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Pioneer Natural Resources Reports Fourth Quarter 2011 Financial and Operating Results and Announces 2012 Capital Budget

DALLAS--(BUSINESS WIRE)--Feb. 6, 2012-- Pioneer Natural Resources Company (NYSE:PXD) (“Pioneer” or “the Company”) today announced financial and operating results for the quarter ended December 31, 2011.

Pioneer reported a fourth quarter net loss attributable to common stockholders of $111 million, or $0.93 per diluted share (see attached schedule for a description of the earnings per diluted share calculation). Without the effect of noncash derivative mark-to-market losses and other unusual items, principally noncash, adjusted income for the fourth quarter was $147 million after tax, or $1.19 per diluted share.

Scott Sheffield, Chairman and CEO, stated, “The Company delivered another strong quarter, with production of 140 thousand barrels oil equivalent per day (MBOEPD), an increase of 12 MBOEPD, or 9%, from the third quarter of 2011 (including South Africa, which is being moved to discontinued operations, in both quarters). Our three core liquids-rich growth assets in Texas, the Spraberry field, the Eagle Ford Shale and the Barnett Shale Combo, were the drivers of this significant increase. These three assets were also the primary contributors to Pioneer’s 313% drillbit reserve replacement in 2011 at a drillbit finding and development cost of $13.83 per barrel oil equivalent (BOE).”

“We are announcing that we plan to sell our South Africa business, the only remaining international asset in Pioneer’s portfolio, during the first half of 2012. With this asset removed from continuing operations, production averaged 120 MBOEPD in 2011, an increase of 16% compared to 2010. Based on our drilling plan for 2012, which high grades liquids-rich drilling to optimize returns in response to low gas prices, we expect the Company to deliver production growth of 23% to 27% compared to 2011. The capital program for 2012 totals $2.5 billion, with 86% of the spending designated for drilling in the Spraberry field, the horizontal Wolfcamp Shale, the Eagle Ford Shale and the Barnett Shale Combo. Funding for the capital program includes forecasted operating cash flow of $2.2 billion and $0.3 billion of the proceeds from Pioneer’s recent equity offering.”

“We expect the Company to achieve a compound annual production growth rate of 20+% through 2014, with liquids increasing from 56% of total production currently to 65% in 2014. This strong, liquids-focused production growth, coupled with our attractive derivatives position, is forecasted to generate compound annual operating cash flow growth of 25+% over the 2012 through 2014 period. Revenue from liquids production is expected to grow from 80% of Pioneer’s total revenue currently to 90% by 2014, assuming commodity prices of $100 per barrel for oil and $3 per thousand cubic feet (MCF) for gas in 2012 and $100 per barrel for oil and $4 per MCF for gas in 2013 and 2014.”

“We recently completed our second successful horizontal well in the Wolfcamp Shale in Upton County, Texas. This well is performing similarly to the first well we announced in 2011, with a 24-hour initial production rate of 807 barrels oil equivalent per day (BOEPD) and a peak 30-day average natural flow rate of 677 BOEPD. The first well continues to flow naturally and produced 45 thousand barrels oil equivalent (MBOE) over its first 90 days of production, which is seven times the production from a Spraberry vertical well over the same time period. These results, which are above our expectations, coupled with the strong production from other industry players drilling horizontal wells in this interval and Pioneer’s extensive geologic interpretation of the area, suggest significant horizontal Wolfcamp Shale potential exists within Pioneer’s acreage. We are the largest acreage holder in the Wolfcamp Shale play with more than 400,000 prospective acres. Our current focus is on 200,000 acres in the southern part of the field where we plan to drill 30 to 35 wells by year end.”

Sheffield continued, “Our deeper vertical drilling program in the Spraberry field continues to successfully add incremental production and proved reserves from completions in the Strawn, Atoka and Mississippian intervals. Production data now supports an incremental expected ultimate recovery (EUR) of 30 MBOE for wells completed in the Strawn. This data also suggests that Atoka and Mississippian can potentially deliver incremental EURs of 50 MBOE to 70 MBOE and 15 MBOE to 40 MBOE, respectively.”

“Owning fracture stimulation fleets continues to enhance the execution of our drilling program and provide significant cash savings versus contracting for these services at market rates. By mid-2012, our fleet capacity will reach 300,000 in total horsepower.”

“Pioneer has a strong financial position, with a net debt-to-book capitalization of 26% as of December 31, 2011, and is committed to maintaining net debt-to-book capitalization below 35% and net debt to operating cash flow at less than 1.75 times. Standard and Poor’s recently upgraded Pioneer to investment grade.”

Mark-to-Market Derivative Losses and Unusual Items Included in Fourth Quarter 2011 Earnings

Pioneer’s fourth quarter results included unrealized mark-to-market losses on derivatives of $22 million after tax, or $0.18 per diluted share.

Pioneer’s fourth quarter results also included a net loss of $236 million after tax, or $1.94 per diluted share, related to unusual items. These unusual items included:

  • a noncash charge of $223 million after tax, or $1.83 per diluted share, for the impairment of dry gas properties in the Company’s legacy Edwards trend play in South Texas as a result of the current low gas price environment (no impairment of the Eagle Ford Shale),
  • a noncash charge of $20 million after tax, or $0.16 per diluted share, for the abandonment of unproved dry gas acreage and
  • Alaska Petroleum Production Tax (PPT) credits of $7 million after tax, or $0.05 per diluted share.

Pioneer’s fourth quarter results also included income of $15 million after tax, or $0.10 per diluted share, related to unwinding certain oil and gas derivatives.

Operations Update and Drilling Program

In the Spraberry oil field in West Texas, Pioneer is currently operating 44 rigs, of which 41 are drilling vertical wells (including 15 Company-owned rigs) and three are drilling horizontal wells. The Company drilled 690 wells in 2011 and placed 640 wells on production. The Company has continued to expand its integrated services to control drilling costs and support the execution of its drilling program. Five Company-owned fracture stimulation fleets totaling 100,000 horsepower are currently operating in the Spraberry field supporting vertical drilling operations. An additional 10,000 horsepower will be added to these five fleets by mid-year. Two additional fleets totaling 60,000 horsepower will be added by mid-year 2012 to support Pioneer’s horizontal drilling program in the Wolfcamp Shale. The Company also owns other oil field service equipment, including pulling units, fracture stimulation tanks, water transport trucks, hot oilers, blowout preventers, construction equipment and fishing tools. In addition, the Company has contracted for tubular and pumping unit requirements through 2012 and well cementing services through 2016.

The Company recently completed its second successful horizontal well in the Upper/Middle Wolfcamp Shale in Upton County, Texas with a 30-stage fracture stimulation in a 5,800-foot lateral section. The XBC Giddings Estate 2073H exhibited a 24-hour initial production rate of 807 BOEPD (602 barrels oil per day, 142 barrels of natural gas liquids (NGLs) per day and 382 thousand cubic feet (MCF) of gas per day) and a peak 30-day average natural flow rate of 677 BOEPD (504 barrels oil per day, 119 barrels NGLs per day and 321 MCF per day). Pioneer’s micro-seismic analysis of the completion showed that the entire 800-foot thick target zone was successfully fracture stimulated. The well continues to flow naturally and is producing to sales.

This well is performing similarly to the Company’s first horizontal well in Upton County (XBC Giddings Estate 2041) announced in 2011. Both had peak 30-day average natural flow rates well above 600 BOEPD. The first well continues to flow naturally and produced 45 MBOE over its first 90 days of production, which is seven times the production from a Spraberry vertical well (40-acre Lower Wolfcamp well with an EUR of 140 MBOE) over the same time period.

The results of the two Upton County horizontal wells are encouraging, as they are 60 miles northwest of the area where most of the recent successful industry horizontal Wolfcamp Shale drilling has been occurring. Based on this successful drilling activity and Pioneer’s extensive geologic interpretation of the Upper/Middle Wolfcamp Shale, the Company believes it has significant horizontal potential within its acreage. Pioneer is the largest acreage holder in the play with more than 400,000 prospective acres.

The Company’s current focus is on 200,000 acres in the southern part of the field to hold expiring acreage. Pioneer has not been drilling vertical Spraberry wells in this area because the returns are marginal. Current plans call for drilling 80 to 90 horizontal wells in this area by the end of 2013, with 30 to 35 horizontal wells being drilled in 2012.

The Company has recently increased its horizontal rig count from one to three rigs in the play, with plans to increase to seven rigs by the end of this year and a further increase in 2013. Two wells are currently being drilled in southern Reagan County and a third has been spud in southern Upton County. All three wells will be testing longer laterals and additional fracture stimulation stages.

The Company continues to drill vertically to deeper intervals in the Spraberry field below the Wolfcamp interval (40-acre type curve EUR of 140 MBOE). This deeper drilling includes the Strawn, Atoka and Mississippian intervals.

Pioneer completed 246 vertical wells in the Strawn interval in 2011. Cumulative production from these wells has increased by more than 25% compared to offset wells that have been drilled only to the Lower Wolfcamp. This data supports an incremental gross EUR per well from the Strawn interval of 30 MBOE. Pioneer believes this interval is prospective on 50% to 60% of its Spraberry acreage.

The Company completed 18 vertical Atoka wells during 2011. Early results and offset well data suggest a potential incremental gross EUR of 50 MBOE to 70 MBOE for wells completed in this interval. Based on drilling by other operators, it may be attractive to drill horizontal wells in this interval. Pioneer believes the Atoka interval is prospective on 25% to 50% of its Spraberry acreage.

Four vertical wells were also completed in the Mississippian interval during 2011. Early results and offset well data indicate a potential incremental gross EUR per well of 15 MBOE to 40 MBOE. Pioneer believes the Mississippian interval is prospective in 20% of its Spraberry acreage.

Pioneer’s 2012 Spraberry vertical drilling program calls for approximately 750 wells to be drilled. This assumes that Pioneer’s vertical rig count will decline from 41 rigs currently to 30 rigs by year end as its horizontal rig count in the Wolfcamp Shale increases from 3 rigs currently to 7 rigs by year end. In approximately 50% of the 750 vertical wells, the Wolfcamp will be the deepest interval completed. Of the remaining 50% of the wells, 20% will be deepened to the Strawn, 20% to the Atoka and 10% to the Mississippian.

Fourth quarter production from the Spraberry field averaged 53 MBOEPD, an increase of 7 MBOEPD from the third quarter. Based on the vertical and horizontal drilling programs described above, production is forecasted to grow from an average of 45 MBOEPD in 2011 to 61 MBOEPD to 65 MBOEPD in 2012. Assuming the vertical rig count remains at 30 rigs in 2013 and 2014, and the horizontal rig count increases to 10 rigs during this time period, production is forecasted to further increase to 81 MBOEPD to 87 MBOEPD in 2013 and 96 MBOEPD to 103 MBOEPD in 2014. The current blended Pioneer and third-party well cost for the vertical drilling program averages $1.7 million to $1.8 million per well, ranging from $1.6 million to $1.7 million for a well drilled to the Wolfcamp interval, $1.65 million to $1.75 million to the Strawn interval and $1.9 million to $2.0 million to the Atoka or Mississippian intervals. Pioneer’s internal rate of return on its 2012 Spraberry vertical drilling program is expected to be 45% to 50% before tax, based on the drilling program and gross EURs described above, and assuming flat commodity prices of $100 per barrel for oil and $4 per MCF for gas.

The Company continues to test vertical downspacing in the Spraberry field from 40 acres to 20 acres. Eighteen 20-acre vertical wells were drilled in 2010 and sixteen were added during 2011. These 20-acre wells were mostly drilled to the Lower Wolfcamp with a few completed in the Strawn. Results continue to indicate that production from these wells is performing near the type curve for a 40-acre Lower Wolfcamp well (EUR of 140 MBOE). The Company expects to drill approximately fifty 20-acre wells in its 2012 drilling program.

Water injection was initiated in the third quarter of 2010 on the Company’s 7,000-acre waterflood project in the Upper Spraberry interval. Results continue to be encouraging, as the production decline from 110 producing wells in the surveillance area has flattened and an increasing uptick in production continues to be observed as additional wells respond to water injection. Cumulative production from the area flooded in the Upper Spraberry has increased by greater than 15% compared to the forecasted base production decline, with further increases and reserve additions expected.

In the liquids-rich Eagle Ford Shale in South Texas, Pioneer and its joint venture partners are currently running 12 rigs. The Company drilled 111 wells in 2011 and placed 92 wells on production. To improve the execution of its drilling and completions program and reduce costs, Pioneer is operating two Company-owned fracture stimulation fleets totaling 100,000 horsepower. The Company is also utilizing a dedicated third-party fracture stimulation fleet, which commenced operating in April 2011 under a two-year contract.

Pioneer plans to continue running 12 rigs in 2012 and drill approximately 125 wells. The 2012 drilling program will continue to focus on liquids-rich drilling, with only 15% of the wells designated to hold strategic dry gas acreage. The original plan for 2012 called for an increase to 14 rigs on the assumption that 25% of the program would target dry gas drilling. However, in response to the current low gas price environment, the increase to 14 rigs has been delayed until 2013. It is now planned that the rig count will increase to 16 rigs in 2014 and 19 rigs in 2015.

Pioneer increased its Eagle Ford Shale production from 14 MBOEPD in the third quarter to 20 MBOEPD in the fourth quarter. The Company expects production to increase from an average of 12 MBOEPD in 2011 to 25 MBOEPD to 29 MBOEPD in 2012, 37 MBOEPD to 41 MBOEPD in 2013 and 47 MBOEPD to 53 MBOEPD in 2014.

Pioneer’s gross well cost in the Eagle Ford Shale ranges from $7 million to $8 million per well. Using this well cost, estimated EURs, assumed flat commodity prices of $100 per barrel for oil and $4 per MCF for gas and excluding the benefit of the joint-venture drilling carry, the before-tax internal rate of return for the 2012 drilling program is estimated to be 70%.

Pioneer has been testing the use of lower-cost white sand instead of ceramic proppant to fracture stimulate wells drilled in shallower areas of the field. Twenty-five wells have been tested to date, with a savings of approximately $700 thousand per well. Early well performance has been similar to direct offset ceramic-stimulated wells. Pioneer plans to continue to monitor the performance of these wells and plans to use white sand in 50% of its 2012 drilling program.

Eight central gathering plants (CGPs) have been completed as part of the joint venture’s Eagle Ford Shale midstream business. Three additional CGPs are planned for 2012. Pioneer’s share of its Eagle Ford Shale joint-venture midstream activities is conducted through a partially-owned, unconsolidated entity. Funding for ongoing midstream infrastructure build-out costs that are in excess of operating cash flow is provided from external debt sources. 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 has built a 78,000 net acreage position, representing more than 1,000 drilling locations. The Company drilled 43 wells in 2011 and placed 42 wells on production. Pioneer operated two rigs in the play for much of 2011 and plans to remain at this level through 2012. The Company expects to increase to four rigs in 2013.

Production in the fourth quarter for the Barnett Shale Combo play was 6 MBOEPD, up from 4 MBOEPD in the third quarter. The Company expects production to increase from an average of 4 MBOEPD in 2011 to 7 MBOEPD to 9 MBOEPD in 2012 under the current two-rig program. With the expected increase to four rigs in 2013, production is forecasted to grow to 12 MBOEPD to 16 MBOEPD in 2013 and 18 MBOEPD to 23 MBOEPD in 2014. Production is comprised of 60% liquids (oil and NGLs) and 40% gas.

Pioneer’s internal rate of return in the Barnett Shale Combo play is expected to be 30% before tax. This assumes a targeted per-well drilling cost of $3.5 million for 5,000-foot lateral wells, a gross EUR of 460 MBOE and flat commodity prices of $100 per barrel for oil and $4 per MCF for gas. The internal rate of return has been impacted by the low gas price environment.

On the North Slope of Alaska, Pioneer will continue to operate one rig and drill development wells from its island targeting the Kuparuk, Nuiqsut and Torok intervals. During the current winter drilling season, the Company has contracted a second rig to drill two exploration wells within Pioneer’s acreage that cannot be reached from the island. One will be to test the Torok interval, while the second will be to test the deeper Ivishak interval. The latter is the main producing zone in the Prudhoe Bay field.

2012 Capital Budget

Pioneer’s capital program for 2012 of $2.5 billion (excludes acquisitions, asset retirement obligations, capitalized interest and geological and geophysical G&A) continues to be focused on liquids-rich drilling. The following provides a breakdown of the forecasted spending by asset:

  • Spraberry Vertical - $1,525 million (includes $100 million for infrastructure)
  • Horizontal Wolfcamp Shale - $275 million (includes $25 million for seismic and coring)
  • Eagle Ford Shale - $130 million (net of carry from Reliance Industries Limited )
  • Barnett Shale Combo play - $215 million
  • Alaska - $135 million
  • Other - $120 million, including land capital for existing assets
  • Vertical Integration - $100 million

2012 Capital Budget Funding and Balance Sheet

The 2012 capital budget is expected to be funded from forecasted operating cash flow of $2.2 billion, assuming commodity prices of $100 per barrel for oil and $3 per MCF for gas and using $0.3 billion of the proceeds from Pioneer’s recent equity offering.

Pioneer’s year-end 2011 net debt (reduced for cash on Pioneer’s balance sheet) was $2.0 billion, a reduction from $2.4 billion at year-end 2010. With Pioneer’s improving net debt position, net debt-to-book capitalization declined from 37% at year-end 2010 to 26% at year-end 2011. The Company is committed to keeping its net debt-to-book capitalization below 35% and net debt to operating cash flow below 1.75 times.

Fourth Quarter 2011 Financial Review

The following financial results for the fourth quarter of 2011 reflect continuing operations and exclude the results of operations attributable to South Africa that are included in discontinued operations.

Sales averaged 137 MBOEPD, consisting of oil sales averaging 50 thousand barrels per day (MBPD), NGL sales averaging 26 MBPD and gas sales averaging 362 million cubic feet per day (MMCFPD).

The average reported price for oil was $95.75 per barrel and included $2.45 per barrel related to deferred revenue from volumetric production payments (VPPs) for which production was not recorded. The average reported price for NGLs was $45.70 per barrel and the average reported price for gas was $3.37 per MCF.

Production costs averaged $13.79 per barrel oil equivalent (BOE). Depreciation, depletion and amortization (DD&A) expense averaged $14.49 per BOE.

Noncash impairment charges related to dry gas properties in the Company’s legacy Edwards trend play in South Texas totaled $354 million for the quarter (no impairment of the Eagle Ford Shale). The impairment charges resulted from the current low gas price environment. Exploration and abandonment costs were $64 million for the quarter including unusual items. This included $41 million of acreage abandonments, of which $31 million was associated with unproved dry gas acreage that is not planned to be drilled in the current low gas price environment (unusual item), and $23 million of geologic and geophysical expenses and personnel costs.

First Quarter 2012 Financial Outlook

The Company’s first quarter 2012 outlook for certain operating and financial items (excluding discontinued operations in South Africa) is provided below.

Production is forecasted to average 141 MBOEPD to 146 MBOEPD. Production costs are expected to average $13.00 to $15.00 per BOE, based on current NYMEX strip commodity prices. DD&A expense is expected to average $13.00 to $15.00 per BOE. Total exploration and abandonment expense is forecasted to be $35 million to $60 million, including the potential dry hole costs associated with the two exploration wells in Alaska.

General and administrative expense is expected to be $49 million to $54 million, interest expense is expected to be $45 million to $49 million and other expense is expected to be $20 million to $30 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 $9 million to $12 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 $2 million to $5 million and are primarily attributable to state taxes.

The Company's financial and derivative mark-to-market results, open derivatives positions for oil, NGL and gas, and future VPP amortization are outlined on the attached schedules.

Earnings Conference Call

On Tuesday, February 7, 2012, at 9:00 a.m. Central Time, Pioneer will discuss its financial and operating results for the quarter ended December 31, 2011, 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 Calls & Webcasts” to listen to the discussion and view the presentation.

Telephone: Dial (877) 856-1965 confirmation code: 7754248 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 February 28 by dialing (888) 203-1112 confirmation code: 7754248.

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

Except for historical information contained herein, the statements in this news release are forward-looking statements that are made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause Pioneer's actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties include, among other things, volatility of commodity prices, product supply and demand, competition, the ability to obtain environmental and other permits and the timing thereof, other government regulation or action, the ability to obtain approvals from third parties and negotiate agreements with third parties on mutually acceptable terms, litigation, the costs and results of drilling and operations, availability of equipment, services and personnel required to complete the Company’s operating activities, access to and availability of transportation, processing 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, international operations 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.

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 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.

“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.

               

PIONEER NATURAL RESOURCES COMPANY

 

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)

 

  December 31,

2011

 

 December 31,

2010

ASSETS
Current assets:
Cash and cash equivalents $ 537,484 $ 111,160
Accounts receivable, net 283,813 245,303
Income taxes receivable 3 30,901
Inventories 241,609 173,615
Prepaid expenses 14,263 11,441
Deferred income taxes 77,005 156,650
Discontinued operations held for sale 73,349 281,741
Derivatives 238,835 171,679
Other current assets, net   12,936     14,693  
 
Total current assets   1,479,297     1,197,183  
 
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting 12,249,332 10,930,226
Accumulated depletion, depreciation and amortization   (3,648,465 )   (3,366,440 )
 
Total property, plant and equipment   8,600,867     7,563,786  
 
Goodwill 298,142 298,182
Other property and equipment, net 573,075 283,542
Investment in unconsolidated affiliate 169,532 72,045
Derivatives 243,240 151,011
Other assets, net   160,008     113,353  
 
$ 11,524,161   $ 9,679,102  
 
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 716,211 $ 419,150
Interest payable 57,240 59,008
Income taxes payable 9,788 19,168
Deferred income taxes - 1,144
Discontinued operations held for sale 75,901 108,592
Deferred revenue 42,069 44,951
Derivatives 74,415 80,997
Other current liabilities   36,174     36,210  
 
Total current liabilities   1,011,798     769,220  
 
Long-term debt 2,528,905 2,601,670
Deferred income taxes 2,077,164 1,751,310
Deferred revenue - 42,069
Derivatives 33,561 56,574
Other liabilities 221,595 232,234
Stockholders' equity   5,651,138     4,226,025  
 
$ 11,524,161   $ 9,679,102  
                 

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,

2011 2010 2011 2010
Revenues and other income:
Oil and gas $ 664,776 $ 453,981 $ 2,294,063 $ 1,718,297
Interest and other 33,812 10,326 101,960 56,972
Derivative gains (losses), net 6,634 (122,151 ) 392,752 448,434
Gain (loss) on disposition of assets, net (2,205 ) (7,897 ) (3,644 ) 19,074
Hurricane activity, net   36     133,240     1,454     138,918  
  703,053     467,499     2,786,585     2,381,695  
Costs and expenses:
Oil and gas production 133,521 86,607 453,085 364,764
Production and ad valorem taxes 39,962 26,697 147,664 112,141
Depletion, depreciation and amortization 182,288 122,717 607,405 499,856
Impairment of oil and gas properties 354,408 - 354,408 -
Exploration and abandonments 64,078 128,824 121,320 189,597
General and administrative 55,347 42,905 193,215 164,332
Accretion of discount on asset retirement obligations 2,092 1,902 8,256 7,945
Interest 45,878 45,191 181,660 183,084
Other   16,195     30,313     63,166     78,404  
  893,769     485,156     2,130,179     1,600,123  
 
Income (loss) from continuing operations before income taxes (190,716 ) (17,657 ) 656,406 781,572
Income tax benefit (provision)   75,272     39,264     (197,644 )   (269,627 )
Income (loss) from continuing operations (115,444 ) 21,607 458,762 511,945
Income from discontinued operations, net of tax   2,256     60,519     423,152     134,050  
Net income (loss) (113,188 ) 82,126 881,914 645,995

Net (income) loss attributable to the noncontrolling interests

  2,042     (1,784 )   (47,425 )   (40,787 )
Net income (loss) attributable to common stockholders $ (111,146 ) $ 80,342   $ 834,489   $ 605,208  
 
Basic earnings per share:

Income (loss) from continuing operations attributable to common

stockholders

$ (0.95 ) $ 0.17 $ 3.45 $ 4.00
Income from discontinued operations attributable to common

stockholders

 

  0.02     0.51     3.56     1.14  
Net income (loss) attributable to common stockholders $ (0.93 ) $ 0.68   $ 7.01   $ 5.14  
 
Diluted earnings per share:

Income (loss) from continuing operations attributable to common

stockholders

$ (0.95 ) $ 0.17 $ 3.39 $ 3.96
Income from discontinued operations attributable to common
stockholders   0.02     0.50     3.49     1.12  
Net income (loss) attributable to common stockholders $ (0.93 ) $ 0.67   $ 6.88   $ 5.08  
 
Weighted average shares outstanding:
Basic   119,223     115,289     116,904     115,062  
Diluted   119,223     117,825     119,215     116,330  
     

PIONEER NATURAL RESOURCES COMPANY

 

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

 
  Three Months Ended

December 31,

 

Twelve Months Ended

December 31,

2011   2010   2011   2010
Cash flows from operating activities:
Net income (loss) $ (113,188) $ 82,126

 

$

881,914 $ 645,995
Adjustments to reconcile net income (loss) to net cash provided by
operating activities:
Depletion, depreciation and amortization 182,288 122,717 607,405 499,856
Impairment of oil and gas properties 354,408 - 354,408 -
Exploration expenses, including dry holes 41,223 116,117 47,231 132,772
Hurricane activity, net - 1,008 - 4,508
Deferred income taxes (76,423) (39,633) 188,579 259,763
(Gain) loss on disposition of assets, net 2,205 7,897 3,644 (19,074)
Accretion of discount on asset retirement obligations 2,092 1,902 8,256 7,945
Discontinued operations 9,436 (12,147) (376,717) 77,158
Interest expense 8,071 7,905 31,483 30,472
Derivative related activity 47,847 129,578 (221,899) (419,809)
Amortization of stock-based compensation 9,917 11,223 41,442 39,854
Amortization of deferred revenue (11,331) (22,477) (44,951) (90,216)
Other noncash items (7,122) 16,182 (22,412) 25,102
Change in operating assets and liabilities:
Accounts receivable, net (12,079) (61,220) (47,331) 36,653
Income taxes receivable 818 (22,567) 29,406 (5,878)
Inventories (21,440) (19,822) (137,401) (26,281)
Prepaid expenses 4,143 5,101 (3,415) (3,874)
Other current assets (6,563) (16,432) 1,957 (14,270)
Accounts payable 52,664 66,578 136,296 128,927
Interest payable 23,285 25,210 (1,768) 11,999
Income taxes payable (5,816) 2,700 (7,623) 4,007
Other current liabilities   15,241   (18,645)   61,210   (40,586)
Net cash provided by operating activities 499,676 383,301 1,529,714 1,285,023
 
Net cash used in investing activities (705,934) (390,654) (1,560,787) (954,856)
Net cash provided by (used in) financing activities   533,177   40,348   457,397   (246,375)
Net increase in cash and cash equivalents 326,919 32,995 426,324 83,792
Cash and cash equivalents, beginning of period   210,565   78,165   111,160   27,368
Cash and cash equivalents, end of period $ 537,484 $ 111,160

 

$

537,484 $ 111,160
                   

PIONEER NATURAL RESOURCES COMPANY

 

UNAUDITED SUMMARY PRODUCTION AND PRICE DATA

 
Three Months Ended

December 31,

Twelve Months Ended

December 31,

2011   2010 2011   2010
Average Daily Sales Volumes
from Continuing Operations:
Oil (Bbls) - U.S. 50,231 30,650 40,618 28,211
 
Natural gas liquids ("NGL") (Bbls) - U.S. 26,163 19,992 22,487 19,736
 
Gas (Mcf) - U.S. 361,829 333,170 343,879 335,256
 
Total (BOE) - U.S. 136,699 106,172 120,418 103,823
 
Average Daily Sales Volumes
from Discontinued Operations:
Oil (Bbls) - South Africa 452 280 530 616
Tunisia   -   4,984   547   4,880
Total   452   5,264   1,077   5,496
 
Gas (Mcf) - South Africa 15,186 28,143 20,570 29,760
Tunisia   -   3,258   496   2,849
Total   15,186   31,401   21,066   32,609
 
Total (BOE) - South Africa 2,983 4,970 3,958 5,576
Tunisia   -   5,527   630   5,355
Total   2,983   10,497   4,588   10,931
 
Average Reported Prices (a):
Oil (per Bbl) - U.S. $ 95.75 $ 94.48 $ 96.60 $ 90.56
 

NGL (per Bbl) -

U.S. $ 45.70 $ 42.03 $ 46.27 $ 38.14
 
Gas (per Mcf) - U.S. $ 3.37 $ 3.60 $ 3.84 $ 4.18
 
Total (BOE) - U.S. $ 52.86 $ 46.48 $ 52.19 $ 45.34

__________

(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, GAAP provides 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 (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 Company's diluted net income (loss) per share attributable to common stockholders is computed as (i) basic net income (loss) attributable to common stockholders, (ii) plus the reallocation of participating earnings (iii) divided by weighted average diluted shares outstanding. During periods in which the Company realizes a loss from continuing operations attributable to common stockholders, securities or other contracts to issue common stock would be dilutive to loss per share; therefore, conversion into common stock is assumed not to occur.

The following table is a reconciliation of the Company's net income (loss) attributable to common stockholders to basic 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, 2011 and 2010:

      Three Months Ended

December 31,

 

Twelve Months Ended

December 31,

2011     2010   2011     2010  
(in thousands)
 
Net income (loss) attributable to common stockholders $ (111,146 ) $ 80,342 $ 834,489 $ 605,208
Participating basic earnings   (116 )   (1,914 )   (15,178 )   (13,896 )
Basic net income (loss) attributable to common stockholders (111,262 ) 78,428 819,311 591,312
Reallocation of participating earnings   -     38     385     180  
Diluted net income (loss) attributable to common stockholders $ (111,262 ) $ 78,466   $ 819,696   $ 591,492  

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, 2011 and 2010:

          Three Months Ended

December 31,

 

Twelve Months Ended

December 31,

2011   2010 2011   2010
(in thousands)
 
Weighted average common shares outstanding:
Basic 119,223 115,289 116,904 115,062
Dilutive common stock options - 200 190 212
Contingently issuable performance unit shares - 697 424 646
Convertible senior notes dilution - 1,639 1,697 410
 
Diluted 119,223 117,825 119,215 116,330
 

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

              Three Months Ended

December 31,

   

Twelve Months Ended

December 31,

  2011     2010 2011     2010
 
Net income (loss) $ (113,188) $ 82,126 $ 881,914 $ 645,995
Depletion, depreciation and amortization 182,288 122,717 607,405 499,856
Impairment of oil and gas properties 354,408 - 354,408 -
Exploration and abandonments 64,078 128,824 121,320 189,597
Hurricane activity, net (36) (133,240) (1,454) (138,918)
Accretion of discount on asset retirement obligations 2,092 1,902 8,256 7,945
Interest expense 45,878 45,191 181,660 183,084
Income tax (benefit) provision (75,272) (39,264) 197,644 269,627
(Gain) loss on disposition of assets, net 2,205 7,897 3,644 (19,074)
Discontinued operations (2,256) (60,519) (423,152) (134,050)
Derivative related activity 47,847 129,578 (221,899) (419,809)
Amortization of stock-based compensation 9,917 11,223 41,442 39,854
Amortization of deferred revenue (11,331) (22,477) (44,951) (90,216)
Other noncash items   (7,122)   16,182   (22,412)   25,102
 
EBITDAX (a) 499,508 290,140 1,683,825 1,058,993
 
Cash interest expense (37,807) (37,286) (150,177) (152,612)
Current income taxes   (1,151)   (369)   (9,065)   (9,864)
 
Discretionary cash flow (b) 460,550 252,485 1,524,583 896,517
 
Cash hurricane activity 36 134,248 1,454 143,426
Discontinued operations cash activity 11,692 48,372 46,435 211,208
Cash exploration expense (22,855) (12,707) (74,089) (56,825)
Changes in operating assets and liabilities   50,253   (39,097)   31,331   90,697
 
Net cash provided by operating activities $ 499,676 $ 383,301 $ 1,529,714 $ 1,285,023

__________

(a)  

“EBITDAX” represents earnings before depletion, depreciation and amortization expense; impairment of oil and gas

properties; exploration and abandonments; net hurricane activity; unrealized mark-to-market derivative activity; accretion

of discount on asset retirement obligations; interest expense; income taxes; (gain) loss on the disposition of assets, net;

discontinued operations; 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, cash activity reflected in discontinued operations and hurricane activity, and cash exploration expense.
 
 
 

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY NON-GAAP FINANCIAL MEASURES (continued)

(in millions, except per share data)

Adjusted loss excluding unrealized mark-to-market ("MTM") derivative losses, and loss adjusted for unrealized MTM losses and unusual items, as presented in this press release, are presented and reconciled to Pioneer's net loss attributable to common stockholders that is determined in accordance with GAAP because Pioneer believes that these non-GAAP financial measures reflect additional ways of viewing aspects of Pioneer's 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 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 loss attributable to common stockholders for the three months ended December 31, 2011, as determined in accordance with GAAP, to adjusted loss excluding unrealized MTM derivative losses, and adjusted income excluding MTM derivative losses and unusual items, for that quarter,

             

After-tax

Amounts

   

Diluted

Amounts Per

Share

 
Net loss attributable to common stockholders $ (111) $ (0.93)
Unrealized MTM derivative losses   22   0.18
Adjusted loss excluding unrealized MTM derivative losses (89) (0.75)
 
Alaska production tax credit recoveries (7) (0.05)
Impairment of dry gas properties in South Texas 223 1.83
Abandonment of unproved dry gas acreage   20   0.16
Adjusted income excluding unrealized MTM derivative losses and unusual items $ 147 $ 1.19
                         

PIONEER NATURAL RESOURCES COMPANY

SUPPLEMENTAL INFORMATION

Open Commodity Derivative Positions as of February 3, 2012

(Volumes are average daily amounts)

 
Twelve Months Ending December 31,
     
2012 2013 2014 2015
 
Average Daily Oil Production Associated with
Derivatives (Bbls):
Swap Contracts:
Volume 3,000 3,000 - -
Price $ 79.32 $ 81.02 $ - $ -
Collar Contracts:
Volume 2,000 - - -
Price:
Ceiling $ 127.00 $ - $ - $ -
Floor $ 90.00 $ - $ - $ -
Collar Contracts with Short Puts:
Volume 41,610 39,000 17,000 -
Price:
Ceiling $ 118.24 $ 118.96 $ 122.92 $ -
Floor $ 82.36 $ 85.08 $ 88.53 $ -
Short Put $ 66.52 $ 67.00 $ 71.47 $ -
Average Daily NGL Production Associated with
Derivatives (Bbls):
Swap Contracts:
Volume 750 - - -
Index price (a) $ 35.03 $ - $ - $ -
Collar Contracts with Short Puts:
Volume 3,000 - - -
Index price (a):
Ceiling $ 79.99 $ - $ - $ -
Floor $ 67.70 $ - $ - $ -
Short Put $ 55.76 $ - $ - $ -
Average Daily Gas Production Associated with
Derivatives (MMBtu):
Swap Contracts:
Volume 200,000 112,500 50,000 -
Price (b) $ 5.17 $ 5.62 $ 6.05 $ -
Collar Contracts:
Volume 65,000 150,000 140,000 50,000
Price (b):
Ceiling $ 6.60 $ 6.25 $ 6.44 $ 7.92
Floor $ 5.00 $ 5.00 $ 5.00 $ 5.00
Collar Contracts with Short Puts:
Volume 75,000 - 60,000 30,000
Price (b):
Ceiling $ 7.01 $ - $ 7.80 $ 7.11
Floor $ 6.01 $ - $ 5.83 $ 5.00
Short Put $ 4.50 $ - $ 4.42 $ 4.00
Basis Swap Contracts:
Permian Basin Index Swaps volume (c) 32,500 52,500 45,000 -
Price differential ($/MMBtu) $ (0.38) $ (0.23) $ (0.27) $ -
Mid-Continent Index Swaps volume (c) 50,000 30,000 30,000 -
Price differential ($/MMBtu) $ (0.53) $ (0.38) $ (0.27) $ -
Gulf Coast Index Swaps volume (c) 53,500 60,000 40,000 -
Price differential ($/MMBtu) $ (0.15) $ (0.14) $ (0.16) $ -

__________

(a)   Represents weighted average index price per Bbl of each NGL component.
(b) Represents the NYMEX Henry Hub index price or approximate NYMEX Henry Hub index price based on historical differentials to the index price on the derivative trade date.
(c)

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 contracts.

Permian Basin roll adjustment swap derivatives. The Company uses ''roll adjustment'' swap derivatives to mitigate the timing risk associated with the sales price of oil in the Permian Basin. In the Permian Basin, the Company generally sells its oil at a sales price based on the calendar month average NYMEX price of oil during that month, plus an adjustment calculated as the weighted average spread between the NYMEX price for that delivery month and (i) the next month and (ii) the following month during the period when the delivery month is prompt. The Company has roll adjustment swap derivatives for 3,000 Bbls per day of March 2012 through May 2012 oil sales and for 3,000 Bbls per day of oil sales for the year 2013. Under the terms of the roll adjustment swap derivatives, the Company pays the periodic variable roll adjustments and receives a fixed price of $0.28 per Bbl for March 2012 through May 2012 and $0.43 per Bbl for the year 2013. The Permian Basin roll adjustment swap derivatives are not included in the table presented above.

Diesel price derivatives. The Company has 250 Bbls of diesel derivative swap contracts for 2012 at an average per Bbl fixed price of $119.70. The diesel derivative swap contracts are priced at an index that is highly correlated to the prices that the Company incurs to fuel its drilling rigs and fracture stimulation fleet equipment. The Company purchases diesel derivative swap contracts to mitigate fuel price risk. The Company's diesel derivative swap contracts are not included in the table presented above.

Interest rates. The Company has interest rate derivative contracts that lock in, through August 2012, a fixed forward 10-year annual interest rate of 3.06% on $200 million notional amount of debt.

           

PIONEER NATURAL RESOURCES COMPANY

 

SUPPLEMENTAL INFORMATION

Amortization of Deferred Revenue Associated with Volumetric Production Payments and Derivative Losses

as of December 31, 2011

(in thousands)

 
2012

First

Quarter

 

Second

Quarter

 

Third

Quarter

 

Fourth

Quarter

Total
 
Total deferred revenues (a) $ 10,459 $ 10,460 $ 10,575 $ 10,575 $ 42,069
Less derivative losses to be recognized in
pretax earnings (b)   (810)   (791)   (784)   (773)   (3,157)
 
Total VPP impact to pretax earnings $ 9,649 $ 9,669 $ 9,791 $ 9,802 $ 38,912

__________

(a)   Deferred revenue will be amortized as increases to oil revenues during the indicated future periods.
(b) Represents the remaining pretax earnings impact of the derivatives assigned in the VPPs.
                   

Derivative Gains, Net

(in thousands)

 

Three Months Ended

December 31, 2011

Twelve Months Ended

December 31, 2011

Noncash changes in fair value:
Oil derivative gains (losses) $ (188,726) $ 68,376
NGL derivative gains 10,055 10,243
Gas derivative gains 133,832 179,787
Diesel derivative gains 888 270
Interest rate derivative losses   (2,990)   (33,206)
Total noncash derivative gains (losses), net (a)   (46,941)   225,470
 
Cash settled changes in fair value:
Oil derivative losses (1,358) (36,664)
NGL derivative losses (3,615) (15,418)
Gas derivative gains 58,538 182,993
Diesel derivative gains 10 67
Interest rate derivative gains   -   36,304
Total cash derivative gains, net   53,575   167,282
Total derivative gains, net $ 6,634 $ 392,752

__________

(a)  

Total unrealized mark-to-market derivative gains, net includes $12.8 million of loss and $7.2 million of gains attributable

to noncontrolling interests in consolidated subsidiaries during the three and twelve months ended December 31, 2011,

respectively.

Source: Pioneer Natural Resources Company

Pioneer Natural Resources
Investors:
Frank Hopkins, 972-969-4065
or
Eric Pregler, 972-969-5756
or
Media and Public Affairs:
Susan Spratlen, 972-969-4018
or
Suzanne Hicks, 972-969-4020

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