bank of 55 wells. This benefit was negatively impacted by the loss of approximately 2,700 BOEPD during the first quarter due to reduced ethane recoveries resulting from Spraberry gas processing facilities operating above capacity as a result of greater-than-anticipated Pioneer and industry production growth. This gas processing capacity shortfall continued until mid-April when the new Driver gas processing plant came online. The plant has a capacity of 200 million cubic feet per day (MMCFPD), which is alleviating the bottleneck that was impacting ethane recoveries.

For 2013, total Spraberry/Wolfcamp 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 three rigs in 2012 to 12 rigs in 2013. This shift to more horizontal drilling 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 takes into account that more than 4 MBOEPD of horizontal production, on an annualized basis, is expected to be conveyed to Sinochem at the time the joint interest transaction closes, which is currently assumed to be on June 1, 2013.

In the liquids-rich Eagle Ford Shale play in South Texas, the Company drilled 37 wells in the first quarter and placed 35 wells on production. Pioneer increased its Eagle Ford Shale production by 7% from 35 MBOEPD in the fourth quarter of 2012 to 37 MBOEPD in the first quarter, achieving another record production level. Strong well performance continues to drive this growth. The Company expects 2013 production to range from 38 MBOEPD to 42 MBOEPD, an increase of 36% to 50% compared to full-year 2012 production of 28 MBOEPD.

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. Pioneer's 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 Pioneer's 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 a similar 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 Eagle Ford Shale field. The Company is now expanding the use of white sand proppant to deeper areas of the field to further assess its performance limits. The Company fracture stimulated 22 wells with white sand proppant in the first quarter, with a savings of approximately $700 thousand per well. Early performance from wells fracture stimulated with white sand over the past two years has been similar to direct offset ceramic-stimulated wells. Pioneer is continuing to monitor the performance of these wells and expects that approximately 70% of its 2013 drilling program will use the lower-cost white sand proppant.

Eleven central gathering plants (CGPs) are now operational as part of the joint venture's Eagle Ford Shale midstream business. One additional CGP is expected to be added during 2014. Pioneer's 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 Pioneer's forecasted operating cash flow.

In the liquids-rich Barnett Shale Combo play, Pioneer drilled eight wells in the first quarter and placed four wells on production. Pioneer operated one rig in the play during the first quarter and added a second rig in April. The cost for a 5,000-foot lateral horizontal well has been reduced to $2.9 million as a result of improved drilling and completion performance. The Company plans to utilize two rigs going forward to hold acreage in the highest-return areas of the Company's 80 thousand net acreage position. These areas have been identified from drilling data and petrophysical and seismic analysis. Pioneer currently holds approximately 25% of its acreage position by production, or 20 thousand net acres, and expects to hold an additional 40 thousand net acres by production over the next three years with a two-rig drilling program.

Production in the first quarter for the Barnett Shale Combo play was 9 MBOEPD. The Company expects production to increase from an average of 7 MBOEPD in 2012 to 9 MBOEPD to 12 MBOEPD in 2013.

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 Company's first quarter production was approximately 4,000 BOPD. During the first quarter of 2012, the Company completed its first successful mechanically diverted fracture stimulation of a Nuiqsut interval well. The well has produced over 685 thousand barrels of oil during its first 12 months of production.

Based on the success of this mechanically diverted fracture stimulation, the Company drilled four more wells over the remainder of 2012 and fracture stimulated these wells during the first quarter of 2013 (winter drilling season). Three of these wells were in the Nuiqsut interval and one was in the Torok interval. The first two fracture stimulated Nuiqsut interval wells have been placed on production with peak gross production rates of approximately 3,500 BOPD and 3,000 BOPD to date (both wells still unloading). The remaining two wells that were fracture stimulated during the first quarter are expected to be placed on production by the end of May.

During the first quarter of 2012, the Company also drilled a successful appraisal well to test the southern extent of the Torok interval from an onshore drill site. The subsurface data provided by this successful well supported the addition of 50 MMBO to the resource potential of the Torok interval within Pioneer's acreage. The well was flow tested again during the first quarter of 2013 and produced at a facility-limited rate of 2,800 BOPD before being shut in until permanent onshore production facilities are constructed.

Pioneer drilled a second Torok appraisal well from the onshore drill site during the first quarter of 2013. Logs from this well confirm the high quality reservoir rock identified in the first onshore well. Based on this result, Pioneer has increased the resource potential range for the Torok interval to 75 MMBO to 100 MMBO. The well encountered a mechanical problem and could not be flow tested before the end of the winter drilling season.

2013 Capital Budget

Pioneer's capital program for 2013 remains at $3 billion (excludes acquisitions, asset retirement obligations, capitalized interest and geological and geophysical G&A), including $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 Pioneer's new Midland office building and several new field buildings. Drilling capital expenditures in the first quarter of 2013 totaled $759 million.

The 2013 capital budget is expected to be funded from forecasted operating cash flow of $2.2 billion, assuming commodity prices of $90 per barrel for oil and $4.25 per thousand cubic feet (MCF) for gas, estimated proceeds of $600 million from Pioneer's 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 $200 million from cash on the balance sheet.

Pioneer's net debt as of March 31, 2013, was $2.6 billion and net debt-to-book capitalization was 26%. The Company will continue to target a net debt-to-book capitalization below 35% and net debt-to-operating cash flow below 1.5 times.

First Quarter 2013 Financial Review

Sales volumes for the first quarter of 2013 averaged 171 MBOEPD. Oil sales averaged 74 thousand barrels per day (MBPD), natural gas liquids (NGL) sales averaged 33 MBPD and gas sales averaged 384 MMCFPD.

The average price for oil was $88.57 per barrel. The average price for NGLs was $30.36 per barrel and the average price for gas was $3.14 per MCF.

Production costs from continuing operations averaged $14.52 per barrel oil equivalent (BOE). Depreciation, depletion and amortization (DD&A) expense averaged $15.00 per BOE. Exploration and abandonment costs were $28 million, principally comprised of $8 million associated with drilling and acreage abandonments, $5 million for seismic data and $15 million for personnel costs. General and administrative expense totaled $64 million. Interest expense was $51 million and other expense was $21 million.

Second Quarter 2013 Financial Outlook

The Company's second quarter 2013 outlook for certain operating and financial items is provided below.

Production is forecasted to average 174 MBOEPD to 179 MBOEPD. This forecast assumes Pioneer will not experience any significant ethane recovery losses in the Spraberry/Wolfcamp area in the second quarter as a result of the new Driver gas processing plant, with a capacity of 200 MMCFPD, which came on line in mid-April. The guidance for the second quarter also assumes that Pioneer does not reject ethane into the gas stream in any of the Company's operating areas due to low ethane prices.

Production costs are expected to average $14.00 to $16.00 per BOE. DD&A expense is expected to average $14.00 to $16.00 per BOE. Total exploration and abandonment expense is forecasted to be $25 million to $35 million.

General and administrative expense is expected to be $62 million to $67 million, interest expense is expected to be $50 million to $55 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 Company's 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 Company's derivative position. Current income taxes are expected to be $5 million to $10 million and are primarily attributable to federal alternative minimum tax and state taxes.

The Company's financial and derivative mark-to-market results and open derivatives positions are outlined on the attached schedules.

Earnings Conference Call

On Thursday, May 2, 2013, at 9:00 a.m. Central Time, Pioneer will discuss its financial and operating results for the quarter ended March 31, 2013, with an accompanying presentation. Instructions for listening to the call and viewing the accompanying presentation are shown below.

Internet: www.pxd.com
Select “Investors,” then “Earnings & Webcasts” to listen to the discussion, view the presentation and see other related material.

Telephone: Dial (888) 417-8533 confirmation code: 5954966 five minutes before the call. View the presentation via Pioneer's internet address above.

A replay of the webcast will be archived on Pioneer's website. A telephone replay will be available through May 27, 2013, by dialing (888) 203-1112 confirmation code: 5954966.

Pioneer is a large independent oil and gas exploration and production company, headquartered in Dallas, Texas, with operations in the United States. For more information, visit Pioneer's website at www.pxd.com.

Except for historical information contained herein, the statements in this news release are forward-looking statements that are made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause Pioneer's actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties include, among other things, volatility of commodity prices, product supply and demand, competition, the ability to obtain environmental and other permits and the timing thereof, other government regulation or action, the ability to obtain approvals from third parties and negotiate agreements with third parties on mutually acceptable terms, the receipt of approvals required to consummate the Company's 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 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 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 SEC's definitions of proved, probable and possible reserves, and which the SEC's guidelines strictly prohibit Pioneer from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being recovered by Pioneer. U.S. investors are urged to consider closely the disclosures in the Company's periodic filings with the SEC. Such filings are available from the Company at 5205 N. O'Connor Blvd., Suite 200, Irving, Texas 75039, Attention: Investor Relations, and the Company's website at www.pxd.com . These filings also can be obtained from the SEC by calling 1-800-SEC-0330.

 
PIONEER NATURAL RESOURCES COMPANY
 
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands)
         
March 31, 2013

December 31, 2012

ASSETS
Current assets:
Cash and cash equivalents $ 430,298 $ 229,396
Accounts receivable, net 359,217 320,153
Income taxes receivable 1,394 7,447
Inventories 233,402 197,056
Prepaid expenses 13,337 13,438
Derivatives 151,431 279,119
Other current assets, net 7,335   3,746  
Total current assets 1,196,414   1,050,355  
 
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting 15,226,384 14,491,263
Accumulated depletion, depreciation and amortization (4,633,359 ) (4,412,913 )
Total property, plant and equipment 10,593,025   10,078,350  
 
Goodwill 298,142 298,142
Other property and equipment, net 1,228,108 1,217,694
Investment in unconsolidated affiliate 216,369 204,129
Derivatives 95,121 55,257
Other assets, net 134,118   165,103  
 
$ 13,761,297   $ 13,069,030  
 
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable $ 820,363 $ 826,877
Interest payable 37,494 68,083
Income taxes payable 292 208
Deferred income taxes 51,783 86,481
Derivatives 20,413 13,416
Other current liabilities 41,521   39,725  
Total current liabilities 971,866   1,034,790  
 
Long-term debt 3,017,280 3,721,193
Derivatives 13,372 12,307
Deferred income taxes 2,202,637 2,140,416
Other liabilities 290,071 293,016
Equity 7,266,071   5,867,308  
 
$ 13,761,297   $ 13,069,030  
 
       
PIONEER NATURAL RESOURCES COMPANY
 
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
 
Three Months Ended
March 31,
2013       2012
Revenues and other income:
Oil and gas $ 787,855 $ 718,956
Interest and other 19,315 21,908
Gain on disposition of assets, net 24,417   43,596  
831,587   784,460  
Costs and expenses:
Oil and gas production 169,140 131,781
Production and ad valorem taxes 54,297 45,796
Depletion, depreciation and amortization 230,763 181,418
Exploration and abandonments 27,627 53,287
General and administrative 63,751 63,067
Accretion of discount on asset retirement obligations 3,153 2,430
Interest 50,735 46,858
Derivative (gains) losses, net 42,243 (91,750 )
Other 21,349   23,607  
663,058   456,494  
 
Income from continuing operations before income taxes 168,529 327,966
Income tax provision (59,329 ) (117,703 )
Income from continuing operations 109,200 210,263
Income (loss) from discontinued operations, net of tax (465 ) 10,695  
Net income 108,735 220,958
Net income attributable to noncontrolling interests (8,072 ) (6,339 )
Net income attributable to common stockholders $ 100,663   $ 214,619  
 
Basic earnings per share:
Income from continuing operations attributable to common stockholders $ 0.77 $ 1.65
Income (loss) from discontinued operations attributable to common stockholders   0.08  
Net income attributable to common stockholders $ 0.77   $ 1.73  
 
Diluted earnings per share:
Income from continuing operations attributable to common stockholders $ 0.75 $ 1.60
Income (loss) from discontinued operations attributable to common stockholders   0.08  
Net income attributable to common stockholders $ 0.75   $ 1.68  
 
Weighted average shares outstanding:
Basic 128,940   122,480  
Diluted 132,751   126,247  
 
       
PIONEER NATURAL RESOURCES COMPANY
 
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
 
Three Months Ended
March 31,
2013     2012
Cash flows from operating activities:
Net income $ 108,735 $ 220,958
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization 230,763 181,418
Exploration expenses, including dry holes 7,954 27,163
Deferred income taxes 51,894 105,871
Gain on disposition of assets, net (24,417 ) (43,596 )
Accretion of discount on asset retirement obligations 3,153 2,430
Discontinued operations (158 ) 1,577
Interest expense 4,844 9,870
Derivative related activity 95,884 (27,243 )
Amortization of stock-based compensation 17,395 15,086
Amortization of deferred revenue (10,459 )
Other noncash items (2,922 ) (9,516 )
Change in operating assets and liabilities, net of effects from acquisitions and dispositions:
Accounts receivable, net (41,803 ) (20,663 )
Income taxes receivable 6,053 1,407
Inventories 825 (31,027 )
Prepaid expenses 101 1,413
Other current assets (636 ) 2,488
Accounts payable (57,572 ) 19,326
Interest payable (30,589 ) (21,917 )
Income taxes payable 84 16,941
Other current liabilities (9,514 ) (15,441 )

Net cash provided by operating activities

360,074 426,086
Net cash used in investing activities (707,176 ) (679,666 )
Net cash provided by financing activities 548,004   33,014  
Net increase (decrease) in cash and cash equivalents 200,902 (220,566 )
Cash and cash equivalents, beginning of period 229,396   537,484  
Cash and cash equivalents, end of period $ 430,298   $ 316,918  
 
           
PIONEER NATURAL RESOURCES COMPANY
 
UNAUDITED SUMMARY PRODUCTION AND PRICE DATA
 
 
Three Months Ended
March 31,
2013       2012
Average Daily Sales Volumes from Continuing Operations:
Oil (Bbls) 73,939 57,671
Natural gas liquids ("NGL") (Bbls) 32,989 27,485
Gas (Mcf) 383,836 369,422
Total (BOE) 170,900 146,727
 
Average Reported Prices (a):
Oil (per Bbl) $ 88.57 $ 100.99
NGL (per Bbl) $ 30.36 $ 41.81
Gas (per Mcf) $ 3.14 $ 2.51
Total (BOE) $ 51.22 $ 53.85

_____________

(a)

  Average reported prices are attributable to continuing operations and, for 2012, include the results of hedging activities and amortization of VPP deferred revenue. During 2012, all remaining deferred hedge losses were transferred to earnings and, as of December 31, 2012, all VPP production volumes had been delivered and there were no further obligations under VPP contracts or 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") provide that share- and unit-based awards with guaranteed dividend or distribution participation rights qualify as "participating securities" during their vesting periods. The Company's basic net income per share attributable to common stockholders is computed as (i) net income attributable to common stockholders, (ii) less participating share- and unit-based basic earnings (iii) divided by weighted average basic shares outstanding. The Company's diluted net income per share attributable to common stockholders is computed as (i) basic net income attributable to common stockholders, (ii) plus the reallocation of participating earnings (iii) divided by weighted average diluted shares outstanding. During periods in which the Company realizes a loss from continuing operations attributable to common stockholders, securities or other contracts to issue common stock would be dilutive to loss per share; therefore, conversion into common stock is assumed not to occur.

The following table is a reconciliation of the Company's net income attributable to common stockholders to basic net income attributable to common stockholders and to diluted net income attributable to common stockholders for the three months ended March 31, 2013 and 2012:

         
Three Months Ended
March 31,
2013       2012
(in thousands)
 
Net income attributable to common stockholders $ 100,663 $ 214,619
Participating basic earnings (1,270 ) (2,448 )
Basic net income attributable to common stockholders 99,393 212,171
Reallocation of participating earnings 35   71  
Diluted net income attributable to common stockholders $ 99,428   $ 212,242  
 

The following table is a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three months ended March 31, 2013 and 2012:

           
Three Months Ended
March 31,
2013       2012
(in thousands)
 
Weighted average common shares outstanding:
Basic 128,940 122,480
Dilutive common stock options 157 150
Convertible senior notes dilution 3,534 3,460
Contingently issuable performance unit shares 120   157
Diluted 132,751   126,247
 

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 and net cash provided by operating activities, because of their wide acceptance by the investment community as financial indicators of a company's ability to internally fund exploration and development activities and to service or incur debt. The Company also views the non-GAAP measures of EBITDAX and DCF as useful tools for comparisons of the Company's financial indicators with those of peer companies that follow the full cost method of accounting. EBITDAX and DCF should not be considered as alternatives to net income or net cash provided by operating activities, as defined by GAAP.

        Three Months Ended
March 31,
2013     2012
 
Net income $ 108,735 $ 220,958
Depletion, depreciation and amortization 230,763 181,418
Exploration and abandonments 27,627 53,287
Accretion of discount on asset retirement obligations 3,153 2,430
Interest expense 50,735 46,858
Income tax provision 59,329 117,703
Gain on disposition of assets, net (24,417 ) (43,596 )
(Income) loss from discontinued operations 465 (10,695 )
Derivative related activity 95,884 (27,243 )
Amortization of stock-based compensation 17,395 15,086
Amortization of deferred revenue (10,459 )
Other noncash items (2,922 ) (9,516 )
 
EBITDAX (a) 566,747 536,231
 
Cash interest expense (45,891 ) (36,988 )
Current income tax provision (7,435 ) (11,832 )
 
Discretionary cash flow (b) 513,421 487,411
 
Discontinued operations cash activity (623 ) 12,272
Cash exploration expense (19,673 ) (26,124 )

Changes in operating assets and liabilities (c)

(133,051 ) (47,473 )
 
Net cash provided by operating activities $ 360,074   $ 426,086  

_____________

(a)   “EBITDAX” represents earnings before depletion, depreciation and amortization expense; exploration and abandonments; accretion of discount on asset retirement obligations; interest expense; income taxes; net gain or loss on the disposition of assets, net; (income) loss 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 and exploration expense.

(c)

Changes in operating assets and liabilities are primarily due to the timing of payments for working capital items.

 

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 losses, and adjusted income excluding unrealized MTM derivative losses and unusual items, as presented in this press release, are presented and reconciled to Pioneer's net income attributable to common stockholders (determined in accordance with GAAP) because Pioneer believes that these non-GAAP financial measures reflect an additional way of viewing aspects of Pioneer's business that, when viewed together with its financial results computed in accordance with GAAP, provides a more complete understanding of factors and trends affecting its historical financial performance and future operating results, greater transparency of underlying trends and greater comparability of results across periods. In addition, management believes that these non-GAAP measures may enhance investors' ability to assess Pioneer's historical and future financial performance. These non-GAAP financial measures are not intended to be substitutes for the comparable GAAP measure and should be read only in conjunction with Pioneer's consolidated financial statements prepared in accordance with GAAP. 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 Pioneer's net income attributable to common stockholders for the three months ended March 31, 2013, as determined in accordance with GAAP, to income adjusted for unrealized MTM derivative losses and adjusted income excluding unrealized MTM derivative losses and unusual items for that quarter.

               

After-tax
Amounts

Amounts
Per Share

 
Net income attributable to common stockholders $ 100,663 $ 0.75
Unrealized MTM derivative losses 60,582   0.45  
Income adjusted for unrealized MTM derivative losses 161,245 1.20
 
Loss from discontinued operations 465
Gain on disposition of unproved leaseholds (13,691 ) (0.10 )
Drilling rig termination fees 642 0.01
Alaska production tax credit recoveries (12,227 ) (0.09 )
 
Adjusted income excluding unrealized MTM derivative losses and unusual items $ 136,434   $ 1.02  
 
 
PIONEER NATURAL RESOURCES COMPANY
 
SUPPLEMENTAL INFORMATION
 

Open Commodity Derivative Positions as of April 30, 2013

(Volumes are average daily amounts)
         
2013 Year Ending December 31,

Second
Quarter

   

Third
Quarter

   

Fourth
Quarter

2014     2015     2016
 
Average Daily Oil Production Associated with Derivatives (Bbl):
Collar contracts with short puts:
Volume 68,750 72,750 75,750 69,000 26,000
NYMEX price:
Ceiling $ 119.42 $ 119.74 $ 120.47 $ 114.05 $ 104.45 $
Floor $ 92.38 $ 92.53 $ 91.90 $ 93.70 $ 95.00 $
Short put $ 74.18 $ 74.50 $ 74.39 $ 77.61 $ 80.00 $
Swap contracts:
Volume 3,000 3,000 3,000
NYMEX price $ 81.02 $ 81.02 $ 81.02 $ $ $
Rollfactor swap contracts:
Volume 6,000 6,000 6,000 15,000
NYMEX roll price (a) $ 0.43 $ 0.43 $ 0.43 $ 0.38 $ $
Basis swap contracts:
Midland-Cushing index swap volume 5,000
Price differential ($/Bbl) (b) $ (5.75 ) $ $ $ $ $
Cushing-LLS index swap volume 2,000
Price differential ($/Bbl) (c) $ $ $ (9.30 ) $ $ $
Average Daily NGL Production Associated with Derivatives (Bbl):
Collar contracts with short puts (d):
Volume 1,064 1,064 1,064 1,000
Index price:
Ceiling $ 105.28 $ 105.28 $ 105.28 $ 109.50 $ $
Floor $ 89.30 $ 89.30 $ 89.30 $ 95.00 $ $
Short put $ 75.20 $ 75.20 $ 75.20 $ 80.00 $ $
Collar contracts (e):
Volume 1,341 2,500 2,500 3,000
Index price:
Ceiling $ 12.60 $ 12.68 $ 12.68 $ 13.72 $ $
Floor $ 10.50 $ 10.50 $ 10.50 $ 10.78 $ $
Average Daily Gas Production Associated with Derivatives (MMBtu):
Collar contracts with short puts:
Volume 115,000 285,000 20,000
NYMEX price:
Ceiling $ $ $ $ 4.70 $ 5.07 $ 5.36
Floor $ $ $ $ 4.00 $ 4.00 $ 4.00
Short put $ $ $ $ 3.00 $ 3.00 $ 3.00
Collar contracts:
Volume 150,824 152,500 152,500
NYMEX price:
Ceiling $ 6.24 $ 6.22 $ 6.22 $ $ $
Floor $ 4.99 $ 4.98 $ 4.98 $ $ $
Swap contracts:
Volume 172,500 172,500 165,870 175,000 20,000
NYMEX price (f) $ 5.05 $ 5.05 $ 5.10 $ 4.02 $ 4.31 $
Basis swap contracts:
Permian Basin index swap volume (g) 52,500 52,500 52,500
Price differential ($/MMBtu) $ (0.23 ) $ (0.23 ) $ (0.23 ) $ $ $
Mid-Continent index swap volume (g) 50,000 50,000 50,000 20,000
Price differential ($/MMBtu) $ (0.30 ) $ (0.30 ) $ (0.30 ) $ (0.19 ) $ $
Gulf Coast index swap volume (g) 60,000 60,000 60,000
Price differential ($/MMBtu) $ (0.14 ) $ (0.14 ) $ (0.14 ) $ $ $

_____________

(a)   Represent swaps that fix the difference between (i) each day's price per Bbl of West Texas Intermediate oil "WTI" for the first nearby month less (ii) the price per Bbl of WTI for the second nearby NYMEX month, multiplied by .6667; plus (iii) each day's price per Bbl of WTI for the first nearby month less (iv) the price per Bbl of WTI for the third nearby NYMEX month, multiplied by .3333.
(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) Represent collar contracts with short puts that reduce the price volatility of natural gasoline forecasted for sale by the Company at Mont Belvieu, Texas-posted prices.
(e) Represent collar contracts that reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices.
(f) Represents the NYMEX Henry Hub index price on the derivative trade date.
(g) Represent swaps that fix the basis differentials between the indices price at which the Company sells its Permian Basin, 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 April 29, 2013, the Company had interest rate derivative contracts that lock in a fixed forward annual interest rate of 3.21%, 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 buy and sell marketing arrangements to fulfill firm pipeline transportation commitments. Associated with these marketing arrangements, the Company may enter into index swaps to mitigate price risk. The following table presents Pioneer's open marketing derivative positions as of April 29, 2013:

         
2013
Second Quarter
 
Average Daily Gas Production Associated with Marketing Derivatives (MMBtu):
Basis swap contracts:
Index swap volume 13,187
Price differential ($/MMBtu) $ 0.34
 
 

Derivative Losses, Net
(in thousands)

The following table summarizes net derivative gains and losses that the Company has recorded in it earnings for the three months ended March 31, 2013:

       

Three Months Ended
March 31, 2013

Noncash changes in fair value:
Oil derivative gains $ 1,625
NGL derivative gains 890
Gas derivative losses (102,430 )
Marketing derivative gains 91
Interest rate derivative gains 3,940  
Total noncash derivative losses, net (a) (95,884 )
 
Cash settled changes in fair value:
Oil derivative gains 7,520
NGL derivative losses (412 )
Gas derivative gains 46,705
Marketing derivative losses (172 )
Total cash derivative gains, net 53,641  
Total derivative losses, net $ (42,243 )

_____________

(a)   Total net unrealized mark-to-market derivative losses includes $277 thousand of net gains attributable to noncontrolling interests in consolidated subsidiaries during the three months ended March 31, 2013.

Pioneer Natural Resources
Investors
Frank Hopkins, 972-969-4065
or
Josh Jones, 972-969-5822
or
Media and Public Affairs
Susan Spratlen, 972-969-4018
or
Suzanne Hicks, 972-969-4020

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