PIONEER NATURAL RESOURCES CO - FORM 8-K - EX-99.1 - PXD FEB 6, 2012 EARNINGS RELEASE 8-K EXH 99.1

Attached files

file	filename
8-K - PXD FEB 6, 2012 EARNINGS RELEASE 8-K - PIONEER NATURAL RESOURCES CO	pxdjan6er8k.htm

EXHIBIT 99.1

News Release

Pioneer Natural Resources Reports

Fourth Quarter 2011 Financial and Operating Results

and Announces 2012 Capital Budget

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

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

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

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

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

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

in the Wolfcamp Shale play with more than 400,000 prospective acres. Our current focus is on 200,000 acres in the southern part of the field where we plan to drill 30 to 35 wells by year end.”

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

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

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

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

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

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

·	a noncash charge of $223 million after tax, or $1.83 per diluted share, for the impairment of dry gas properties in the Company’s legacy Edwards trend play in South Texas as a result of the current low gas price environment (no impairment of the Eagle Ford Shale),

·	a noncash charge of $20 million after tax, or $0.16 per diluted share, for the abandonment of unproved dry gas acreage and

·	Alaska Petroleum Production Tax (PPT) credits of $7 million after tax, or $0.05 per diluted share.

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

Operations Update and Drilling Program

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

The Company recently completed its second successful horizontal well in the Upper/Middle Wolfcamp Shale in Upton County, Texas with a 30-stage fracture stimulation in a 5,800-foot lateral section. The XBC Giddings Estate 2073H exhibited a 24-hour initial production rate of 807 BOEPD (602 barrels oil per

day, 142 barrels of natural gas liquids (NGLs) per day and 382 thousand cubic feet (MCF) of gas per day) and a peak 30-day average natural flow rate of 677 BOEPD (504 barrels oil per day, 119 barrels NGLs per day and 321 MCF per day). Pioneer’s micro-seismic analysis of the completion showed that the entire 800-foot thick target zone was successfully fracture stimulated. The well continues to flow naturally and is producing to sales.

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

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

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

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

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

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

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

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

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

Fourth quarter production from the Spraberry field averaged 53 MBOEPD, an increase of 7 MBOEPD from the third quarter. Based on the vertical and horizontal drilling programs described above, production is forecasted to grow from an average of 45 MBOEPD in 2011 to 61 MBOEPD to 65 MBOEPD in 2012. Assuming the vertical rig count remains at 30 rigs in 2013 and 2014, and the horizontal rig count increases to 10 rigs during this time period, production is forecasted to further increase to 81 MBOEPD to 87 MBOEPD in 2013 and 96 MBOEPD to 103 MBOEPD in 2014.

The current blended Pioneer and third-party well cost for the vertical drilling program averages $1.7 million to $1.8 million per well, ranging from $1.6 million to $1.7 million for a well drilled to the Wolfcamp interval, $1.65 million to $1.75 million to the Strawn interval and $1.9 million to $2.0 million to the Atoka or Mississippian intervals. Pioneer’s internal rate of return on its 2012 Spraberry vertical drilling program is expected to be 45% to 50% before tax, based on the drilling program and gross EURs described above, and assuming flat commodity prices of $100 per barrel for oil and $4 per MCF for gas.

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

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

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

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

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

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

Pioneer has been testing the use of lower-cost white sand instead of ceramic proppant to fracture stimulate wells drilled in shallower areas of the field. Twenty-five wells have been tested to date, with a

savings of approximately $700 thousand per well. Early well performance has been similar to direct offset ceramic-stimulated wells. Pioneer plans to continue to monitor the performance of these wells and plans to use white sand in 50% of its 2012 drilling program.

Eight central gathering plants (CGPs) have been completed as part of the joint venture’s Eagle Ford Shale midstream business. Three additional CGPs are planned for 2012. Pioneer’s share of its Eagle Ford Shale joint-venture midstream activities is conducted through a partially-owned, unconsolidated entity. Funding for ongoing midstream infrastructure build-out costs that are in excess of operating cash flow is provided from external debt sources. Cash flow from the services provided by the midstream operations is not included in Pioneer’s forecasted operating cash flow.

In the liquids-rich Barnett Shale Combo play, Pioneer has built a 78,000 net acreage position, representing more than 1,000 drilling locations. The Company drilled 43 wells in 2011 and placed 42 wells on production. Pioneer operated two rigs in the play for much of 2011 and plans to remain at this level through 2012. The Company expects to increase to four rigs in 2013.

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

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

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

2012 Capital Budget

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

·	Spraberry Vertical - $1,525 million (includes $100 million for infrastructure)

·	Horizontal Wolfcamp Shale - $275 million (includes $25 million for seismic and coring)

·	Eagle Ford Shale - $130 million (net of carry from Reliance Industries Limited )

·	Barnett Shale Combo play - $215 million

·	Alaska - $135 million

·	Other - $120 million, including land capital for existing assets

·	Vertical Integration - $100 million

2012 Capital Budget Funding and Balance Sheet

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

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

Fourth Quarter 2011 Financial Review

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

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

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

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

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

First Quarter 2012 Financial Outlook

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

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

General and administrative expense is expected to be $49 million to $54 million, interest expense is expected to be $45 million to $49 million and other expense is expected to be $20 million to $30 million. Accretion of discount on asset retirement obligations is expected to be $2 million to $4 million.

Noncontrolling interest in consolidated subsidiaries’ income, excluding unrealized derivative mark-to-market adjustments, is expected to be $9 million to $12 million, primarily reflecting the public ownership in Pioneer Southwest Energy Partners L.P.

The Company’s effective income tax rate is expected to range from 35% to 40% based on current capital spending plans and the assumption of no significant unrealized derivative mark-to-market changes in the Company’s derivative position. Current income taxes are expected to be $2 million to $5 million and are primarily attributable to state taxes.

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

Earnings Conference Call

On Tuesday, February 7, 2012, at 9:00 a.m. Central Time, Pioneer will discuss its financial and operating results for the quarter ended December 31, 2011, with an accompanying presentation. Instructions for listening to the call and viewing the accompanying presentation are shown below.

Internet: www.pxd.com

Select “Investors,” then “Earnings Calls & Webcasts” to listen to the discussion and view the presentation.

Telephone: Dial (877) 856-1965 confirmation code: 7754248 five minutes before the call. View the presentation via Pioneer’s internet address above.

A replay of the webcast will be archived on Pioneer’s website. A telephone replay will be available through February 28 by dialing (888) 203-1112 confirmation code: 7754248.

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

Except for historical information contained herein, the statements in this news release are forward-looking statements that are made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause Pioneer's actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties include, among other things, volatility of commodity prices, product supply and demand, competition, the ability to obtain environmental and other permits and the timing thereof, other government regulation or action, the ability to obtain approvals from third parties and negotiate agreements with third parties on mutually acceptable terms, litigation, the costs and results of drilling and operations, availability of equipment, services and personnel required to complete the Company’s operating activities, access to and availability of transportation, processing and refining facilities, Pioneer's ability to replace reserves, implement its business plans or complete its development activities as scheduled, access to and cost of capital, the financial strength of counterparties to Pioneer’s credit facility and derivative contracts and the purchasers of Pioneer’s oil, NGL and gas production, uncertainties about estimates of reserves and resource potential and the ability to add proved reserves in the future, the assumptions underlying production forecasts, quality of technical data, environmental and weather risks, including the possible impacts of climate change, international operations and acts of war or terrorism. These and other risks are described in Pioneer's 10-K and 10-Q Reports and other filings with the Securities and Exchange Commission. In addition, Pioneer may be subject to currently unforeseen risks that may have a materially adverse impact on it. Pioneer undertakes no duty to publicly update these statements except as required by law.

Cautionary Note to U.S. Investors --The U.S. Securities and Exchange Commission (the “SEC”) prohibits oil and gas companies, in their filings with the SEC, from disclosing estimates of oil or gas resources other than “reserves,” as that term is defined by the SEC. In this news release, Pioneer includes estimates of quantities of oil and gas using certain terms, such as “resource potential,” “estimated ultimate recovery,” “EUR” or other descriptions of volumes of reserves, which terms include quantities of oil and gas that may not meet the SEC’s definitions of proved, probable and possible reserves, and which the SEC's guidelines strictly prohibit Pioneer from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being recovered by Pioneer. U.S. investors are urged to consider closely the disclosures in the Company’s periodic filings with the SEC. Such filings are available from the Company at 5205 N. O'Connor Blvd., Suite 200, Irving, Texas 75039, Attention: Investor Relations, and the Company’s website at www.pxd.com. These filings also can be obtained from the SEC by calling 1-800-SEC-0330.

“Drillbit finding and development cost per BOE,” or “drillbit F&D cost per BOE,” means the summation of exploration and development costs incurred divided by the summation of annual proved reserves, on a BOE basis, attributable to

technical revisions of previous estimates, discoveries and extensions and improved recovery. Consistent with industry practice, future capital costs to develop proved undeveloped reserves are not included in costs incurred.

“Reserve replacement” is the summation of annual proved reserves, on a BOE basis, attributable to revisions of previous estimates, purchases of minerals-in-place, discoveries and extensions and improved recovery divided by annual production of oil, NGLs and gas, on a BOE basis.

“Drillbit reserve replacement” is the summation of annual proved reserves, on a BOE basis, attributable to technical revisions of previous estimates, discoveries and extensions and improved recovery divided by annual production of oil, NGLs and gas, on a BOE basis.

Pioneer Natural Resources Contacts:

Investors

Frank Hopkins – 972-969-4065

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)

			December 31, 2011		December 31, 2010
ASSETS
Current assets:
	Cash and cash equivalents		$	537,484	$	111,160
	Accounts receivable, net			283,813		245,303
	Income taxes receivable			3		30,901
	Inventories			241,609		173,615
	Prepaid expenses			14,263		11,441
	Deferred income taxes			77,005		156,650
	Discontinued operations held for sale			73,349		281,741
	Derivatives			238,835		171,679
	Other current assets, net			12,936		14,693

		Total current assets		1,479,297		1,197,183

Property, plant and equipment, at cost:
	Oil and gas properties, using the successful efforts method of accounting			12,249,332		10,930,226
	Accumulated depletion, depreciation and amortization			(3,648,465)		(3,366,440)

		Total property, plant and equipment		8,600,867		7,563,786

Goodwill				298,142		298,182
Other property and equipment, net				573,075		283,542
Investment in unconsolidated affiliate				169,532		72,045
Derivatives				243,240		151,011
Other assets, net				160,008		113,353

			$	11,524,161	$	9,679,102

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
	Accounts payable		$	716,211	$	419,150
	Interest payable			57,240		59,008
	Income taxes payable			9,788		19,168
	Deferred income taxes			-		1,144
	Discontinued operations held for sale			75,901		108,592
	Deferred revenue			42,069		44,951
	Derivatives			74,415		80,997
	Other current liabilities			36,174		36,210

		Total current liabilities		1,011,798		769,220

Long-term debt				2,528,905		2,601,670
Deferred income taxes				2,077,164		1,751,310
Deferred revenue				-		42,069
Derivatives				33,561		56,574
Other liabilities				221,595		232,234
Stockholders' equity				5,651,138		4,226,025

			$	11,524,161	$	9,679,102

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

			Three Months Ended December 31,				Twelve Months Ended December 31,
			2011		2010		2011			2010
Revenues and other income:
	Oil and gas		$	664,776	$	453,981	$	2,294,063	$	1,718,297
	Interest and other			33,812		10,326		101,960		56,972
	Derivative gains (losses), net			6,634		(122,151)		392,752		448,434
	Gain (loss) on disposition of assets, net			(2,205)		(7,897)		(3,644)		19,074
	Hurricane activity, net			36		133,240		1,454		138,918
				703,053		467,499		2,786,585		2,381,695
Costs and expenses:
	Oil and gas production			133,521		86,607		453,085		364,764
	Production and ad valorem taxes			39,962		26,697		147,664		112,141
	Depletion, depreciation and amortization			182,288		122,717		607,405		499,856
	Impairment of oil and gas properties			354,408		-		354,408		-
	Exploration and abandonments			64,078		128,824		121,320		189,597
	General and administrative			55,347		42,905		193,215		164,332
	Accretion of discount on asset retirement obligations			2,092		1,902		8,256		7,945
	Interest			45,878		45,191		181,660		183,084
	Other			16,195		30,313		63,166		78,404
				893,769		485,156		2,130,179		1,600,123

Income (loss) from continuing operations before income taxes				(190,716)		(17,657)		656,406		781,572
Income tax benefit (provision)				75,272		39,264		(197,644)		(269,627)
Income (loss) from continuing operations				(115,444)		21,607		458,762		511,945
Income from discontinued operations, net of tax				2,256		60,519		423,152		134,050
Net income (loss)				(113,188)		82,126		881,914		645,995
	Net (income) loss attributable to the noncontrolling interests			2,042		(1,784)		(47,425)		(40,787)
Net income (loss) attributable to common stockholders			$	(111,146)	$	80,342	$	834,489	$	605,208

Basic earnings per share:
	Income (loss) from continuing operations attributable to common stockholders		$	(0.95)	$	0.17	$	3.45	$	4.00
	Income from discontinued operations attributable to common
		stockholders		0.02		0.51		3.56		1.14
	Net income (loss) attributable to common stockholders		$	(0.93)	$	0.68	$	7.01	$	5.14

Diluted earnings per share:
	Income (loss) from continuing operations attributable to common stockholders		$	(0.95)	$	0.17	$	3.39	$	3.96
	Income from discontinued operations attributable to common
		stockholders		0.02		0.50		3.49		1.12
	Net income (loss) attributable to common stockholders		$	(0.93)	$	0.67	$	6.88	$	5.08

Weighted average shares outstanding:
	Basic			119,223		115,289		116,904		115,062
	Diluted			119,223		117,825		119,215		116,330

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

							Three Months Ended December 31,				Twelve Months Ended December 31,
							2011		2010		2011		2010
Cash flows from operating activities:
	Net income (loss)					$	(113,188)	$	82,126	$	881,914	$	645,995
		Adjustments to reconcile net income (loss) to net cash provided by
			operating activities:
				Depletion, depreciation and amortization			182,288		122,717		607,405		499,856
				Impairment of oil and gas properties			354,408		-		354,408		-
				Exploration expenses, including dry holes			41,223		116,117		47,231		132,772
				Hurricane activity, net			-		1,008		-		4,508
				Deferred income taxes			(76,423)		(39,633)		188,579		259,763
				(Gain) loss on disposition of assets, net			2,205		7,897		3,644		(19,074)
				Accretion of discount on asset retirement obligations			2,092		1,902		8,256		7,945
				Discontinued operations			9,436		(12,147)		(376,717)		77,158
				Interest expense			8,071		7,905		31,483		30,472
				Derivative related activity			47,847		129,578		(221,899)		(419,809)
				Amortization of stock-based compensation			9,917		11,223		41,442		39,854
				Amortization of deferred revenue			(11,331)		(22,477)		(44,951)		(90,216)
				Other noncash items			(7,122)		16,182		(22,412)		25,102
	Change in operating assets and liabilities:
				Accounts receivable, net			(12,079)		(61,220)		(47,331)		36,653
				Income taxes receivable			818		(22,567)		29,406		(5,878)
				Inventories			(21,440)		(19,822)		(137,401)		(26,281)
				Prepaid expenses			4,143		5,101		(3,415)		(3,874)
				Other current assets			(6,563)		(16,432)		1,957		(14,270)
				Accounts payable			52,664		66,578		136,296		128,927
				Interest payable			23,285		25,210		(1,768)		11,999
				Income taxes payable			(5,816)		2,700		(7,623)		4,007
				Other current liabilities			15,241		(18,645)		61,210		(40,586)
					Net cash provided by operating activities		499,676		383,301		1,529,714		1,285,023
Net cash used in investing activities							(705,934)		(390,654)		(1,560,787)		(954,856)
Net cash provided by (used in) financing activities							533,177		40,348		457,397		(246,375)
Net increase in cash and cash equivalents							326,919		32,995		426,324		83,792
Cash and cash equivalents, beginning of period							210,565		78,165		111,160		27,368
Cash and cash equivalents, end of period						$	537,484	$	111,160	$	537,484	$	111,160

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUMMARY PRODUCTION AND PRICE DATA

				Three Months Ended December 31,				Twelve Months Ended December 31,
				2011		2010		2011		2010
Average Daily Sales Volumes
	from Continuing Operations:
		Oil (Bbls) -	U.S.		50,231		30,650		40,618		28,211

		Natural gas liquids ("NGL") (Bbls) -	U.S.		26,163		19,992		22,487		19,736

		Gas (Mcf) -	U.S.		361,829		333,170		343,879		335,256

		Total (BOE) -	U.S.		136,699		106,172		120,418		103,823

Average Daily Sales Volumes
	from Discontinued Operations:
		Oil (Bbls) -	South Africa		452		280		530		616
			Tunisia		-		4,984		547		4,880
			Total		452		5,264		1,077		5,496

		Gas (Mcf) -	South Africa		15,186		28,143		20,570		29,760
			Tunisia		-		3,258		496		2,849
			Total		15,186		31,401		21,066		32,609

		Total (BOE) -	South Africa		2,983		4,970		3,958		5,576
			Tunisia		-		5,527		630		5,355
			Total		2,983		10,497		4,588		10,931

Average Reported Prices (a):
		Oil (per Bbl) -	U.S.	$	95.75	$	94.48	$	96.60	$	90.56

		NGL (per Bbl) -	U.S.	$	45.70	$	42.03	$	46.27	$	38.14

		Gas (per Mcf) -	U.S.	$	3.37	$	3.60	$	3.84	$	4.18

		Total (BOE) -	U.S.	$	52.86	$	46.48	$	52.19	$	45.34

__________

(a)	Average reported prices are attributable to continuing operations and include the results of hedging activities and amortization of VPP deferred revenue.

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY EARNINGS PER SHARE INFORMATION

The Company uses the two-class method of calculating basic and diluted earnings per share. Under the two-class method of calculating earnings per share, GAAP provides that share- and unit-based awards with guaranteed dividend or distribution participation rights qualify as "participating securities" during their vesting periods. The Company's basic net income (loss) per share attributable to common stockholders is computed as (i) net income (loss) attributable to common stockholders, (ii) less participating share- and unit-based basic earnings (iii) divided by weighted average basic shares outstanding. The Company's diluted net income (loss) per share attributable to common stockholders is computed as (i) basic net income (loss) attributable to common stockholders, (ii) plus the reallocation of participating earnings (iii) divided by weighted average diluted shares outstanding. During periods in which the Company realizes a loss from continuing operations attributable to common stockholders, securities or other contracts to issue common stock would be dilutive to loss per share; therefore, conversion into common stock is assumed not to occur.

The following table is a reconciliation of the Company's net income (loss) attributable to common stockholders to basic net income (loss) attributable to common stockholders and to diluted net income (loss) attributable to common stockholders for the three and twelve months ended December 31, 2011 and 2010:

		Three Months Ended December 31,				Twelve Months Ended December 31,
		2011		2010		2011		2010
		(in thousands)

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

The following table is a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three and twelve months ended December 31, 2011 and 2010:

		Three Months Ended December 31,		Twelve Months Ended December 31,
		2011	2010	2011	2010
		(in thousands)

Weighted average common shares outstanding:
	Basic	119,223	115,289	116,904	115,062
	Dilutive common stock options	-	200	190	212
	Contingently issuable performance unit shares	-	697	424	646
	Convertible senior notes dilution	-	1,639	1,697	410

	Diluted	119,223	117,825	119,215	116,330

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES

(in thousands)

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

			Three Months Ended December 31,				Twelve Months Ended December 31,
			2011		2010		2011		2010

Net income (loss)		$	(113,188)	$	82,126	$	881,914	$	645,995
Depletion, depreciation and amortization			182,288		122,717		607,405		499,856
Impairment of oil and gas properties			354,408		-		354,408		-
Exploration and abandonments			64,078		128,824		121,320		189,597
Hurricane activity, net			(36)		(133,240)		(1,454)		(138,918)
Accretion of discount on asset retirement obligations			2,092		1,902		8,256		7,945
Interest expense			45,878		45,191		181,660		183,084
Income tax (benefit) provision			(75,272)		(39,264)		197,644		269,627
(Gain) loss on disposition of assets, net			2,205		7,897		3,644		(19,074)
Discontinued operations			(2,256)		(60,519)		(423,152)		(134,050)
Derivative related activity			47,847		129,578		(221,899)		(419,809)
Amortization of stock-based compensation			9,917		11,223		41,442		39,854
Amortization of deferred revenue			(11,331)		(22,477)		(44,951)		(90,216)
Other noncash items			(7,122)		16,182		(22,412)		25,102

	EBITDAX (a)		499,508		290,140		1,683,825		1,058,993

Cash interest expense			(37,807)		(37,286)		(150,177)		(152,612)
Current income taxes			(1,151)		(369)		(9,065)		(9,864)

	Discretionary cash flow (b)		460,550		252,485		1,524,583		896,517

Cash hurricane activity			36		134,248		1,454		143,426
Discontinued operations cash activity			11,692		48,372		46,435		211,208
Cash exploration expense			(22,855)		(12,707)		(74,089)		(56,825)
Changes in operating assets and liabilities			50,253		(39,097)		31,331		90,697

	Net cash provided by operating activities	$	499,676	$	383,301	$	1,529,714	$	1,285,023

__________

(a)

“EBITDAX” represents earnings before depletion, depreciation and amortization expense; impairment of oil and gas properties; exploration and abandonments; net hurricane activity; unrealized mark-to-market derivative activity; accretion of discount on asset retirement obligations; interest expense; income taxes; (gain) loss on the disposition of assets, net; discontinued operations; amortization of stock-based compensation; amortization of deferred revenue and other noncash items.

(b)

Discretionary cash flow equals cash flows from operating activities before changes in operating assets and liabilities, cash activity reflected in discontinued operations and hurricane activity, and cash exploration expense.

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY NON-GAAP FINANCIAL MEASURES (continued)

(in millions, except per share data)

Adjusted loss excluding unrealized mark-to-market ("MTM") derivative losses, and loss adjusted for unrealized MTM losses and unusual items, as presented in this press release, are presented and reconciled to Pioneer's net loss attributable to common stockholders that is determined in accordance with GAAP because Pioneer believes that these non-GAAP financial measures reflect additional ways of viewing aspects of Pioneer's business that, when viewed together with its financial results computed in accordance with GAAP, provide a more complete understanding of factors and trends affecting its historical financial performance and future operating results, greater transparency of underlying trends and greater comparability of results across periods. In addition, management believes that these non-GAAP measures may enhance investors' ability to assess Pioneer's historical and future financial performance. These non-GAAP financial measures are not intended to be substitutes for the comparable GAAP measure and should be read only in conjunction with Pioneer's consolidated financial statements prepared in accordance with GAAP. Unrealized MTM derivative gains and losses and unusual items will recur in future periods; however, the amount and frequency can vary significantly from period to period. The table below reconciles Pioneer's net loss attributable to common stockholders for the three months ended December 31, 2011, as determined in accordance with GAAP, to adjusted loss excluding unrealized MTM derivative losses, and adjusted income excluding MTM derivative losses and unusual items, for that quarter,

		After-tax Amounts		Diluted Amounts Per Share

Net loss attributable to common stockholders		$	(111)	$	(0.93)
	Unrealized MTM derivative losses		22		0.18
Adjusted loss excluding unrealized MTM derivative losses			(89)		(0.75)

	Alaska production tax credit recoveries		(7)		(0.05)
	Impairment of dry gas properties in South Texas		223		1.83
	Abandonment of unproved dry gas acreage		20		0.16
Adjusted income excluding unrealized MTM derivative losses and unusual items		$	147	$	1.19

PIONEER NATURAL RESOURCES COMPANY

SUPPLEMENTAL INFORMATION

Open Commodity Derivative Positions as of February 3, 2012

(Volumes are average daily amounts)

				Twelve Months Ending December 31,

				2012		2013		2014		2015

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

__________

(a)	Represents weighted average index price per Bbl of each NGL component.
(b)	Represents the NYMEX Henry Hub index price or approximate NYMEX Henry Hub index price based on historical differentials to the index price on the derivative trade date.
(c)	Represent swaps that fix the basis differentials between the indices price at which the Company sells its Permian Basin, Mid-Continent and Gulf Coast gas and the NYMEX Henry Hub index price used in gas swap contracts.

Permian Basin roll adjustment swap derivatives. The Company uses ''roll adjustment'' swap derivatives to mitigate the timing risk associated with the sales price of oil in the Permian Basin. In the Permian Basin, the Company generally sells its oil at a sales price based on the calendar month average NYMEX price of oil during that month, plus an adjustment calculated as the weighted average spread between the NYMEX price for that delivery month and (i) the next month and (ii) the following month during the period when the delivery month is prompt. The Company has roll adjustment swap derivatives for 3,000 Bbls per day of March 2012 through May 2012 oil sales and for 3,000 Bbls per day of oil sales for the year 2013. Under the terms of the roll adjustment swap

derivatives, the Company pays the periodic variable roll adjustments and receives a fixed price of $0.28 per Bbl for March 2012 through May 2012 and $0.43 per Bbl for the year 2013. The Permian Basin roll adjustment swap derivatives are not included in the table presented above.

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

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

Amortization of Deferred Revenue Associated with Volumetric Production Payments and Derivative Losses as of December 31, 2011

(in thousands)

		2012
		First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total

Total deferred revenues (a)		$	10,459	$	10,460	$	10,575	$	10,575	$	42,069
Less derivative losses to be recognized in
	pretax earnings (b)		(810)		(791)		(784)		(772)		(3,157)

Total VPP impact to pretax earnings		$	9,649	$	9,669	$	9,791	$	9,803	$	38,912

__________

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

Derivative Gains, Net

(in thousands)

				Three Months Ended December 31, 2011		Twelve Months Ended December 31, 2011
Noncash changes in fair value:
	Oil derivative gains (losses)			$	(188,726)	$	68,376
	NGL derivative gains				10,055		10,243
	Gas derivative gains				133,832		179,787
	Diesel derivative gains				888		270
	Interest rate derivative losses				(2,990)		(33,206)
		Total noncash derivative gains (losses), net (a)			(46,941)		225,470

Cash settled changes in fair value:
	Oil derivative losses				(1,358)		(36,664)
	NGL derivative losses				(3,615)		(15,418)
	Gas derivative gains				58,538		182,993
	Diesel derivative gains				10		67
	Interest rate derivative gains				-		36,304
		Total cash derivative gains, net			53,575		167,282
			Total derivative gains, net	$	6,634	$	392,752

__________

(a)	Total unrealized mark-to-market derivative gains, net includes $12.8 million of loss and $7.2 million of gains attributable to noncontrolling interests in consolidated subsidiaries during the three and twelve months ended December 31, 2011, respectively.

Attached files

Stock widget

Investing forum

PIONEER NATURAL RESOURCES CO Reports