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Pioneer Natural Resources Reports Second Quarter 2012 Financial and Operating Results

DALLAS--(BUSINESS WIRE)--Jul. 31, 2012-- Pioneer Natural Resources Company (NYSE:PXD) (“Pioneer” or “the Company”) today announced financial and operating results for the quarter ended June 30, 2012.

Pioneer reported a second quarter net loss attributable to common stockholders of $70 million, or $0.57 per diluted share (see attached schedule for a description of the net loss per diluted share calculation). Without the effect of noncash derivative mark-to-market gains and other unusual items, adjusted income for the second quarter was $98 million after tax, or $0.78 per share.

Second quarter and other recent highlights included:

  • producing 150.5 thousand barrels oil equivalent per day (MBOEPD) from continuing operations, an increase from the first quarter of 2012 of 4 MBOEPD, or 3%, as a result of continued production growth in the Company’s Spraberry, Eagle Ford Shale, Barnett Shale Combo and Alaska areas; this increase was delivered despite losing approximately 4,800 barrels oil equivalent per day (BOEPD) of production from the Spraberry field due to unplanned third-party natural gas liquids (NGL) fractionation downtime at Mont Belvieu, Texas, combined with NGL fractionation capacity limitations at Mont Belvieu, resulting in ethane rejection; had these third-party processing shortfalls not occurred, Pioneer’s production would have been approximately 155 MBOEPD, above the top of Pioneer’s guidance range for the second quarter of 149 MBOEPD to 154 MBOEPD,
  • increasing the Company’s annual production growth target range for 2012 from 23% - 25% to 25% - 29%, as strong drilling and well performance is expected to outweigh continuing ethane rejection and a decrease in drilling activity over the remainder of 2012,
  • drilling five additional successful wells in the southern portion of the horizontal Wolfcamp Shale play in West Texas and increasing the estimated ultimate recovery (EUR) for wells in this area to 575 thousand barrels oil equivalent (MBOE) for 7,000-foot laterals,
  • pursuing a joint venture partner to accelerate development of the horizontal Wolfcamp Shale play in the southern 200,000 acres of Pioneer’s total prospective acreage position,
  • delivering production outperformance from deeper vertical wells to the Strawn, Atoka and Mississippian intervals in the Spraberry field,
  • maintaining the Company’s 2012 drilling capital budget at $2.4 billion by reducing second half drilling activity in response to lower commodity prices,
  • liquidating gas derivatives in 2014 and 2015 for cash proceeds of $143 million,
  • adding 8 thousand barrels of oil per day (MBPD) of oil derivative swaps for August through December 2012 at $93.09 per barrel,
  • completing a successful 10-year senior note offering of $600 million at an interest rate of 3.95%, and
  • being upgraded to investment grade by Moody’s.

Scott Sheffield, Chairman and CEO, stated, “The Spraberry vertical play continued to outperform in the second quarter, while the Eagle Ford Shale and Barnett Shale Combo plays continued to deliver strong and consistent production growth as expected. Our early drilling results from the horizontal Wolfcamp Shale play are exceeding expectations and we expect this asset to significantly contribute to our production growth going forward. We estimate that the southern 200,000 acres of our Spraberry acreage position has more than 4,000 horizontal drilling locations with a gross resource potential of more than two billion barrels oil equivalent. In order to accelerate development and enhance the net asset value of this substantial oil resource, we will pursue a joint venture partner during the second half of 2012. We also plan to begin delineating horizontal Wolfcamp Shale potential on our northern acreage in the fourth quarter. Based on our success to date in the horizontal Wolfcamp Shale, we are increasing the Company’s net resource potential from five billion barrels oil equivalent to more than seven billion barrels oil equivalent.”

Mark-To-Market Derivative Gains and Unusual Items Included in Second Quarter 2012 Earnings

Pioneer’s second quarter earnings included unrealized mark-to-market gains on derivatives of $61 million after tax, or $0.49 per diluted share.

Second quarter earnings also included a net loss of $229 million after tax, or $1.84 per diluted share, related to unusual items. These unusual items included:

  • a noncash impairment charge of $280 million after tax, or $2.28 per diluted share, as a result of the lower commodity price environment not supporting the Company’s carrying value of its legacy Barnett Shale dry gas properties in Texas,
  • Spraberry field drilling rig termination fees of $6 million after tax, or $0.05 per diluted share, (reflected in Other Expense),
  • a realized gain of $45 million after tax, or $0.37 per diluted share, for 2014 gas derivatives that were liquidated in June,
  • income associated with discontinued operations in South Africa of $12 million after tax, or $0.10 per diluted share and
  • a $0.02 per diluted share impact of including two million incremental dilutive shares in computing adjusted income per share that, in accordance with GAAP, were not included in the net loss per diluted share computation because the Company reported a net loss for the second quarter of 2012.

Operations Update and Drilling Program

Pioneer is the largest acreage holder in the horizontal Wolfcamp Shale play where the Company believes it has significant resource potential based on its extensive geologic data covering the Wolfcamp A, B, C and D intervals and its successful drilling results to date as described below.

Pioneer’s first two successful horizontal Wolfcamp Shale wells were drilled in northern Upton County in the B interval to a depth of approximately 9,500 feet with stimulated lateral lengths of approximately 5,300 feet and 30 fracture stimulation stages each. The XBC Giddings Estate #2041H and the XBC Giddings Estate #2073H had peak 30-day average natural flow rates of 643 BOEPD and 673 BOEPD, respectively. Both wells continue to produce above expectations, with cumulative production of 107 MBOE and 83 MBOE after being on production for nine-and-one-half months and seven months, respectively. Of these produced volumes, approximately 75% was oil, 20% NGLs and 5% gas. The wells are currently producing at an average daily rate of 365 BOEPD per well. The two wells each have EURs of approximately 650 MBOE. Future wells drilled with longer lateral lengths in this area are expected to have significantly higher EURs. Although both wells flowed naturally until recently, the wells have recently been placed on artificial lift.

The Company placed five additional horizontal Wolfcamp wells on production during the second quarter in southern Upton and Reagan counties. These wells were drilled in the B interval at depths ranging from 7,600 feet to 8,400 feet and have stimulated lateral lengths ranging from 5,700 feet to 6,600 feet, with 32 to 37 fracture stimulation stages. All of the wells have been on production for more than 30 days and have delivered 30-day peak rates ranging from 332 BOEPD to 597 BOEPD, with oil content ranging from 77% to 90%. Production from these five wells has remained stable after the peak 30-day production periods. The production results for each well are shown below:

Well       Stimulated Lateral
Length (ft)
      Frac
Stages
      Peak 24-Hour IP
(BOEPD)
      Peak 30-Day IP
(BOEPD)
      % Oil
University 10-20 #4H       6,422       36       454       332       77%
University 10-19 #4H       6,422       36       671       499       87%
University 3-32 #4H       5,702       32       451       380       90%
University 3-31 #4H       5,882       33       485       404       90%
University 10-13 #5H       6,577       37       942       597       83%
                                         

The Company is very encouraged by the strong production rates and high oil content from its early drilling activity in the horizontal Wolfcamp Shale. Based on the strong production results to date and continuing petrophysical analysis, Pioneer believes its wells in southern Upton, Reagan and Irion counties, with a stimulated lateral length of 7,000 feet and 30 to 35 fracture stimulation stages, will have EURs of 575 MBOE, above the Company’s initial estimate of 350 MBOE to 500 MBOE. As the stimulated lateral lengths of the Company’s wells are increased to 7,000 feet and longer, higher production rates are expected and EURs may increase above 575 MBOE.

Pioneer’s drilling focus will continue to be the Company’s 200,000 acres in the southern part of the play to hold expiring acreage totaling 50,000 acres. Pioneer is currently drilling 4 additional horizontal Wolfcamp Shale wells and has 9 wells awaiting completion in this area. For the remainder of 2012, the Company plans to continue drilling in the B interval and to test the A interval in this area. Pioneer’s first two A interval wells have been drilled and are awaiting completion.

The Company expects to drill approximately 90 horizontal wells in the southern part of the play by the end of 2013 to hold expiring acreage, with 30 to 35 horizontal wells being drilled in 2012. During the fourth quarter of 2012, the Company plans to begin delineating the northern portion of its Spraberry acreage position by drilling in Midland, Martin and Gaines Counties. Wells drilled in these areas are expected to benefit from greater original oil in place and higher reservoir pressures associated with deeper drilling depths compared to the southern part of the play. Pioneer believes a successful drilling program in this area could substantially increase its prospective horizontal Wolfcamp Shale acreage position.

Pioneer currently has four horizontal rigs running in the play and plans to increase to seven rigs late in the fourth quarter of 2012. The horizontal wells to date have been drilled and completed with extra “science,” including coring, extensive logging and micro-seismic, resulting in well costs of $8 million to $9 million per well. In the second half of 2012, Pioneer is transitioning to “development” drilling, which is expected to lower well costs to $7 million per well for a 7,000-foot stimulated lateral with 35 to 40 fracture stimulation stages. This will include increasing utilization of Brady Brown® sand produced by the U.S. industrial sands business acquired by Pioneer in early April. Pioneer’s first two “development” wells are currently being drilled.

Pioneer plans to pursue a joint venture partner to accelerate the development of the horizontal Wolfcamp Shale in the southern 200,000 acres of the Company’s total prospective acreage position. Pioneer plans to offer a 33% to 50% working interest in the southern acreage, or 8% to 12% of the Company’s total acreage position. The acreage position being offered is estimated to have more than 4,000 potential horizontal development locations, with downspacing upside, and a total gross resource potential of more than two billion barrels oil equivalent. Wells in this area are expected to have oil content of more than 70% and EURs of 575 MBOE for 7,000-foot laterals.

Pioneer had originally planned to reduce the vertical drilling program in the Spraberry field from 40 rigs to 30 rigs during the second half of 2012 as the Company increased its horizontal rig count in the Wolfcamp Shale play. However, the recent decline in commodity prices has led to a reduction in the Company’s forecasted cash flow for 2012. This caused the Company to begin reducing its vertical drilling rig count to 30 rigs in June, slightly earlier than originally anticipated. A further reduction of up to 3 rigs is possible during the second half of 2012 if commodity prices remain under pressure.

The Company continues to drill vertically to deeper intervals in the Spraberry field below the Wolfcamp interval (vertical Wolfcamp 40-acre type curve EUR of 140 MBOE with a 24-hour initial production (“IP”) rate of 90 BOEPD). Production from this deeper drilling has exceeded expectations and is the primary contributor to the production outperformance by this asset in the first half of 2012. This deeper drilling includes the Strawn, Atoka and Mississippian intervals. The original 2012 drilling program called for the Wolfcamp to be the deepest interval completed in approximately 50% of the wells. The remaining 50% of the wells were to be deepened below the Wolfcamp interval. The latest drilling program now calls for 65% of the wells to be deepened below the Wolfcamp interval.

Pioneer placed 53 commingled vertical Strawn wells on production in the second quarter, with an average 24-hour IP rate of 147 BOEPD. Production data continues to support an incremental gross EUR per well from the Strawn interval of 30 MBOE. Pioneer now estimates that 70% of its Spraberry acreage position is prospective for the Strawn interval, at the upper end of the prior estimated range of 60% to 70%.

The Company placed 54 commingled vertical Atoka wells on production during the second quarter, with an average 24-hour IP rate of 163 BOEPD. Results from well tests continue to support an incremental gross EUR of 50 MBOE to 70 MBOE for wells completed in the Atoka interval. Like the Strawn, Pioneer has further refined the Spraberry acreage position it believes is prospective for the Atoka interval to 40% to 50%, at the upper end of the prior range of 25% to 50%.

Seven vertical commingled wells were also placed on production through the Mississippian interval during the second quarter, with an average initial 24-hour IP rate of 124 BOEPD. Data from all Mississippian wells drilled to date continues to support an incremental gross EUR per well of 15 MBOE to 40 MBOE from this interval. Pioneer continues to believe the Mississippian interval is prospective in 20% of its Spraberry acreage.

Second quarter production from the Spraberry field averaged 64 MBOEPD, an increase of 2 MBOEPD from the first quarter of 2012. Production was negatively impacted by approximately 4,800 BOEPD due to unplanned third-party NGL fractionation downtime and tight industry NGL fractionation capacity at Mont Belvieu, Texas, as described below. Had these third-party processing issues not occurred during the second quarter and all of Pioneer’s NGL volumes could have been fractionated and sold, Pioneer’s Spraberry production would have been approximately 68,500 BOEPD.

  • The Spraberry field produces oil and associated liquids-rich gas. The gas includes NGLs, which are separated at the Midkiff/Benedum and Sale Ranch gas processing facilities in West Texas. These NGLs are then transported to third-party fractionation facilities at Mont Belvieu. During May, a significant third-party facility was shut down for planned maintenance. When it came back on line in late May, it had operating problems and was not able to achieve its pre-shutdown fractionation capacity. As a result of this problem and tight fractionation capacity across the Mont Belvieu complex, Pioneer built an NGL inventory of 256 thousand barrels that could not be processed for sale in June, thereby negatively impacting production for the second quarter by approximately 2,800 BOEPD. Within the next month, the fractionation facility is expected to increase processing rates to its pre-shutdown processing capacity, thereby allowing Pioneer’s NGL inventory and ongoing production to be fractionated and sold over the remainder of 2012. Based on the Company’s second quarter NGL price realization per barrel, the NGL inventory has a sales value of approximately $8 million.
  • The Midkiff/Benedum gas processing plants were also forced to reject ethane into the residue gas stream during the second quarter as a result of tight NGL fractionation capacity at Mont Belvieu. The net impact of rejecting ethane was primarily a loss in production of approximately 2,000 BOEPD. Ethane rejection continues and is expected to impact Pioneer’s production over the remainder of 2012 based on the outlook for continuing tight fractionation capacity at Mont Belvieu. Due to low ethane prices, there is not a significant economic impact associated with rejecting ethane versus recovering and selling it. Pioneer estimates that its revenues are lower as a result of rejecting ethane by approximately $18 thousand per day at current gas and NGL prices.

Based on production for the first half of 2012, the planned vertical and horizontal drilling programs for the remainder of 2012 described above, continued ethane rejection of up to 2,000 BOEPD through the end of 2012 and the sale of the NGL inventory during the second half of 2012, production is forecasted to grow from an average of 45 MBOEPD in 2011 to 63 MBOEPD to 67 MBOEPD in 2012. This is an increase from the previous production guidance range of 61 MBOEPD to 65 MBOEPD.

In the liquids-rich Eagle Ford Shale in South Texas, Pioneer is currently running 12 rigs and plans to drill approximately 125 wells in 2012. The 2012 drilling program will continue to focus on liquids-rich drilling, with only 10% of the wells designated to hold strategic dry gas acreage in response to the current low gas price environment. The Company drilled 34 wells in the second quarter and placed 37 wells on production.

Pioneer increased its Eagle Ford Shale production from 23 MBOEPD in the first quarter of 2012 to 24 MBOEPD in the second quarter. The Company expects production to increase from an average of 12 MBOEPD in 2011 to 25 MBOEPD to 29 MBOEPD in 2012.

Pioneer’s gross well cost in the Eagle Ford Shale ranges from $7 million to $8 million per well. 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. The Company is now expanding the use of white sand proppant to deeper areas of the field to further define its performance limits. The Company has tested 53 wells through the second quarter, with a savings of approximately $700 thousand per well. Early well performance has been similar to direct offset ceramic-stimulated wells. Pioneer is continuing to monitor the performance of these wells and plans to use white sand in 50% of its 2012 drilling program. The first dry gas well using white sand as proppant was fracture stimulated in July. Four additional dry gas wells using white sand as proppant are planned over the remainder of the year.

Three central gathering plants (CGPs) were added during the second quarter as part of the joint venture’s Eagle Ford Shale midstream business. Eleven CGPs are now operational. 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 93,000 gross acreage position, representing more than 1,000 drilling locations. The Company drilled 12 wells in the second quarter and placed 10 wells on production. Pioneer is operating two rigs in the play but plans to reduce its activity to one rig in August in response to low gas and NGL prices.

Production in the second quarter for the Barnett Shale Combo play was 7 MBOEPD, up from 6 MBOEPD in the first quarter. The Company expects production to increase from an average of 4 MBOEPD in 2011 to 7 MBOEPD to 9 MBOEPD in 2012. Production is comprised of 60% liquids (oil and NGLs) and 40% gas.

The Company’s well results are continuing to improve. Peak 30-day rates on seven recent wells have averaged 345 BOEPD, with an oil content of 60%. Drilling times have also been reduced from 16 days in 2011 to 10 days currently.

On the North Slope of Alaska, Pioneer continues to operate one rig and drill development wells from its island targeting the Kuparuk, Nuiqsut and Torok intervals. The Company’s second quarter production was 5 MBOEPD, an increase of 1 MBOEPD from the first quarter of 2012. This increase was primarily the result of the first successful mechanically diverted fracture stimulation of a Nuiqsut interval well during the first quarter. Based on the success of this mechanically diverted fracture stimulation, the Company is planning four more wells using this stimulation technique early next year during the winter drilling season. During the first quarter of 2012, the Company also drilled a successful onshore appraisal well to test the southern extent of the Torok interval. The production and subsurface data provided by this successful well supports the addition of 50 million barrels of oil to the resource potential of the Torok interval within Pioneer’s acreage. The well is now shut in awaiting permanent onshore production facilities for which an onshore development FEED study has been initiated. Pioneer is planning a second onshore Torok well for the first quarter of next year (winter drilling season) to further test this interval.

2012 Capital Budget

Pioneer’s capital program for 2012 of $2.9 billion (excludes acquisitions, asset retirement obligations, capitalized interest and geological and geophysical G&A) includes drilling capital of $2.4 billion and capital for vertical integration of $0.5 billion.

The Company is maintaining its 2012 drilling budget at $2.4 billion and is managing second half drilling activity in response to lower-than-anticipated cash flow resulting from lower commodity prices. Increased activity and higher costs during the first half of 2012 are being offset by rig reductions in the Spraberry and Barnett Shale Combo plays in the second half. The capital program for 2012 was weighted towards the first half of year, with drilling expenditures totaling $1.4 billion. The first half capital included two exploration wells in Alaska in which Pioneer had a 100% working interest, running 40 Spraberry vertical rigs compared to 30 rigs in the second half, running two Barnett Shale Combo rigs compared to one rig in the second half, acquiring new seismic data in the horizontal Wolfcamp Shale and Barnett Shale Combo plays and higher-cost “science” wells in the horizontal Wolfcamp Shale play. A further reduction of up to 3 rigs in the Spraberry is also possible during the second half of 2012 if commodity prices remain under pressure.

The capital for vertical integration of $500 million includes $300 million for the U.S. industrial sands business acquired by Pioneer in early April, $100 million for pressure pumping and well service equipment and $100 million for the accelerated construction of field offices and facilities from 2013 into 2012.

The 2012 capital budget is expected to be funded from forecasted operating cash flow of $1.8 billion, assuming commodity prices of $85 per barrel for oil and $3 per thousand cubic feet (MCF) for gas, proceeds of $0.5 billion from Pioneer’s equity offering during the fourth quarter of 2011, net proceeds from the liquidation of 2014 and 2015 gas derivatives of $143 million, proceeds from the divestiture of South African and certain South Texas assets of $107 million, the utilization of approximately $150 million of pipe and equipment inventory and borrowings of $200 million under Pioneer’s credit facility.

Second Quarter 2012 Financial Review

The following financial results for the second quarter of 2012 reflect continuing operations and exclude the results of operations attributable to South Africa that are included in discontinued operations.

Liquids and gas sales averaged 150.5 MBOEPD, consisting of oil sales averaging 61 MBPD, NGL sales averaging 27 MBPD and gas sales averaging 373 million cubic feet per day (MMCFPD).

The average price for oil was $88.32 per barrel including $1.87 per barrel related to deferred revenue from volumetric production payments (VPPs) for which production was not recorded. The average reported price for NGLs was $32.62 per barrel and the average reported price for gas was $2.00 per MCF.

Production costs averaged $14.70 per barrel oil equivalent (BOE). Depreciation, depletion and amortization (DD&A) expense averaged $14.67 per BOE. Exploration and abandonment costs were $37 million for the quarter. This included $13 million related to the drilling program and $24 million for geologic and geophysical activities, including $11 million for new seismic data being acquired in the horizontal Wolfcamp Shale and the Barnett Shale Combo plays and $13 million for personnel costs. General and administrative expense totaled $55 million. Interest expense was $49 million, and other expense was $31 million, including $9 million for non-recurring rig termination fees.

Commodity Derivative Positions For 2014 and 2015

In June and July 2012, Pioneer liquidated swap, collar and three-way collar derivatives for 250,000 million British thermal units per day (MMBTUPD) of 2014 gas production and 80,000 MMBTUPD of 2015 gas production. These liquidated volumes represent 100% and 43% of Pioneer’s gas derivative positions in 2014 and 2015, respectively. The Company also liquidated 140,000 MMBTUPD of gas basis swaps for 2014. As a result of these liquidations, the Company realized $143 million of net cash proceeds, of which $72 million was realized during June. A before-tax realized gain of $72 million was recorded in the second quarter related to volumes liquidated in June. A before-tax realized gain of $71 million related to the volumes liquidated in July will be recorded in the third quarter.

The gas derivatives were unwound when gas prices were at low levels to partially offset the reduction in cash flow the Company is forecasting for 2012 resulting from lower price realizations on oil and NGL sales. Despite the monetization of the gas derivatives for 2014 and a portion for 2015, Pioneer continues to have one of the best commodity derivatives positions in the industry. Derivative swap, collar and three-way collar contracts cover approximately 95% of the Company’s oil production over the remainder of 2012, 85% in 2013 and 40% in 2014. Swap, collar and three-way collar derivative contracts are in place to cover 90% of Pioneer’s gas production over the remainder of 2012, 70% in 2013 and 25% in 2015.

Third Quarter 2012 Financial Outlook

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

Production is forecasted to average 155 MBOEPD to 159 MBOEPD. Production costs are expected to average $13.50 to $15.50 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 $25 million to $40 million.

General and administrative expense is expected to be $55 million to $60 million, interest expense is expected to be $51 million to $56 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 $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 $5 million to $10 million and are primarily attributable to alternative minimum tax and state taxes.

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

Earnings Conference Call

On Wednesday, August 1, 2012, at 9:00 a.m. Central Time, Pioneer will discuss its financial and operating results for the quarter ended June 30, 2012, 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 (888) 430-8690 confirmation code: 4778865 five minutes before the call. View the presentation via Pioneer’s internet address above.

A replay of the webcast will be archived on Pioneer’s website. A telephone replay will be available through August 22 by dialing (888) 203-1112 confirmation code: 4778865.

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 (including joint venture 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, the risks associated with the ownership and operation of an industrial sand mining business, 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 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)
         
   

June 30,
2012

 

December 31,
2011

ASSETS
Current assets:        
Cash and cash equivalents   $ 317,769     $ 537,484  
Accounts receivable, net   252,493     283,813  
Income taxes receivable   2,417     3  
Inventories   277,539     241,609  
Prepaid expenses   28,213     14,263  
Deferred income taxes   118,074     77,005  
Discontinued operations held for sale   70,177     73,349  
Derivatives   308,762     238,835  
Other current assets, net   26,663     12,936  
Total current assets   1,402,107     1,479,297  
         
Property, plant and equipment, at cost:        
Oil and gas properties, using the successful efforts method of accounting   13,261,118     12,249,332  
Accumulated depletion, depreciation and amortization   (4,013,770 )   (3,648,465 )
Total property, plant and equipment   9,247,348     8,600,867  
         
Goodwill   298,142     298,142  
Other property and equipment, net   1,134,532     573,075  
Investment in unconsolidated affiliate   184,374     169,532  
Derivatives   260,929     243,240  
Other assets, net   160,376     160,008  
         
    $ 12,687,808     $ 11,524,161  
         
LIABILITIES AND EQUITY
Current liabilities:        
Accounts payable   $ 809,158     $ 716,211  
Interest payable   57,329     57,240  
Income taxes payable   1,881     9,788  
Discontinued operations held for sale   77,310     75,901  
Deferred revenue   21,150     42,069  
Derivatives   30,650     74,415  
Other current liabilities   41,857     36,174  
Total current liabilities   1,039,335     1,011,798  
         
Long-term debt   3,285,497     2,528,905  
Deferred income taxes   2,362,031     2,077,164  
Derivatives   17,785     33,561  
Other liabilities   226,184     221,595  
Equity   5,756,976     5,651,138  
         
    $ 12,687,808     $ 11,524,161  
                 
 
PIONEER NATURAL RESOURCES COMPANY
 
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
           
      Three Months Ended
June 30,
  Six Months Ended
June 30,
      2012   2011   2012   2011
Revenues and other income:                  
Oil and gas     $ 641,737     $ 562,412     $ 1,360,693     $ 1,038,140  
Interest and other     6,043     13,594     34,491     42,067  
Derivative gains (losses), net     275,812     229,478     367,562     (14,954 )
Gain (loss) on disposition of assets, net     1,140     (296 )   44,736     (2,487 )
      924,732     805,188     1,807,482     1,062,766  
Costs and expenses:                  
Oil and gas production     156,838     101,741     295,159     200,576  
Production and ad valorem taxes     44,495     35,864     90,291     69,160  
Depletion, depreciation and amortization     200,921     135,511     382,339     258,345  
Impairment of oil and gas properties     444,880         444,880      
Exploration and abandonments     37,178     19,732     90,465     37,216  
General and administrative     54,957     44,339     118,024     88,250  
Accretion of discount on asset retirement obligations     2,444     2,048     4,874     4,092  
Interest     49,008     44,995     95,866     90,222  
Hurricane activity, net         (2 )       69  
Other     30,651     12,053     54,258     29,914  
      1,021,372     396,281     1,576,156     777,844  
                           
Income (loss) from continuing operations before income taxes     (96,640 )   408,907     231,326     284,922  
Income tax benefit (provision)     45,086     (140,182 )   (72,617 )   (92,275 )
Income (loss) from continuing operations     (51,554 )   268,725     158,709     192,647  
Income (loss) from discontinued operations, net of tax     12,017     (3,025 )   22,712     416,857  
Net income (loss)     (39,537 )   265,700     181,421     609,504  
Net income attributable to noncontrolling interests     (30,855 )   (20,123 )   (37,194 )   (15,333 )
Net income (loss) attributable to common stockholders     $ (70,392 )   $ 245,577     $ 144,227     $ 594,171  
                                   
Basic earnings per share:                  
Income (loss) from continuing operations attributable to common stockholders     $ (0.67 )   $ 2.10     $ 0.98     $ 1.50  
Income (loss) from discontinued operations attributable to common stockholders     0.10     (0.03 )   0.18     3.53  
Net income (loss) attributable to common stockholders     $ (0.57 )   $ 2.07     $ 1.16     $ 5.03  
                                   
Diluted earnings per share:                  
Income (loss) from continuing operations attributable to common stockholders     $ (0.67 )   $ 2.06     $ 0.95     $ 1.46  
Income (loss) from discontinued operations attributable to common stockholders     0.10     (0.03 )   0.18     3.44  
Net income (loss) attributable to common stockholders     $ (0.57 )   $ 2.03     $ 1.13     $ 4.90  
                                   
Weighted average shares outstanding:                  
Basic     123,028     116,213     122,754     116,042  
Diluted     123,028     118,592     125,772     118,986  
                           
 
PIONEER NATURAL RESOURCES COMPANY
 
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
           
      Three Months Ended
June 30,
  Six Months Ended
June 30,
      2012   2011   2012   2011
Cash flows from operating activities:                  
Net income (loss)     $ (39,537 )   $ 265,700     $ 181,421     $ 609,504  
Adjustments to reconcile net income (loss) to net cash provided by operating activities:                  
Depletion, depreciation and amortization     200,921     135,511     382,339     258,345  
Impairment of oil and gas properties     444,880         444,880      
Exploration expenses, including dry holes     12,567     2,794     39,730     4,275  
Deferred income taxes     (48,580 )   137,642     57,291     87,337  
(Gain) loss on disposition of assets, net     (1,140 )   296     (44,736 )   2,487  
Accretion of discount on asset retirement obligations     2,444     2,048     4,874     4,092  
Discontinued operations     2,020     8,821     3,597     (390,868 )
Interest expense     8,282     7,795     18,152     15,432  
Derivative related activity     (116,757 )   (220,303 )   (144,000 )   56,380  
Amortization of stock-based compensation     15,884     10,981     30,970     21,155  
Amortization of deferred revenue     (10,460 )   (11,207 )   (20,919 )   (22,290 )
Other noncash items     1,671     7,070     (7,513 )   (9,207 )
Change in operating assets and liabilities, net of effects from acquisitions and dispositions:                  
Accounts receivable, net     54,876     1,665     33,881     (23,605 )
Income taxes receivable     (2,859 )   27,225     (1,452 )   27,226  
Inventories     (2,291 )   (44,817 )   (33,318 )   (74,136 )
Prepaid expenses     (14,838 )   (11,332 )   (13,425 )   (9,990 )
Other current assets     (11,334 )   5,467     (8,846 )   8,772  
Accounts payable     11,254     96,181     30,580     6,201  
Interest payable     21,999     23,424     82     (1,642 )
Income taxes payable     (24,848 )   (26,839 )   (7,907 )   (11,485 )
Other current liabilities     (4,830 )   3,118     (20,271 )   6,471  
Net cash provided by operating activities     499,324     421,240     925,410     564,454  
Net cash used in investing activities     (1,142,400 )   (576,020 )   (1,822,066 )   (241,852 )
Net cash provided by (used in) financing activities     643,927     (13,450 )   676,941     (81,341 )
Net increase (decrease) in cash and cash equivalents     851     (168,230 )   (219,715 )   241,261  
Cash and cash equivalents, beginning of period     316,918     520,651     537,484     111,160  
Cash and cash equivalents, end of period     $ 317,769     $ 352,421     $ 317,769     $ 352,421  
                                   
 
PIONEER NATURAL RESOURCES COMPANY
 
UNAUDITED SUMMARY PRODUCTION AND PRICE DATA
                 
            Three Months Ended
June 30,
  Six Months Ended
June 30,
            2012   2011   2012   2011
Average Daily Sales Volumes from Continuing Operations:                        
Oil (Bbls) -     U.S.     61,428     35,872     59,550     34,904
Natural gas liquids ("NGL") (Bbls) -     U.S.     26,960     21,839     27,222     20,251
Gas (Mcf) -     U.S.     372,713     337,354     371,068     331,295
Total (BOE) -     U.S.     150,506     113,937     148,617     110,371
                         
Average Daily Sales Volumes from Discontinued Operations:                        
Oil (Bbls) -     South Africa     702     616     744     571
      Tunisia                 1,103
      Total     702     616     744     1,674
                         
Gas (Mcf) -     South Africa     19,382     24,193     17,647     23,867
      Tunisia                 1,001
      Total     19,382     24,193     17,647     24,868
                         
Total (BOE) -     South Africa     3,932     4,648     3,686     4,549
      Tunisia                 1,270
      Total     3,932     4,648     3,686     5,819
                         
Average Reported Prices (a):                        
Oil (per Bbl) -     U.S.     $ 88.32     $ 104.34     $ 94.45     $ 100.05
NGL (per Bbl) -     U.S.     $ 32.62     $ 48.16     $ 37.26     $ 45.42
Gas (per Mcf) -     U.S.     $ 2.00     $ 4.11     $ 2.26     $ 4.00
Total (BOE) -     U.S.     $ 46.86     $ 54.24     $ 50.31     $ 51.97

_____________

(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 six months ended June 30, 2012 and 2011:

           
      Three Months Ended
June 30,
  Six Months Ended
June 30,
      2012   2011   2012   2011
      (in thousands)
                   
Net income (loss) attributable to common stockholders     $ (70,392 )   $ 245,577     $ 144,227     $ 594,171  
Participating basic earnings     (265 )   (4,847 )   (2,176 )   (10,849 )
Basic net income (loss) attributable to common stockholders     (70,657 )   240,730     142,051     583,322  
Reallocation of participating earnings         164     154     271  
Diluted net income (loss) attributable to common stockholders     $ (70,657 )   $ 240,894     $ 142,205     $ 583,593  
                                   

The following table is a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three and six months ended June 30, 2012 and 2011:

           
      Three Months Ended
June 30,
  Six Months Ended
June 30,
      2012   2011   2012   2011
      (in thousands)
                   
Weighted average common shares outstanding:                  
Basic     123,028     116,213     122,754     116,042
Dilutive common stock options         178     205     188
Contingently issuable performance unit shares         429     171     423

Convertible senior notes dilution

        1,772     2,642     2,333
Diluted     123,028     118,592     125,772     118,986
                         
                         

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
June 30,
  Six Months Ended
June 30,
        2012   2011   2012   2011
                     
Net income (loss)       $ (39,537 )   $ 265,700     $ 181,421     $ 609,504  
Depletion, depreciation and amortization       200,921     135,511     382,339     258,345  
Exploration and abandonments       37,178     19,732     90,465     37,216  
Impairment of oil and gas properties       444,880         444,880      
Hurricane activity, net           (2 )       69  
Accretion of discount on asset retirement obligations       2,444     2,048     4,874     4,092  
Interest expense       49,008     44,995     95,866     90,222  
Income tax (benefit) provision       (45,086 )   140,182     72,617     92,275  
(Gain) loss on disposition of assets, net       (1,140 )   296     (44,736 )   2,487  
Discontinued operations       (12,017 )   3,025     (22,712 )   (416,857 )
Derivative related activity       (116,757 )   (220,303 )   (144,000 )   56,380  
Amortization of stock-based compensation       15,884     10,981     30,970     21,155  
Amortization of deferred revenue       (10,460 )   (11,207 )   (20,919 )   (22,290 )
Other noncash items       1,671     7,070     (7,513 )   (9,207 )
                     
EBITDAX (a)       526,989     398,028     1,063,552     723,391  
                     
Cash interest expense       (40,726 )   (37,200 )   (77,714 )   (74,790 )
Current income taxes       (3,494 )   (2,540 )   (15,326 )   (4,938 )
                     
Discretionary cash flow (b)       482,769     358,288     970,512     643,663  
                     
Cash hurricane activity           2         (69 )
Discontinued operations cash activity       14,037     5,796     26,309     25,989  
Cash exploration expense       (24,611 )   (16,938 )   (50,735 )   (32,941 )
Changes in operating assets and liabilities       27,129     74,092     (20,676 )   (72,188 )
Net cash provided by operating activities       $ 499,324     $ 421,240     $ 925,410     $ 564,454  

_____________

(a)   “EBITDAX” represents earnings before depletion, depreciation and amortization expense; exploration and abandonments; impairment of oil and gas properties; 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 SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES (continued)
(in thousands, except per share data)

Adjusted loss excluding unrealized mark-to-market ("MTM") derivative gains, and adjusted income excluding unrealized MTM derivative gains and unusual items, as presented in this press release, are presented and reconciled to Pioneer's net loss attributable to common stockholders and diluted common shares outstanding (determined in accordance with GAAP) because Pioneer believes that these non-GAAP financial measures reflect an additional way of viewing aspects of 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 tables below reconcile Pioneer's net loss attributable to common stockholders and diluted shares outstanding for the three months ended June 30, 2012, as determined in accordance with GAAP, to loss adjusted for unrealized MTM derivative gains and adjusted income excluding unrealized MTM derivative gains and unusual items for that quarter.

           
     

After-tax
Amounts

 

Amounts
Per Share

           
Net loss attributable to common stockholders     $ (70,392 )   $ (0.57 )
Unrealized MTM derivative gains     (60,433 )   (0.49 )
Loss adjusted for unrealized MTM derivative gains     (130,825 )   (1.06 )
           
Income from discontinued operations (primarily South Africa)     (12,017 )   (0.10 )
Realized MTM termination gains on 2014 gas derivatives     (45,304 )   (0.37 )
Drilling rig termination fees     5,645     0.05  
Impairment of oil and gas properties     280,274     2.28  
Incremental share dilution attributable to common stock equivalents         (0.02 )
Adjusted income excluding unrealized MTM derivative gains and unusual items     $ 97,773     $ 0.78  
           
           
      Three Months Ended
June 30,
       
Diluted common shares outstanding     123,028
Dilutive common stock equivalents attributable to adjusted income     2,216
Diluted common shares outstanding including common stock equivalents     125,244
       
 
PIONEER NATURAL RESOURCES COMPANY
 
SUPPLEMENTAL INFORMATION
 
Open Commodity Derivative Positions as of July 30, 2012
(Volumes are average daily amounts)
             
      2012     Twelve Months Ending December 31,
     

Third
Quarter

   

Fourth
Quarter

    2013     2014     2015
                               
Average Daily Oil Production Associated with Derivatives (Bbls):                              
Collar contracts with short puts:                              
Volume     50,110       53,110       67,290       40,000      
NYMEX price:                              
Ceiling     $ 118.61       $ 118.85       $ 120.61       $ 122.77       $
Floor     $ 84.50       $ 85.09       $ 88.88       $ 91.50       $

Short put

    $ 68.80       $ 69.44       $ 71.72       $ 74.88       $
Collar contracts:                              
Volume     2,000       2,000                  
NYMEX price:                              
Ceiling     $ 127.00       $ 127.00       $       $       $
Floor     $ 90.00       $ 90.00       $       $       $
Swap contracts:                              
Volume     8,304       11,000       3,000            
NYMEX price     $ 88.12       $ 89.34       $ 81.02       $       $
Rollfactor swap contracts:                              
Volume                 6,000            
NYMEX roll price (a)     $       $       $ 0.43       $       $
Basis swap contracts:                              
Index swap volume     20,000       20,000                  
Price (b)     $ (1.15 )     $ (1.15 )     $       $       $
Average Daily NGL Production Associated with Derivatives (Bbls):                              
Collar contracts with short puts:                              
Volume     3,000       3,000                  
Index price (c):                              
Ceiling     $ 79.99       $ 79.99       $       $       $
Floor     $ 67.70       $ 67.70       $       $       $
Short put     $ 55.76       $ 55.76       $       $       $
Swap contracts:                              
Volume     2,070       2,750                  
Index price (c)     $ 63.88       $ 67.85       $       $       $
Average Daily Gas Production Associated with Derivatives (MMBtu):                              
Collar contracts with short puts:                              
Volume                             105,000
NYMEX price:                              
Ceiling     $       $       $       $       $ 4.96
Floor     $       $       $       $       $ 4.00
Short put     $       $       $       $       $ 3.00
Collar contracts:                              
Volume     65,000       65,000       150,000            
NYMEX price:                              
Ceiling     $ 6.60       $ 6.60       $ 6.25       $       $
Floor     $ 5.00       $ 5.00       $ 5.00       $       $
Swap contracts:                              
Volume     275,000       275,000       112,500            
NYMEX price (d)     $ 4.97       $ 4.97       $ 5.62       $       $
Basis swap contracts:                              
Permian Basin index swap volume (e)     32,500       32,500       52,500            
Price differential ($/MMBtu)     $ (0.38 )     $ (0.38 )     $ (0.23 )     $       $
Mid-Continent index swap volume (e)     50,000       50,000       30,000            
Price differential ($/MMBtu)     $ (0.53 )     $ (0.53 )     $ (0.38 )     $       $
Gulf Coast index swap volume (e)     53,500       53,500       60,000            
Price differential ($/MMBtu)     $ (0.15 )     $ (0.15 )     $ (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)   Represents weighted average index price per Bbl of each NGL component.
     
(d)   Represents the NYMEX Henry Hub index price on the derivative trade date.
     
(e)   Represent swaps that fix the basis differentials between the indices price at which the Company sells its Permian Basin, Mid-Continent and Gulf Coast gas and the NYMEX Henry Hub index price used in gas swap and collar contracts.
     

Diesel prices. As of July 30, 2012, the Company has diesel derivative swap contracts for 250 notional Bbls per day for 2013 at an average per Bbl fixed price of $111.30. The diesel derivative 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.

Interest rate derivatives. As of July 30, 2012, 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 gas buy and sell marketing arrangements to fulfill firm pipeline transportation commitments. Associated with these gas marketing arrangements, the Company may enter into gas index swaps to mitigate price risk.

From time to time, the Company also enters into long and short gas swap contracts that transfer gas basis risk from one sales index to another sales index. The following table presents Pioneer’s open marketing and basis transfer derivative positions as of July 30, 2012:

         
        2012
       

Third
Quarter

 

Fourth
Quarter

             
Average Daily Gas Production Associated with Marketing Derivatives (MMBtu):            
Basis swap contracts:            
Index swap volume       40,000     13,478  
Price differential ($/MMBtu)       $ 0.25     $ 0.25  
Average Daily Gas Production Associated with Basis Transfer Derivatives (MMBtu):            
Basis swap contracts:            
Short index swap volume       5,000     1,685  
NGI-So Cal Border Monthly price differential ($/MMBtu)       $ 0.12     $ 0.12  
Long index swap volume       (5,000 )   (1,685 )
IF-HSC price differential ($/MMBtu)       $ (0.05 )   $ (0.05 )
                     
   
  PIONEER NATURAL RESOURCES COMPANY
   
  SUPPLEMENTAL INFORMATION
   
 

Amortization of Deferred Revenue Associated with Volumetric Production Payments as of June 30, 2012

  (in thousands)
           
      2012    
      Third Quarter  

Fourth
Quarter

  Total
               
  Total deferred revenue associated with VPP (a)   $ 10,575     $ 10,575     $ 21,150

_____________

(a)   Deferred revenue will be amortized as increases to oil revenues during the indicated future periods.
     
             
Derivative Gains, Net
(in thousands)
             
     

Three Months Ended
June 30, 2012

   

Six Months Ended
June 30, 2012

Noncash changes in fair value:            
Oil derivative gains     $ 317,479       $ 267,610  
NGL derivative gains     8,477       11,360  
Gas derivative losses     (184,548 )     (112,813 )
Diesel derivative gains (losses)     236       (34 )
Marketing derivative gains     119       73  
Interest rate derivative losses     (22,659 )     (19,039 )
Total noncash derivative gains, net (a)     119,104       147,157  
             
Cash settled changes in fair value:            
Oil derivative losses     (2,099 )     (8,703 )
NGL derivative gains     4,552       6,465  
Gas derivative gains (b)     154,180       220,726  
Diesel derivative gains           1,864  
Marketing derivative gains     75       53  
Total cash derivative gains, net     156,708       220,405  
Total derivative gains, net     $ 275,812       $ 367,562  

_____________

(a)   Total net unrealized mark-to-market derivative gains includes $23.2 million and $19.2 million, respectively, of net gains attributable to noncontrolling interests in consolidated subsidiaries during the three and six months ended June 30, 2012.
     
(b)   During June and July 2012, the Company terminated swap, collar, three-way collar and basis swap derivative contracts for 2014 and 2015 gas production. As a result of these terminations, the Company realized $71.9 million of proceeds during the second quarter of 2012 and $71.2 million of proceeds that will be recognized during the third quarter of 2012. The terminated derivative contracts are not included in the accompanying open commodity derivative positions table.

 

Source: Pioneer Natural Resources Company

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