EXHIBIT 99.1
News Release
Pioneer Natural Resources Reports
Third Quarter 2011 Financial and Operating Results
Dallas, Texas, November 1, 2011 -- Pioneer Natural Resources Company (NYSE:PXD) (“Pioneer” or “the Company”) today announced financial and operating results for the quarter ended September 30, 2011.
Pioneer reported third quarter net income attributable to common stockholders of $351 million, or $2.95 per diluted share (see attached schedule for a description of the earnings per diluted share calculation). Net income included unrealized mark-to-market gains on derivatives of $191 million after tax, or $1.60 per diluted share. Without the effect of this item, adjusted income for the third quarter would have been $160 million, or $1.35 per diluted share. Also included in Pioneer’s third quarter results was income of $26 million after tax, or $0.21 per diluted share, related to unwinding certain oil and interest rate derivatives.
Scott Sheffield, Chairman and CEO, stated, “The Company delivered another strong quarter, with production increasing to 128 thousand barrels oil equivalent per day (MBOEPD), an increase of 9 MBOEPD, or 8%, from the second quarter of 2011. This follows an increase of 7 MBOEPD, or 7%, from the first quarter to the second quarter. Our three core Texas liquids-rich growth assets, the Spraberry field, Eagle Ford Shale and the Barnett Shale Combo, were the drivers of these quarterly production increases. Fourth quarter production is forecasted to grow by approximately 10 MBOEPD, reflecting the continued successful drilling in these three assets. For 2011, production is expected to average approximately 125 MBOEPD.”
“Based on our drilling plans for the Spraberry field, the Eagle Ford Shale and the Barnett Shale Combo play, we expect the Company to deliver production growth of 20+% in 2012 compared to 2011 and U.S. production growth of 22+%. We also expect the Company to achieve a compound annual production growth rate of 18+% through 2014, with liquids increasing from 44% of total production in 2010 to 60% in 2014. This strong, liquids-focused production growth is forecasted to generate compound annual operating cash flow growth of 30+% over the 2011 through 2014 period.”
“We are excited about the successful horizontal well we recently completed in the Wolfcamp Shale. It continues to flow naturally with a peak seven-day average rate of 732 barrels oil equivalent per day (BOEPD) and a peak 24-hour rate of 854 BOEPD, even with flow line restrictions. This result, coupled with the strong production from other industry players drilling horizontal wells in this interval and Pioneer’s extensive geologic interpretation of the area, suggests significant horizontal Wolfcamp Shale potential exists within Pioneer’s acreage. We are currently focusing our efforts on more than 200,000 acres in the southern part of the field. We plan to drill three additional horizontal Wolfcamp Shale wells by early 2012 and expect to expand our horizontal drilling program in this area next year.”
“Owning fracture stimulation fleets, drilling rigs and other service-related equipment is not only enhancing the execution of our drilling program, but it is also providing significant cash savings versus contracting for these services at market rates. We estimate that by year-end 2011, the Company’s annualized cash savings from vertical integration investments will be greater than $450 million.”
“We are funding our 2011 capital program of $2.1 billion from forecasted operating cash flow of $1.4 billion to $1.5 billion and the redeployment of proceeds from the sale of Tunisia. Pioneer has a strong financial position, with a net
debt-to-book capitalization of 31% as of September 30, 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.”
Operations Update and Drilling Program
The Spraberry field and the Eagle Ford Shale are the two most active plays in the U.S., with the industry operating 225 rigs and 200 rigs in each play, respectively. Pioneer is a drilling, production and technology leader in both of these liquids-rich, high-margin plays.
In the Spraberry oil field in West Texas, Pioneer has increased its drilling program to an average of 38 rigs in the third quarter, including 15 Company-owned rigs. The Company has continued to expand its integrated services to control drilling costs and support the execution of its accelerated drilling program. Five Company-owned fracture stimulation fleets are currently operating in the Spraberry field. To support its growing operations, 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, forecasted fracture stimulation sand supply requirements through 2015 and forecasted well cementing services through 2016.
Vertical integration in the Spraberry field is saving Pioneer up to $500 thousand per well compared to utilizing third-party services at market rates. Pioneer expects its vertical integration equipment will provide approximately one third of its rig requirements and two thirds of its fracture stimulation requirements by the end of 2011. As a result, the blended Pioneer and third-party well cost is expected to average $1.5 million to $1.6 million per well for 2011. Pioneer’s internal rate of return on its 2011 Spraberry drilling program is expected to be approximately 40% before tax based on flat commodity prices of $90 per barrel for oil and $5 per thousand cubic feet (MCF) for gas, estimated future production costs and an estimated ultimate recovery (EUR) of 140 thousand barrels oil equivalent (MBOE) for a vertical well completed through the Lower Wolfcamp.
During 2010, Pioneer successfully added incremental production and proved reserves from vertical completions in the Lower Wolfcamp and organic rich shale/silt intervals. The Company is also continuing to drill deeper intervals below the Wolfcamp in certain areas of the field. This deeper drilling includes the Strawn, the Atoka and the Mississippian intervals. The Company anticipates a potential increase of up to 110 MBOE in the EUR of a Lower Wolfcamp well in areas of the field where the Strawn and Atoka intervals are both present.
Pioneer has completed 113 vertical wells in the Strawn interval since the drilling program began in 2010. Initial peak production rates from this interval, when tested alone, have averaged 70 BOEPD. For wells that have been on production for at least ten months, production has increased by more than 25% compared to offset wells that have been drilled only to the Lower Wolfcamp. This data suggests a potential incremental EUR per well of 20 MBOE to 40 MBOE from the Strawn interval. The incremental cost per well for this deeper drilling and one additional fracture stimulation stage is approximately $60 thousand. Pioneer believes the Strawn interval is prospective in 40% of its Spraberry acreage and expects to complete and commingle this interval with all zones in 25% of the vertical wells drilled in the fourth quarter of 2011 and during 2012.
The Company completed its third vertical Atoka well in the third quarter of 2011. The initial peak production rate from this interval alone averaged 127 BOEPD. The Company plans to test the Atoka interval for approximately six months and will then commingle this production with production from all zones. The incremental cost to drill an Atoka well ranges from approximately $300 thousand to $350 thousand as a result of deeper drilling, larger casing and two additional fracture stimulation stages. Pioneer believes the Atoka interval is prospective in 25% to 50% of its Spraberry acreage. Incremental EURs per well from this interval are estimated to range from 50 MBOE to 70 MBOE based on offset well data. The Company plans to test two to three additional single-zone Atoka
wells in the fourth quarter and is forecasting that 15% to 20% of its 2012 vertical drilling program in the Spraberry will include wells drilled to the Atoka interval, with production commingled from all zones.
Pioneer completed its second vertical test of the Mississippian interval in the third quarter, with an initial peak production rate of 92 BOEPD. The incremental cost per well for this deeper drilling, larger casing and two additional fracture stimulation stages is approximately $300 thousand to $350 thousand. Offset well data indicates a potential incremental EUR per well of 15 MBOE to 30 MBOE. Pioneer believes the Mississippian interval is prospective in 10% to 20% of its Spraberry acreage. The Company expects to complete one to two additional single-zone wells in the fourth quarter and is forecasting that 10% of its 2012 vertical drilling program in the Spraberry will include wells drilled to the Mississippian interval, with production commingled from all zones.
The Company continues to test vertical downspacing in the Spraberry field from 40 acres to 20 acres. Eleven 20-acre vertical wells have been drilled during 2011, with six put on production. These 20-acre wells are producing from the Lower Wolfcamp, Strawn and shale/silt intervals. As was the case with 20-acre wells drilled during 2010, results continue to indicate that production from these wells is significantly outperforming the previous 110 MBOE type curve for a traditional Spraberry/Dean well. The Company expects to drill three to five additional 20-acre downspaced wells in 2011 and is targeting 30 to 50 20-acre wells in its 2012 vertical 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 increase in production is now being observed. Cumulative production from the area flooded in the Upper Spraberry has increased by greater than 10% compared to forecasted base production decline, with further increases expected as additional wells respond to the water injection. Based on these early results, reserve adds related to the waterflood are likely during 2011.
The Company has one dedicated rig drilling horizontal wells in the Wolfcamp Shale in the Spraberry field area. The Company successfully completed its first horizontal well in Upton County, Texas with a 30-stage fracture stimulation in a 5,800-foot lateral section. The XBC Giddings Estate 2041H continues to flow naturally with a peak seven-day average rate of 732 BOEPD (591 barrels oil per day, 86 barrels natural gas liquids (NGLs) per day and 332 MCF per day), and a peak 24-hour rate of 854 BOEPD (686 barrels oil per day, 102 barrels NGLs per day and 395 MCF per day), even with flow line restrictions. Pioneer’s micro-seismic analysis of the completion showed that the entire 800 foot thick target zone was successfully fracture stimulated. The well is producing to sales.
The results of the XBC Giddings 2041H well are encouraging, as this well is 30 miles to 60 miles northwest of the area where most of the recent successful industry drilling of horizontal Wolfcamp Shale wells has been occurring. Based on this successful drilling activity and Pioneer’s extensive geologic interpretation of the Wolfcamp Shale, the Company believes it has significant horizontal Wolfcamp Shale potential within its acreage and is currently focusing its efforts on more than 200,000 acres in the southern part of the field. Pioneer has not been drilling vertical Spraberry wells in this area because the returns are marginal and the southern acreage is not prospective for the deeper Strawn, Atoka and Mississippian intervals.
Pioneer is currently drilling its second horizontal Wolfcamp Shale well in Upton County with a planned 6,000-foot lateral section and 30-stage fracture stimulation. Two additional horizontal Wolfcamp Shale wells are planned in southern Reagan County by early 2012. These two wells are expected to test longer lateral lengths and additional fracture stimulation stages. Pioneer expects to expand its horizontal drilling program in 2012.
Third quarter production from the Spraberry field averaged 47 MBOEPD, an increase of 6 MBOEPD from the second quarter. Current production is approximately 51 MBOEPD. Spraberry production is forecasted to continue to grow to 51 MBOEPD to 53 MBOEPD in the fourth quarter, with full-year 2011 production expected to be towards the high end of the Company’s full-year average guidance of 43 MBOEPD to 46 MBOEPD. Production is forecasted to further increase to 54 MBOEPD to 59 MBOEPD in 2012, 68 MBOEPD to 74 MBOEPD in 2013 and 77 MBOEPD to 84 MBOEPD in 2014. The forecast for 2012 through 2014 excludes the potential contributions from drilling vertical wells deeper to intervals below the Lower Wolfcamp and the impacts from the expected expansion of horizontal Wolfcamp Shale drilling.
In the liquids-rich Eagle Ford Shale in South Texas, Pioneer and its joint venture partners are currently running 12 rigs. To improve the execution of its drilling and completions program and reduce costs, Pioneer purchased two fracture stimulation fleets for its Eagle Ford Shale completions. One fleet was placed in service in April and the other fleet is expected to be operational later in the fourth quarter. The Company also entered into a two-year contract for a dedicated third-party fracture stimulation fleet, which commenced operating in April. With the start-up of these two fleets, Pioneer has been able to significantly increase the number of wells put on production, with a further increase expected when the second Company-owned fleet commences operations later this quarter.
The Company continues to see strong performance from its Eagle Ford Shale drilling program. Wells drilled during the third quarter continued to yield approximately 65% liquids, consisting of oil, condensate and NGLs. The lateral length of each well continues to average approximately 5,500 feet and is being completed with a 13-stage fracture stimulation.
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. Beginning in June 2011, funding for ongoing midstream infrastructure build-out costs that are in excess of operating cash flow are expected to be 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 of $1.4 billion to $1.5 billion in 2011.
Pioneer’s gross well cost in the Eagle Ford Shale ranges from $7 million to $8 million per well. Using this cost, flat commodity prices of $90 per barrel for oil and $5 per MCF for gas, estimated future production costs, and excluding the benefit of the joint-venture drilling carry, before tax internal rates of return are estimated to be 80% for high condensate yield wells (200 barrels per million cubic feet) and 60% for lean condensate yield wells (60 barrels per million cubic feet).
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 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 approximately 30% of its 2012 drilling program.
Pioneer increased its Eagle Ford Shale production from 8 MBOEPD in the second quarter to 14 MBOEPD in the third quarter as it continued to successfully bring new wells on production. Current production is approximately 20 MBOEPD. A further increase to 20 MBOEPD to 23 MBOEPD is forecasted for the fourth quarter. As a result, annual production for 2011 is forecasted to average 12 MBOEPD to 15 MBOEPD and grow to 26 MBOEPD to 30 MBOEPD in 2012, 40 MBOEPD to 45 MBOEPD in 2013 and 54 MBOEPD to 60 MBOEPD in 2014.
In the liquids-rich Barnett Shale Combo play, Pioneer has built a 76,000-acre position, representing more than 700 drilling locations. Pioneer is currently operating two rigs in the play. The Company continued to see performance from new wells improve in the third quarter. Production is liquids-rich, with approximately 75% of the production being oil and NGLs.
Production in the third quarter for the Barnett Shale Combo play was 4 MBOEPD, up from 3 MBOEPD in the second quarter. Current production is approximately 5 MBOEPD. The Company expects production to increase to 5 MBOEPD to 7 MBOEPD in the fourth quarter and average 4 MBOEPD to 5 MBOEPD for the full year. Current plans call for a further increase in production to 9 MBOEPD to 12 MBOEPD in 2012, 18 MBOEPD to 22 MBOEPD in 2013 and 26 MBOEPD to 31 MBOEPD in 2014. Assuming flat commodity prices of $90 per barrel for oil and $5 per MCF for gas, estimated future production costs, an average per-well drilling cost of $3 million and a gross EUR of 320 MBOE, Pioneer’s internal rate of return in the Barnett Shale Combo play is expected to be 40% before tax.
South Africa production was shut in for approximately three weeks during the third quarter due to unplanned third-party gas-to-liquids plant downtime. As a result, Pioneer’s third quarter production was reduced by approximately 1 MBOEPD. The plant was again shut down in late September due to an unrelated issue and has just come back on line at the end of October. As a result, Pioneer’s fourth quarter production guidance has been reduced by approximately 1.5 MBOEPD.
Third Quarter 2011 Financial Review
The following financial results for the third quarter of 2011 reflect continuing operations.
Sales averaged 128 MBOEPD, consisting of oil sales averaging 43 thousand barrels per day (MBPD), NGL sales averaging 23 MBPD and gas sales averaging 370 million cubic feet per day (MMCFPD). Compared to the second quarter, third quarter oil sales increased by 6 MBPD, primarily due to continued successful drilling and the addition of incremental oil transport trucks in the Spraberry field. NGL sales during the third quarter were essentially flat compared to the second quarter due to unplanned downtime and takeaway limitations at the Midkiff/Benedum plants in the Spraberry field. The plants are now back in full operations and the takeaway limitations have been resolved. Gas sales during the third quarter increased by 9 MMCFPD compared to the second quarter as higher sales in the Eagle Ford Shale and Barnett Shale Combo were partly offset by unplanned plant downtime in South Africa and the constraints at Midkiff/Benedum.
The average reported price for oil was $92.24 per barrel and included $2.88 per barrel related to deferred revenue from volumetric production payments (VPPs) for which production was not recorded. The average reported price for NGLs was $48.36 per barrel. The average reported price for gas was $4.24 per MCF.
Production costs averaged $13.47 per barrel oil equivalent (BOE), an increase of $0.65 per BOE from the second quarter of 2011. This increase was primarily due to higher lease operating expenses related in large part to increases in labor rates, chemical costs and electricity rates. Higher natural gas processing expenses increased as a result of unplanned downtime and NGL takeaway limitations at the Midkiff/Benedum plants.
Depreciation, depletion and amortization (DD&A) expense averaged $14.18 per BOE. Exploration and abandonment costs were $20 million for the quarter and included $2 million of acreage abandonments and $18 million of geologic and geophysical expenses and personnel costs.
Fourth Quarter 2011 Financial Outlook
The Company’s fourth quarter 2011 outlook for certain operating and financial items is provided below.
Production is forecasted to average 136 MBOEPD to 141 MBOEPD. South Africa production was shut-in during the month of October due to unplanned third-party gas-to-liquids plant downtime. The plant is now back in operation and production guidance for the quarter reflects the October downtime and assumes the plant will be in full operation over the remainder of the quarter.
Production costs are expected to average $12.50 to $14.50 per BOE, based on current NYMEX strip commodity prices. DD&A expense is expected to average $13.50 to $15.00 per BOE. Total exploration and abandonment expense is forecasted to be $25 million to $35 million.
General and administrative expense is expected to be $47 million to $52 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 $10 million to $15 million and are primarily attributable to South Africa.
The Company's financial and derivative mark-to-market results, open derivatives positions for oil, NGL and gas, amortization of net deferred gains on discontinued commodity hedges and future VPP amortization are outlined on the attached schedules.
Earnings Conference Call
On Wednesday, November 2, 2011, at 11:00 a.m. Central Time, Pioneer will discuss its financial and operating results for the quarter ended September 30, 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) 718-5111 confirmation code: 3367644 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 November 30 by dialing (888) 203-1112 confirmation code: 3367644.
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.
Pioneer Natural Resources Contacts:
Investors
Frank Hopkins – 972-969-4065
Brian Hansen – 972-969-4017
Eric Pregler – 972-969-5756
Media and Public Affairs
Susan Spratlen – 972-969-4018
Suzanne Hicks – 972-969-4020
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands)
September 30, 2011 | December 31, 2010 | |||||||
| ASSETS | ||||||||
| Current assets: | ||||||||
| Cash and cash equivalents | $ | 210,565 | $ | 111,160 | ||||
| Accounts receivable, net | 278,188 | 245,303 | ||||||
| Income taxes receivable | 2,312 | 30,901 | ||||||
| Inventories | 260,356 | 173,615 | ||||||
| Prepaid expenses | 18,910 | 11,441 | ||||||
| Deferred income taxes | 92,140 | 156,650 | ||||||
| Discontinued operations held for sale | - | 281,741 | ||||||
| Derivatives | 234,806 | 171,679 | ||||||
| Other current assets, net | 6,366 | 14,693 | ||||||
| Total current assets | 1,103,643 | 1,197,183 | ||||||
| Property, plant and equipment, at cost: | ||||||||
| Oil and gas properties, using the successful efforts method of accounting | 12,341,837 | 10,930,226 | ||||||
| Accumulated depletion, depreciation and amortization | (3,788,686) | (3,366,440) | ||||||
| Total property, plant and equipment | 8,553,151 | 7,563,786 | ||||||
| Deferred income taxes | 7,358 | - | ||||||
| Goodwill | 298,154 | 298,182 | ||||||
| Other property and equipment, net | 500,709 | 283,542 | ||||||
| Investment in unconsolidated affiliate | 164,107 | 72,045 | ||||||
| Derivatives | 224,754 | 151,011 | ||||||
| Other assets, net | 133,167 | 113,353 | ||||||
| $ | 10,985,043 | $ | 9,679,102 | |||||
| LIABILITIES AND STOCKHOLDERS' EQUITY | ||||||||
| Current liabilities: | ||||||||
| Accounts payable | $ | 631,804 | $ | 419,150 | ||||
| Interest payable | 33,955 | 59,008 | ||||||
| Income taxes payable | 15,604 | 19,168 | ||||||
| Deferred income taxes | - | 1,144 | ||||||
| Discontinued operations held for sale | - | 108,592 | ||||||
| Deferred revenue | 42,825 | 44,951 | ||||||
| Derivatives | 12,377 | 80,997 | ||||||
| Other current liabilities | 39,552 | 36,210 | ||||||
| Total current liabilities | 776,117 | 769,220 | ||||||
| Long-term debt | 2,587,371 | 2,601,670 | ||||||
| Deferred income taxes | 2,133,147 | 1,751,310 | ||||||
| Deferred revenue | 46,701 | 42,069 | ||||||
| Derivatives | 16,946 | 56,574 | ||||||
| Other liabilities | 228,094 | 232,234 | ||||||
| Stockholders' equity | 5,196,667 | 4,226,025 | ||||||
| $ | 10,985,043 | $ | 9,679,102 | |||||
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||
| 2011 | 2010 | 2011 | 2010 | ||||||||||
| Revenues and other income: | |||||||||||||
| Oil and gas | $ | 610,509 | $ | 437,411 | $ | 1,691,570 | $ | 1,331,498 | |||||
| Interest and other | 17,573 | 14,969 | 68,714 | 49,929 | |||||||||
| Derivative gains, net | 401,072 | 127,581 | 386,118 | 570,585 | |||||||||
| Gain (loss) on disposition of assets, net | 1,048 | 2,383 | (1,439) | 26,971 | |||||||||
| Hurricane activity, net | 1,487 | 3,452 | 1,418 | 5,678 | |||||||||
| 1,031,689 | 585,796 | 2,146,381 | 1,984,661 | ||||||||||
| Costs and expenses: | |||||||||||||
| Oil and gas production | 119,609 | 100,717 | 321,995 | 280,829 | |||||||||
| Production and ad valorem taxes | 38,542 | 33,045 | 107,702 | 85,444 | |||||||||
| Depletion, depreciation and amortization | 166,536 | 147,096 | 460,807 | 435,833 | |||||||||
| Exploration and abandonments | 20,026 | 21,610 | 57,583 | 61,201 | |||||||||
| General and administrative | 49,812 | 43,417 | 138,562 | 122,165 | |||||||||
| Accretion of discount on asset retirement obligations | 2,806 | 2,521 | 8,119 | 7,909 | |||||||||
| Interest | 45,559 | 45,002 | 136,554 | 137,893 | |||||||||
| Other | 17,183 | 19,687 | 49,452 | 49,826 | |||||||||
| 460,073 | 413,095 | 1,280,774 | 1,181,100 | ||||||||||
| Income from continuing operations before income taxes | 571,616 | 172,701 | 865,607 | 803,561 | |||||||||
| Income tax provision | (185,471) | (76,211) | (283,016) | (303,438) | |||||||||
| Income from continuing operations | 386,145 | 96,490 | 582,591 | 500,123 | |||||||||
| Income (loss) from discontinued operations, net of tax | (547) | 18,083 | 412,511 | 63,745 | |||||||||
| Net income | 385,598 | 114,573 | 995,102 | 563,868 | |||||||||
| Net income attributable to the noncontrolling interests | (34,134) | (2,538) | (49,467) | (39,003) | |||||||||
| Net income attributable to common stockholders | $ | 351,464 | $ | 112,035 | $ | 945,635 | $ | 524,865 | |||||
| Basic earnings per share: | |||||||||||||
| Income from continuing operations attributable to common stockholders | $ | 2.96 | $ | 0.80 | $ | 4.51 | $ | 3.92 | |||||
| Income (loss) from discontinued operations attributable to common | |||||||||||||
| stockholders | - | 0.15 | 3.49 | 0.54 | |||||||||
| Net income attributable to common stockholders | $ | 2.96 | $ | 0.95 | $ | 8.00 | $ | 4.46 | |||||
| Diluted earnings per share: | |||||||||||||
| Income from continuing operations attributable to common stockholders | $ | 2.95 | $ | 0.79 | $ | 4.42 | $ | 3.89 | |||||
| Income (loss) from discontinued operations attributable to common | |||||||||||||
| stockholders | - | 0.15 | 3.43 | 0.54 | |||||||||
| Net income attributable to common stockholders | $ | 2.95 | $ | 0.94 | $ | 7.85 | $ | 4.43 | |||||
| Weighted average shares outstanding: | |||||||||||||
| Basic | 116,281 | 115,191 | 116,122 | 114,985 | |||||||||
| Diluted | 117,075 | 116,021 | 118,350 | 115,832 | |||||||||
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||
| Cash flows from operating activities: | ||||||||||||||||
| Net income | $ | 385,598 | $ | 114,573 | $ | 995,102 | $ | 563,868 | ||||||||
| Adjustments to reconcile net income to net cash provided by | ||||||||||||||||
| operating activities: | ||||||||||||||||
| Depletion, depreciation and amortization | 166,536 | 147,096 | 460,807 | 435,833 | ||||||||||||
| Exploration expenses, including dry holes | 1,733 | 8,682 | 6,008 | 16,655 | ||||||||||||
| Hurricane activity, net | - | - | - | 3,500 | ||||||||||||
| Deferred income taxes | 173,533 | 62,931 | 249,040 | 283,283 | ||||||||||||
| (Gain) loss on disposition of assets, net | (1,048) | (2,383) | 1,439 | (26,971) | ||||||||||||
| Accretion of discount on asset retirement obligations | 2,806 | 2,521 | 8,119 | 7,909 | ||||||||||||
| Discontinued operations | (238) | 1,877 | (407,353) | 43,339 | ||||||||||||
| Interest expense | 7,980 | 7,647 | 23,412 | 22,567 | ||||||||||||
| Derivative related activity | (326,126) | (107,300) | (269,746) | (549,387) | ||||||||||||
| Amortization of stock-based compensation | 10,370 | 9,582 | 31,525 | 28,631 | ||||||||||||
| Amortization of deferred revenue | (11,330) | (22,669) | (33,620) | (67,739) | ||||||||||||
| Other noncash items | 2,504 | 9,115 | (15,773) | 10,440 | ||||||||||||
| Change in operating assets and liabilities: | ||||||||||||||||
| Accounts receivable, net | (11,647) | 1,497 | (35,252) | 97,873 | ||||||||||||
| Income taxes receivable | 1,362 | (6,751) | 28,588 | 16,689 | ||||||||||||
| Inventories | (41,825) | (18,938) | (115,961) | (6,459) | ||||||||||||
| Prepaid expenses | 2,432 | 1,229 | (7,558) | (8,975) | ||||||||||||
| Other current assets | (252) | 9,354 | 8,520 | 2,162 | ||||||||||||
| Accounts payable | 77,431 | 11,891 | 83,632 | 62,349 | ||||||||||||
| Interest payable | (23,411) | (20,225) | (25,053) | (13,211) | ||||||||||||
| Income taxes payable | 9,678 | 5,777 | (1,807) | 1,307 | ||||||||||||
| Other current liabilities | 39,498 | (6,998) | 45,969 | (21,941) | ||||||||||||
| Net cash provided by operating activities | 465,584 | 208,508 | 1,030,038 | 901,722 | ||||||||||||
| Net cash used in investing activities | (613,001) | (325,829) | (854,853) | (564,202) | ||||||||||||
| Net cash provided by (used in) financing activities | 5,561 | (2,200) | (75,780) | (286,723) | ||||||||||||
| Net increase (decrease) in cash and cash equivalents | (141,856) | (119,521) | 99,405 | 50,797 | ||||||||||||
| Cash and cash equivalents, beginning of period | 352,421 | 197,686 | 111,160 | 27,368 | ||||||||||||
| Cash and cash equivalents, end of period | $ | 210,565 | $ | 78,165 | $ | 210,565 | $ | 78,165 | ||||||||
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUMMARY PRODUCTION AND PRICE DATA
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||
| Average Daily Sales Volumes | ||||||||||||||
| from Continuing Operations: | ||||||||||||||
| Oil (Bbls) - | U.S. | 42,245 | 28,880 | 37,378 | 27,388 | |||||||||
| South Africa | 527 | 445 | 556 | 730 | ||||||||||
| Worldwide | 42,772 | 29,325 | 37,934 | 28,118 | ||||||||||
| Natural gas liquids ("NGL") (Bbls) - | U.S. | 23,212 | 20,525 | 21,249 | 19,649 | |||||||||
| Gas (Mcf) - | U.S. | 350,687 | 327,917 | 337,830 | 335,960 | |||||||||
| South Africa | 19,468 | 31,069 | 22,384 | 30,304 | ||||||||||
| Worldwide | 370,155 | 358,986 | 360,214 | 366,264 | ||||||||||
| Total (BOE) - | U.S. | 123,905 | 104,058 | 114,932 | 103,030 | |||||||||
| South Africa | 3,771 | 5,623 | 4,287 | 5,781 | ||||||||||
| Worldwide | 127,676 | 109,681 | 119,219 | 108,811 | ||||||||||
| Average Reported Prices (a): | ||||||||||||||
| Oil (per Bbl) - | U.S. | $ | 92.01 | $ | 86.06 | $ | 96.98 | $ | 89.08 | |||||
| South Africa | $ | 110.65 | $ | 77.84 | $ | 107.18 | $ | 77.43 | ||||||
| Worldwide | $ | 92.24 | $ | 85.93 | $ | 97.13 | $ | 88.77 | ||||||
| Natural gas liquids (per Bbl) - | U.S. | $ | 48.36 | $ | 34.46 | $ | 46.50 | $ | 36.80 | |||||
| Gas (per Mcf) - | U.S. | $ | 4.04 | $ | 4.06 | $ | 4.01 | $ | 4.37 | |||||
| South Africa | $ | 7.82 | $ | 6.34 | $ | 7.53 | $ | 6.26 | ||||||
| Worldwide | $ | 4.24 | $ | 4.25 | $ | 4.23 | $ | 4.53 | ||||||
| Total (BOE) - | U.S. | $ | 51.86 | $ | 43.47 | $ | 51.93 | $ | 44.95 | |||||
| South Africa | $ | 55.80 | $ | 41.17 | $ | 53.22 | $ | 42.57 | ||||||
| Worldwide | $ | 51.97 | $ | 43.35 | $ | 51.97 | $ | 44.82 | ||||||
__________
| (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 per share attributable to common stockholders is computed as (i) net income attributable to common stockholders, (ii) less participating share- and unit-based basic earnings (iii) divided by weighted average basic shares outstanding. The Company's diluted net income per share attributable to common stockholders is computed as (i) basic net income attributable to common stockholders, (ii) plus the reallocation of participating earnings (iii) divided by weighted average diluted shares outstanding. During periods in which the Company realizes a loss from continuing operations attributable to common stockholders, securities or other contracts to issue common stock would be dilutive to loss per share; therefore, conversion into common stock is assumed not to occur.
The following table is a reconciliation of the Company's net income attributable to common stockholders to basic net income attributable to common stockholders and to diluted net income attributable to common stockholders for the three and nine months ended September 30, 2011 and 2010:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||
| (in thousands) | ||||||||||||
| Net income attributable to common stockholders | $ | 351,464 | $ | 112,035 | $ | 945,635 | $ | 524,865 | ||||
| Participating basic earnings | (6,797) | (2,689) | (17,186) | (12,020) | ||||||||
| Basic net income attributable to common stockholders | 344,667 | 109,346 | 928,449 | 512,845 | ||||||||
| Reallocation of participating earnings | 189 | 19 | 458 | 127 | ||||||||
| Diluted net income attributable to common stockholders | $ | 344,856 | $ | 109,365 | $ | 928,907 | $ | 512,972 | ||||
The following table is a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three and nine months ended September 30, 2011 and 2010:
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||
| 2011 | 2010 | 2011 | 2010 | ||||||
| (in thousands) | |||||||||
| Weighted average common shares outstanding: | |||||||||
| Basic | 116,281 | 115,191 | 116,122 | 114,985 | |||||
| Dilutive common stock options | 166 | 168 | 181 | 218 | |||||
| Contingently issuable performance unit shares | 443 | 662 | 429 | 629 | |||||
| Convertible senior notes dilution | 185 | - | 1,618 | - | |||||
| Diluted | 117,075 | 116,021 | 118,350 | 115,832 | |||||
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 and net cash provided by operating activities because of their wide acceptance by the investment community as financial indicators of a company's ability to internally fund exploration and development activities and to service or incur debt. The Company also views the non-GAAP measures of EBITDAX and DCF as useful tools for comparisons of the Company's financial indicators with those of peer companies that follow the full cost method of accounting. EBITDAX and DCF should not be considered as alternatives to net income or net cash provided by operating activities, as defined by GAAP.
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||
| 2011 | 2010 | 2011 | 2010 | ||||||||||
| Net income | $ | 385,598 | $ | 114,573 | $ | 995,102 | $ | 563,868 | |||||
| Depletion, depreciation and amortization | 166,536 | 147,096 | 460,807 | 435,833 | |||||||||
| Exploration and abandonments | 20,026 | 21,610 | 57,583 | 61,201 | |||||||||
| Hurricane activity, net | (1,487) | (3,452) | (1,418) | (5,678) | |||||||||
| Accretion of discount on asset retirement obligations | 2,806 | 2,521 | 8,119 | 7,909 | |||||||||
| Interest expense | 45,559 | 45,002 | 136,554 | 137,893 | |||||||||
| Income tax provision | 185,471 | 76,211 | 283,016 | 303,438 | |||||||||
| (Gain) loss on disposition of assets, net | (1,048) | (2,383) | 1,439 | (26,971) | |||||||||
| Discontinued operations | 547 | (18,083) | (412,511) | (63,745) | |||||||||
| Derivative related activity | (326,126) | (107,300) | (269,746) | (549,387) | |||||||||
| Amortization of stock-based compensation | 10,370 | 9,582 | 31,525 | 28,631 | |||||||||
| Amortization of deferred revenue | (11,330) | (22,669) | (33,620) | (67,739) | |||||||||
| Other noncash items | 2,504 | 9,115 | (15,773) | 10,440 | |||||||||
| EBITDAX (a) | 479,426 | 271,823 | 1,241,077 | 835,693 | |||||||||
| Cash interest expense | (37,579) | (37,355) | (113,142) | (115,326) | |||||||||
| Current income taxes | (11,938) | (13,280) | (33,976) | (20,155) | |||||||||
| Discretionary cash flow (b) | 429,909 | 221,188 | 1,093,959 | 700,212 | |||||||||
| Cash hurricane activity | 1,487 | 3,452 | 1,418 | 9,178 | |||||||||
| Discontinued operations cash activity | (785) | 19,960 | 5,158 | 107,084 | |||||||||
| Cash exploration expense | (18,293) | (12,928) | (51,575) | (44,546) | |||||||||
| Changes in operating assets and liabilities | 53,266 | (23,164) | (18,922) | 129,794 | |||||||||
| Net cash provided by operating activities | $ | 465,584 | $ | 208,508 | $ | 1,030,038 | $ | 901,722 | |||||
__________
| (a) | “EBITDAX” represents earnings before depletion, depreciation and amortization expense; 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 income excluding unrealized mark-to-market ("MTM") derivative gains, as presented in this press release, is presented and reconciled to Pioneer's net income attributable to common stockholders that is determined in accordance with GAAP because Pioneer believes that this non-GAAP financial measure reflects 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 this non-GAAP measure may enhance investors' ability to assess Pioneer's historical and future financial performance. This non-GAAP financial measure is not intended to be a substitute 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 will recur in future periods; however, the amount and frequency can vary significantly from period to period. The table below reconciles Pioneer's net income attributable to common stockholders for the three months ended September 30, 2011, as determined in accordance with GAAP, to adjusted income excluding unrealized MTM derivative gains for that quarter.
After-tax Amounts | Diluted Amounts Per Share | ||||||
| Net income attributable to common stockholders | $ | 351 | $ | 2.95 | |||
| Unrealized MTM derivative gains | (191) | (1.60) | |||||
| Adjusted income excluding unrealized MTM derivative gains | $ | 160 | $ | 1.35 | |||
PIONEER NATURAL RESOURCES COMPANY
SUPPLEMENTAL INFORMATION
Open Commodity Derivative Positions as of October 14, 2011
(Volumes are average daily amounts)
| 2011 | ||||||||||||||||||
Fourth Quarter | 2012 | 2013 | 2014 | 2015 | ||||||||||||||
| Average Daily Oil Production Associated with | ||||||||||||||||||
| Derivatives (Bbls): | ||||||||||||||||||
| Swap Contracts: | ||||||||||||||||||
| Volume | 750 | 3,000 | 3,000 | - | - | |||||||||||||
| NYMEX price (a) | $ | 77.25 | $ | 79.32 | $ | 81.02 | $ | - | $ | - | ||||||||
| Collar Contracts: | ||||||||||||||||||
| Volume | 2,000 | 2,000 | - | - | - | |||||||||||||
| NYMEX price: | ||||||||||||||||||
| Ceiling | $ | 170.00 | $ | 127.00 | $ | - | $ | - | $ | - | ||||||||
| Floor | $ | 115.00 | $ | 90.00 | $ | - | $ | - | $ | - | ||||||||
| Collar Contracts with Short Puts: | ||||||||||||||||||
| Volume | 32,000 | 36,000 | 31,000 | 10,000 | - | |||||||||||||
| NYMEX price: | ||||||||||||||||||
| Ceiling | $ | 99.33 | $ | 117.99 | $ | 119.78 | $ | 127.46 | $ | - | ||||||||
| Floor | $ | 73.75 | $ | 80.42 | $ | 83.81 | $ | 87.50 | $ | - | ||||||||
| Short Put | $ | 59.31 | $ | 65.00 | $ | 66.23 | $ | 72.50 | $ | - | ||||||||
| Percent of total oil production (b) | ~80% | ~75% | ~50% | ~15% | N/A | |||||||||||||
| Average Daily NGL Production Associated with | ||||||||||||||||||
| Derivatives (Bbls): | ||||||||||||||||||
| Swap Contracts: | ||||||||||||||||||
| Volume | 1,150 | 750 | - | - | - | |||||||||||||
| Blended index price (c) | $ | 51.50 | $ | 35.03 | $ | - | $ | - | $ | - | ||||||||
| Collar Contracts: | ||||||||||||||||||
| Volume | 2,650 | - | - | - | - | |||||||||||||
| Index price (c): | ||||||||||||||||||
| Ceiling | $ | 64.23 | $ | - | $ | - | $ | - | $ | - | ||||||||
| Floor | $ | 53.29 | $ | - | $ | - | $ | - | $ | - | ||||||||
| Collar Contracts with Short Puts: | ||||||||||||||||||
| Volume | - | 3,000 | - | - | - | |||||||||||||
| Index price (c): | ||||||||||||||||||
| Ceiling | $ | - | $ | 79.99 | $ | - | $ | - | $ | - | ||||||||
| Floor | $ | - | $ | 67.70 | $ | - | $ | - | $ | - | ||||||||
| Short Put | $ | - | $ | 55.76 | $ | - | $ | - | $ | - | ||||||||
| Percent of total NGL production (b) | ~15% | ~15% | N/A | N/A | N/A | |||||||||||||
| Average Daily Gas Production Associated with | ||||||||||||||||||
| Derivatives (MMBtu): | ||||||||||||||||||
| Swap Contracts: | ||||||||||||||||||
| Volume | 117,500 | 105,000 | 67,500 | 50,000 | - | |||||||||||||
| NYMEX price (d) | $ | 6.13 | $ | 5.82 | $ | 6.11 | $ | 6.05 | $ | - | ||||||||
| Collar Contracts: | ||||||||||||||||||
| Volume | - | 65,000 | 150,000 | 140,000 | 50,000 | |||||||||||||
| NYMEX price (d): | ||||||||||||||||||
| Ceiling | $ | - | $ | 6.60 | $ | 6.25 | $ | 6.44 | $ | 7.92 | ||||||||
| Floor | $ | - | $ | 5.00 | $ | 5.00 | $ | 5.00 | $ | 5.00 | ||||||||
| Collar Contracts with Short Puts: | ||||||||||||||||||
| Volume | 200,000 | 190,000 | 45,000 | 60,000 | 30,000 | |||||||||||||
| NYMEX price (d): | ||||||||||||||||||
| Ceiling | $ | 8.55 | $ | 7.96 | $ | 7.49 | $ | 7.80 | $ | 7.11 | ||||||||
| Floor | $ | 6.32 | $ | 6.12 | $ | 6.00 | $ | 5.83 | $ | 5.00 | ||||||||
| Short Put | $ | 4.88 | $ | 4.55 | $ | 4.50 | $ | 4.42 | $ | 4.00 | ||||||||
| Percent of total gas production (b) | ~85% | ~85% | ~55% | ~45% | ~15% | |||||||||||||
| Basis Swap Contracts: | ||||||||||||||||||
| Permian Basin Index Swaps volume (e) | 20,000 | 32,500 | 22,500 | 25,000 | - | |||||||||||||
| Price differential ($/MMBtu) | $ | (0.30) | $ | (0.38) | $ | (0.28) | $ | (0.30) | $ | - | ||||||||
| Mid-Continent Index Swaps volume (e) | 100,000 | 50,000 | 10,000 | 10,000 | - | |||||||||||||
| Price differential ($/MMBtu) | $ | (0.71) | $ | (0.53) | $ | (0.71) | $ | (0.30) | $ | - | ||||||||
| Gulf Coast Index Swaps volume (e) | 23,500 | 53,500 | 40,000 | 20,000 | - | |||||||||||||
| Price differential ($/MMBtu) | $ | (0.16) | $ | (0.15) | $ | (0.13) | $ | (0.14) | $ | - | ||||||||
__________
| (a) | During October 2011, the Company entered into NYMEX swap contracts on 3,000 Bbls per day of March 2012 through May 2012 forecasted production, whereby the Company receives $0.28 per Bbl and pays 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. These crude oil swap contracts,which are not included in the table above, are referred to as "Roll Factor Swaps" and are highly correlated with certain terms of the Company's physical oil sales. |
| (b) | Represents an estimated percentage of forecasted production, which may differ from the percentage of actual production. |
| (c) | Represents weighted average index price per Bbl of each NGL component. |
PIONEER NATURAL RESOURCES COMPANY
SUPPLEMENTAL INFORMATION
Open Commodity Derivative Positions as of October 14, 2011
(Volumes are average daily amounts)
| (d) | 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. |
| (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 contracts. |
Diesel price derivatives. The Company has diesel derivative swap contracts for 250 notional Bbls per day for the period from October 2011 through December 2011 at an average per Bbl fixed price of $123.90 and for 2012 at an average per Bbl fixed price of $119.28. 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. During July 2011, the Company terminated $470 million notional amount of fixed-for-variable interest rate derivative contracts and received $26.1 million of associated cash proceeds. During August 2011, the Company entered into interest rate derivative contracts that lock in, for a period of one year, 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 September 30, 2011
(in thousands)
| 2011 | ||||||||||
Fourth Quarter | 2012 | Total | ||||||||
| Total deferred revenues (a) | $ | 11,329 | $ | 42,071 | $ | 53,400 | ||||
| Less derivative losses to be recognized in | ||||||||||
| pretax earnings (b) | (904) | (3,160) | (4,064) | |||||||
| Total VPP impact to pretax earnings | $ | 10,425 | $ | 38,911 | $ | 49,336 | ||||
__________
| (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. |
Deferred Gains on Discontinued Commodity Hedges as of September 30, 2011 (a)
(in thousands)
| 2011 | ||||
Fourth Quarter | ||||
| Commodity hedge gains - oil (b) | $ | 9,197 | ||
__________
| (a) | Excludes deferred hedge losses on terminated derivatives related to the VPPs. |
| (b) | Deferred commodity hedge gains will be realized as an increase to oil revenues during the fourth quarter of 2011. |
PIONEER NATURAL RESOURCES COMPANY
SUPPLEMENTAL INFORMATION
Derivative Gains, Net
(in thousands)
Three Months Ended September 30, 2011 | Nine Months Ended September 30, 2011 | |||||||
| Noncash changes in fair value: | ||||||||
| Oil derivative gains | $ | 298,438 | $ | 257,102 | ||||
| NGL derivative gains | 3,982 | 188 | ||||||
| Gas derivative gains | 62,932 | 45,955 | ||||||
| Diesel derivative losses | (714) | (618) | ||||||
| Interest rate derivative losses | (37,610) | (30,216) | ||||||
| Total noncash derivative gains, net (a) | 327,028 | 272,411 | ||||||
| Cash settled changes in fair value: | ||||||||
| Oil derivative gains (losses) | 5,535 | (35,306) | ||||||
| NGL derivative losses | (4,478) | (11,803) | ||||||
| Gas derivative gains | 41,655 | 124,455 | ||||||
| Diesel derivative gains | 57 | 57 | ||||||
| Interest rate derivative gains | 31,275 | 36,304 | ||||||
| Total cash derivative losses, net | 74,044 | 113,707 | ||||||
| Total derivative gains, net | $ | 401,072 | $ | 386,118 | ||||
__________
| (a) | Total unrealized mark-to-market derivative gains, net includes $23.7 million and $20.0 million of gains attributable to noncontrolling interests in consolidated subsidiaries during the three and nine months ended September 30, 2011, respectively. |