exv99w3

REPORT OF INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM

The Board of Directors and Stockholders of
Pioneer Natural Resources Company:

We have audited the accompanying consolidated balance sheets of Pioneer Natural Resources Company (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of operations, stockholders’ equity, cash flows and comprehensive income for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of the Company at December 31, 2006 and 2005, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.

As discussed in Note B to the consolidated financial statements, in 2006 the Company adopted Statement of Financial Accounting Standards No. 123(R), “Share-Based Payment,” and No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.”

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 19, 2007 expressed an unqualified opinion thereon.

Ernst & Young LLP

Dallas, Texas
February 19, 2007, except for the matters related to the
sale of the Canadian assets described in Notes A,B and V
as to which the date is January 10, 2008

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)


	December 31,
	2006			2005
ASSETS
Current assets:
Cash and cash equivalents	$	7,033		$	18,802
Accounts receivable:
Trade, net of allowance for doubtful accounts of $6,999 and $5,736 as of December 31, 2006 and 2005, respectively		195,534			334,864
Due from affiliates		3,837			1,596
Income taxes receivable		24,693			1,198
Inventories		95,131			79,659
Prepaid expenses		11,509			18,091
Deferred income taxes		82,927			158,878
Other current assets:
Derivatives		63,665			1,246
Other, net of allowance for doubtful accounts of $6,425 as of December 31, 2005		52,229			9,470

Total current assets		536,558			623,804

Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting:
Proved properties		7,967,708			8,499,253
Unproved properties		210,344			313,881
Accumulated depletion, depreciation and amortization		(1,895,408	)		(2,577,946	)

Total property, plant and equipment		6,282,644			6,235,188

Deferred income taxes		345			—
Goodwill		309,908			311,651
Other property and equipment, net		131,840			90,010
Other assets:
Derivatives		4,333			1,048
Other, net of allowance for doubtful accounts of $4,045 and $92 as of December 31, 2006 and 2005, respectively		89,771			67,533

	$	7,355,399		$	7,329,234

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	332,795		$	330,151
Due to affiliates		17,025			15,053
Interest payable		31,008			40,314
Income taxes payable		12,865			22,470
Other current liabilities:
Derivatives		141,898			320,098
Deferred revenue		181,232			190,327
Other		170,156			114,942

Total current liabilities		886,979			1,033,355

Long-term debt		1,497,162			2,058,412
Derivatives		125,459			431,543
Deferred income taxes		1,172,507			767,329
Deferred revenue		483,279			664,511
Other liabilities and minority interests		205,342			156,982
Stockholders’ equity:
Common stock, $.01 par value; 500,000,000 shares authorized; 122,686,073 and 145,200,293 shares issued at December 31, 2006 and 2005, respectively		1,227			1,452
Additional paid-in capital		2,654,047			3,775,812
Treasury stock, at cost: 1,183,090 and 18,368,109 shares at December 31, 2006 and 2005, respectively		(53,274	)		(882,382	)
Deferred compensation		—			(45,827	)
Retained earnings (accumulated deficit)		497,488			(184,320	)
Accumulated other comprehensive income (loss):
Net deferred hedge losses, net of tax		(167,220	)		(506,636	)
Cumulative translation adjustment		52,403			59,003

Total stockholders’ equity		2,984,671			2,217,102
Commitments and contingencies

	$	7,355,399		$	7,329,234

The accompanying notes are an integral part of these consolidated financial statements.

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)


	Year Ended December 31,
	2006			2005			2004
Revenues and other income:
Oil and gas	$	1,458,940		$	1,338,883		$	962,162
Interest and other		48,390			26,460			1,837
Gain (loss) on disposition of assets, net		(6,459	)		60,063			292

		1,500,871			1,425,406			964,291


Costs and expenses:
Oil and gas production		349,066			309,714			206,093
Depletion, depreciation and amortization		314,081			267,757			208,316
Impairment of long-lived assets		—			644			39,684
Exploration and abandonments		250,196			153,779			94,309
General and administrative		116,595			110,104			69,490
Accretion of discount on asset retirement obligations		3,726			3,349			3,557
Interest		107,050			125,987			101,987
Hurricane activity, net		32,000			39,813			—
Other		36,919			80,723			25,598

		1,209,633			1,091,870			749,034

Income from continuing operations before income taxes		291,238			333,536			215,257
Income tax provision		(141,021	)		(149,231	)		(62,086	)

Income from continuing operations		150,217			184,305			153,171
Income from discontinued operations, net of tax		589,514			350,263			159,683

Net income	$	739,731		$	534,568		$	312,854


Basic earnings per share:
Income from continuing operations	$	1.21		$	1.35		$	1.22
Income from discontinued operations		4.74			2.55			1.28

Net income	$	5.95		$	3.90		$	2.50


Diluted earnings per share:
Income from continuing operations	$	1.19		$	1.32		$	1.21
Income from discontinued operations		4.62			2.48			1.25

Net income	$	5.81		$	3.80		$	2.46


Weighted average shares outstanding:
Basic		124,359			137,110			125,156

Diluted		127,608			141,417			127,488

The accompanying notes are an integral part of these consolidated financial statements.

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(in thousands, except dividends per share)


															Accumulated Other
															Comprehensive Income (Loss)
												Retained			Net Deferred
			Additional									Earnings			Hedge Gains			Cumulative		Total
	Common		Paid-in			Treasury			Deferred			(Accumulated			(Losses), Net			Translation		Stockholders’
	Stock		Capital			Stock			Compensation			Deficit)			of Tax			Adjustment		Equity
Balance as of January 1, 2004	$	1,179	$	2,734,421		$	(5,385	)	$	(9,933	)	$	(887,848	)	$	(104,130	)	$	31,468	$	1,759,772
Acquisition of Evergreen Resources, Inc.		254		947,334			—			(6,001	)		—			—			—		941,587
Dividends declared ($.20 per common share)		—		—			—			—			(26,557	)		—			—		(26,557	)
Exercise of long-term incentive plan stock options and employee stock purchases		—		(2,185	)		69,848			—			(32,595	)		—			—		35,068
Purchase of treasury stock		—		—			(92,256	)		—			—			—			—		(92,256	)
Tax benefits related to stock-based compensation		—		6,612			—			—			—			—			—		6,612
Compensation costs:
Compensation awards		5		19,122			—			(19,127	)		—			—			—		—
Compensation costs included in net income		—		—			—			12,503			—			—			—		12,503
Net income		—		—			—			—			312,854			—			—		312,854
Other comprehensive income (loss):
Deferred hedging activity, net of tax:
Net deferred hedge losses		—		—			—			—			—			(291,642	)		—		(291,642	)
Net hedge losses included in continuing operations		—		—			—			—			—			75,737			—		75,737
Net hedge losses included in discontinued operations		—		—			—			—			—			78,685			—		78,685
Translation adjustment		—		—			—			—			—			—			19,417		19,417

Balance as of December 31, 2004	$	1,438	$	3,705,304		$	(27,793	)	$	(22,558	)	$	(634,146	)	$	(241,350	)	$	50,885	$	2,831,780


Dividends declared ($.22 per common share)		—		—			—			—			(30,339	)		—			—		(30,339	)
Exercise of long-term incentive plan stock options and employee stock purchases		—		1,310			94,670			—			(54,403	)		—			—		41,577
Purchase of treasury stock		—		—			(949,259	)		—			—			—			—		(949,259	)
Tax benefits related to stock-based compensation		—		18,752			—			—			—			—			—		18,752
Compensation costs:
Compensation awards		14		56,146			—			(56,160	)		—			—			—		—
Compensation costs included in net income		—		—			—			26,857			—			—			—		26,857
Forfeiture of deferred compensation		—		(5,700	)		—			6,034			—			—			—		334
Net income		—		—			—			—			534,568			—			—		534,568
Other comprehensive income (loss):
Deferred hedging activity, net of tax:
Net deferred hedge losses		—		—			—			—			—			(539,384	)		—		(539,384	)
Net hedge losses included in continuing operations		—		—			—			—			—			180,941			—		180,941
Net hedge losses included in discontinued operations		—		—			—			—			—			93,157			—		93,157
Translation adjustment		—		—			—			—			—			—			8,118		8,118

Balance as of December 31, 2005	$	1,452	$	3,775,812		$	(882,382	)	$	(45,827	)	$	(184,320	)	$	(506,636	)	$	59,003	$	2,217,102

The accompanying notes are an integral part of these consolidated financial statements.

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (Continued)
(in thousands, except dividends per share)


															Accumulated Other Comprehensive Income (Loss)
												Retained			Net Deferred
				Additional								Earnings			Hedge Gains			Cumulative			Total
	Common			Paid-in			Treasury			Deferred		(Accumulated			(Losses), Net			Translation			Stockholders’
	Stock			Capital			Stock			Compensation		Deficit)			of Tax			Adjustment			Equity
Dividends declared ($.25 per share)	$	—		$	—		$	—		$	—	$	(31,726	)	$	—		$	—		$	(31,726	)
Conversion of senior notes		—			(85,023	)		107,023			—		—			—			—			22,000
Exercise of long-term incentive plan stock options and employee stock purchases		—			4,010			39,568			—		(26,197	)		—			—			17,381
Purchase of treasury stock		—			—			(348,945	)		—		—			—			—			(348,945	)
Tax benefits related to stock-based compensation		—			4,247			—			—		—			—			—			4,247
Compensation costs:
Adoption of SFAS No. 123(R)		—			(45,827	)		—			45,827		—			—			—			—
Compensation awards		4			(4	)		—			—		—			—			—			—
Compensation costs included in net income		—			32,065			—			—		—			—			—			32,065
Net income		—			—			—			—		739,731			—			—			739,731
Retirement of shares		(229	)		(1,031,233	)		1,031,462			—		—			—			—			—
Other comprehensive income (loss):
Deferred hedging activity, net of tax:
Net deferred hedge gains		—			—			—			—		—			118,139			—			118,139
Net hedge losses included in continuing operations		—			—			—			—		—			96,530			—			96,530
Net hedge losses included in discontinued operations		—			—			—			—		—			124,747			—			124,747
Translation adjustment		—			—			—			—		—			—			(6,600	)		(6,600	)

Balance as of December 31, 2006	$	1,227		$	2,654,047		$	(53,274	)	$	—	$	497,488		$	(167,220	)	$	52,403		$	2,984,671

The accompanying notes are an integral part of these consolidated financial statements.

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)


	Year Ended December 31,
	2006			2005			2004
Cash flows from operating activities:
Net income	$	739,731		$	534,568		$	312,854
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization		314,081			267,757			208,316
Impairment of long-lived assets		—			644			39,684
Exploration expenses, including dry holes		140,135			49,037			25,018
Hurricane activity		75,000			39,813			—
Deferred income taxes		161,761			99,379			44,521
Loss (gain) on disposition of assets, net		6,459			(60,063	)		(292	)
Loss (gain) on extinguishment of debt		8,076			25,975			(95	)
Accretion of discount on asset retirement obligations		3,726			3,349			3,557
Discontinued operations		(489,959	)		423,728			540,053
Interest expense		11,042			4,399			(13,413	)
Commodity hedge related activity		(8,443	)		18,181			(45,102	)
Amortization of stock-based compensation		32,065			26,857			12,503
Amortization of deferred revenue		(190,327	)		(75,773	)		—
Other noncash items		14,486			19,563			15,002
Change in operating assets and liabilities, net of effects from acquisitions and dispositions:
Accounts receivable, net		121,360			(128,015	)		(73,376	)
Income taxes receivable		(23,495	)		(1,198	)		—
Inventories		(48,060	)		(36,948	)		(14,025	)
Prepaid expenses		4,808			(7,504	)		974
Other current assets, net		(42,484	)		972			262
Accounts payable		(36,085	)		83,960			250
Interest payable		(6,500	)		(7,115	)		5,533
Income taxes payable		(3,695	)		8,950			3,372
Other current liabilities		(28,854	)		(13,362	)		(14,037	)

Net cash provided by operating activities		754,828			1,277,154			1,051,559

Cash flows from investing activities:
Payments for acquisitions, net of cash acquired		—			(965	)		(880,365	)
Proceeds from dispositions of assets, net of cash sold		1,644,829			1,248,581			1,709
Additions to oil and gas properties		(1,403,879	)		(1,123,297	)		(562,907	)
Additions to other assets and other property and equipment, net		(95,435	)		(39,585	)		(36,970	)

Net cash provided by (used in) investing activities		145,515			84,734			(1,478,533	)

Cash flows from financing activities:
Borrowings under long-term debt		1,426,490			1,203,190			1,157,903
Principal payments on long-term debt		(1,981,164	)		(1,556,763	)		(604,475	)
Borrowings (payments) of other liabilities, net		610			(60,129	)		(54,252	)
Exercise of long-term incentive plan stock options and employee stock purchases		17,381			41,577			35,068
Purchase of treasury stock		(348,945	)		(949,259	)		(92,256	)
Excess tax benefits from share-based payment arrangements		5,989			—			—
Payment of financing fees		(2,178	)		(1,911	)		(1,173	)
Dividends paid		(31,726	)		(30,339	)		(26,557	)

Net cash provided by (used in) financing activities		(913,543	)		(1,353,634	)		414,258

Net increase (decrease) in cash and cash equivalents		(13,200	)		8,254			(12,716	)
Effect of exchange rate changes on cash and cash equivalents		1,431			3,291			674
Cash and cash equivalents, beginning of year		18,802			7,257			19,299

Cash and cash equivalents, end of year	$	7,033		$	18,802		$	7,257

The accompanying notes are an integral part of these consolidated financial statements.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

NOTE A. Organization and Nature of Operations

Pioneer Natural Resources Company (“Pioneer” or the “Company”) is a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. The Company is a large independent oil and gas exploration and production company with continuing operations for the stated periods in the United States, Equatorial Guinea, Nigeria, South Africa and Tunisia.

Recast of consolidated financial statements and notes to consolidated financial statements. During November 2007, the Company completed the divestiture of its Canadian assets. In accordance with the discontinued operations provisions of Statement of Financial Accounting Standards (“SFAS”) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”), the accompanying consolidated financial statements and notes to consolidated financial statements have been revised to present the results of operations, comprehensive income and cash flows of the Company’s Canadian assets as discontinued operations. All periods presented have been recast to reflect this revision. Accordingly, the following notes to consolidated financial statements and the unaudited supplementary data have been revised: A, B, D, F, I, J, L, M, O, P, Q, R and V. Additionally, Note W has been added to the recast of the consolidated financial statements to disclose subsequent events.

NOTE B. Summary of Significant Accounting Policies

Principles of consolidation. The consolidated financial statements include the accounts of the Company and its wholly-owned and majority-owned subsidiaries since their acquisition or formation. The Company proportionately consolidates less than 100 percent-owned affiliate partnerships, for which certain of its wholly-owned subsidiaries serve as general partners, involved in oil and gas producing activities in accordance with Emerging Issues Task Force (“EITF”) Abstract Issue No. 00-1, “Investor Balance Sheet and Income Statement Display under the Equity Method for Investments in Certain Partnerships and Other Ventures”. The Company owns less than a 22 percent interest in the oil and gas partnerships that it proportionately consolidates. All material intercompany balances and transactions have been eliminated.

Minority interests in consolidated subsidiaries. The Company owns the majority interests in certain subsidiaries with operations in the United States and Nigeria. Associated therewith, the Company has recognized minority interests in consolidated subsidiaries of $14.4 million and $9.3 million in other liabilities and minority interests in the accompanying Consolidated Balance Sheets as of December 31, 2006 and 2005, respectively.

Minority interests in the net losses of the Company’s consolidated Nigerian subsidiary totaled $4.9 million and $5.2 million for the years ended December 31, 2006 and 2005, respectively, and are included in interest and other income in the accompanying Consolidated Statements of Operations. Minority interests in the net income of the Company’s consolidated United States subsidiaries totaled $2.6 million, $3.5 million and $.9 million for the years ended December 31, 2006, 2005 and 2004, respectively, and are included in other expense in the accompanying Consolidated Statements of Operations.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

Discontinued operations. During 2005, 2006 and 2007, the Company sold its interests in the following oil and gas asset groups:


Country	Description of Asset Groups	Date Divested
Canada	Martin Creek, Conroy Black and Lookout Butte fields	May 2005

United States	Two Gulf of Mexico shelf fields	August 2005

United States	Deepwater Gulf of Mexico fields	March 2006

Argentina	Argentine assets	April 2006

Canada	Canadian assets	November 2007

In accordance with SFAS 144, the Company has reflected the results of operations of the above divestitures as discontinued operations, rather than as a component of continuing operations. See Note V for additional information regarding discontinued operations.

Use of estimates in the preparation of financial statements. Preparation of the accompanying consolidated financial statements in conformity with generally accepted accounting principles in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Depletion of oil and gas properties and impairment of goodwill and oil and gas properties, in part, is determined using estimates of proved oil and gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves; commodity price outlooks; foreign laws, restrictions and currency exchange rates; and export and excise taxes. Actual results could differ from the estimates and assumptions utilized.

Argentina. In April 2006, the Company sold its Argentine assets and is currently winding-up the affairs associated with its remaining Argentine entity. As of December 31, 2006 and 2005, the Company used exchange rates of 3.06 pesos to $1 and 3.03 pesos to $1, respectively, to remeasure the peso-denominated monetary assets and liabilities of the Company’s Argentine subsidiaries. The Company remains exposed to uncertainties surrounding the Argentine economic and political environment until the Company completes (i) the distribution of its remaining sales proceeds to the United Sates, (ii) the liquidation of its remaining Argentine entity and (iii) its obligations under the indemnifications and retained obligations related to the divesture of the Argentine assets.

Cash equivalents. Cash and cash equivalents include cash on hand and depository accounts held by banks.

Investments. Investments in unaffiliated equity securities that have a readily determinable fair value are classified as “trading securities” if management’s current intent is to hold them for the near term; otherwise, they are accounted for as “available-for-sale” securities. The Company reevaluates the classification of investments in unaffiliated equity securities at each balance sheet date. The carrying value of trading securities and available-for-sale securities are adjusted to fair value as of each balance sheet date.

Unrealized holding gains are recognized for trading securities in interest and other income, and unrealized holding losses are recognized in other expense during the periods in which changes in fair value occur.

Unrealized holding gains and losses are recognized for available-for-sale securities as credits or charges to stockholders’ equity and other comprehensive income (loss) during the periods in which changes in fair value occur.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

Realized gains and losses on the divestiture of available-for-sale securities are determined using the average cost method. The Company had no investments in available-for-sale securities as of December 31, 2006 or 2005.

Investments in unaffiliated equity securities that do not have a readily determinable fair value are measured at the lower of their original cost or the net realizable value of the investment. The Company had no significant equity security investments that did not have a readily determinable fair value as of December 31, 2006 or 2005.

Inventories. Inventories were comprised of $93.7 million and $77.3 million of materials and supplies and $1.4 million and $2.4 million of commodities as of December 31, 2006 and 2005, respectively. The Company’s materials and supplies inventory is primarily comprised of oil and gas drilling or repair items such as tubing, casing, chemicals, operating supplies and ordinary maintenance materials and parts. The materials and supplies inventory is primarily acquired for use in future drilling operations or repair operations and is carried at the lower of cost or market, on a weighted average cost basis. Commodities inventory is carried at the lower of average cost or market, on a first-in, first-out basis. Any impairments of inventory are reflected in gain (loss) on disposition of assets in the Consolidated Statements of Operations. As of December 31, 2006 and 2005, the Company’s materials and supplies inventory was net of $4.2 million and $.2 million, respectively, of valuation reserve allowances.

Oil and gas properties. The Company utilizes the successful efforts method of accounting for its oil and gas properties. Under this method, all costs associated with productive wells and nonproductive development wells are capitalized while nonproductive exploration costs and geological and geophysical expenditures are expensed. The Company capitalizes interest on expenditures for significant development projects, generally when the underlying project is sanctioned, until such projects are ready for their intended use.

The Company generally does not carry the costs of drilling an exploratory well as an asset in its Consolidated Balance Sheets for more than one year following the completion of drilling unless the exploratory well finds oil and gas reserves in an area requiring a major capital expenditure and both of the following conditions are met:

	(i)		The well has found a sufficient quantity of reserves to justify its completion as a producing well.

	(ii)		The Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

Due to the capital intensive nature and the geographical location of certain Alaskan, deepwater Gulf of Mexico and foreign projects, it may take the Company longer than one year to evaluate the future potential of the exploration well and economics associated with making a determination on its commercial viability. In these instances, the project’s feasibility is not contingent upon price improvements or advances in technology, but rather the Company’s ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies’ production, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and being pursued constantly. Consequently, the Company’s assessment of suspended exploratory well costs is continuous until a decision can be made that the well has found proved reserves or is noncommercial and is impaired. See Note D for additional information regarding the Company’s suspended exploratory well costs.

The Company owns interests in seven natural gas processing plants and seven treating facilities. The Company operates five of the plants and all seven treating facilities. The Company’s ownership interests in the natural gas processing plants and treating facilities is primarily to accommodate handling the Company’s gas production and thus are considered a component of the capital and operating costs of the respective fields that they service. To the extent that there is excess capacity at a plant or treating facility, the Company attempts to process third party gas volumes for a fee to keep the plant or treating facility at capacity. All revenues and expenses derived from third party gas volumes processed through the plants and treating facilities are reported as components of oil and gas production costs. Third party revenues generated from the plant and treating facilities for the three years ended December 31, 2006, 2005 and 2004 were $38.5 million, $39.2 million and $32.1 million, respectively. Third party expenses attributable to the plants and treating facilities for the same respective periods were $6.4 million, $13.8 million and $11.8 million. The capitalized costs of the plants and treating facilities are included in proved oil

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

and gas properties and are depleted using the unit-of-production method along with the other capitalized costs of the field that they service.

Capitalized costs relating to proved properties are depleted using the unit-of-production method based on proved reserves. Costs of significant nonproducing properties, wells in the process of being drilled and development projects are excluded from depletion until such time as the related project is completed and proved reserves are established or, if unsuccessful, impairment is determined.

Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion, depreciation and amortization. Generally, no gain or loss is recognized until the entire amortization base is sold. However, gain or loss is recognized from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the depletion base.

In accordance with SFAS No. 144, the Company reviews its long-lived assets to be held and used, including proved oil and gas properties accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future cash flows is less than the carrying amount of the assets. In this circumstance, the Company recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset.

Unproved oil and gas properties are periodically assessed for impairment on a project-by-project basis. The impairment assessment is affected by the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. If the quantity of potential reserves determined by such evaluations is not sufficient to fully recover the cost invested in each project, the Company will recognize an impairment loss at that time by recording an allowance.

Goodwill. As described in Note C, the Company recorded $327.8 million of goodwill associated with the merger with Evergreen Resources, Inc. (“Evergreen”). The goodwill was recorded to the Company’s United States reporting unit. In accordance with EITF Abstract Issue No. 00-23, “Issues Related to the Accounting for Stock Compensation under APB Opinion No. 25 and FASB Interpretation No. 44”, the Company has reduced goodwill by $18.0 million since September 28, 2004 for tax benefits associated with the exercise of fully-vested stock options assumed in conjunction with the Evergreen merger. In accordance with SFAS No. 142, “Goodwill and Other Intangible Assets”, goodwill is not amortized to earnings, but is assessed for impairment whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely, but no less often than annually. If the carrying value of goodwill is determined to be impaired, it is reduced for the impaired value with a corresponding charge to pretax earnings in the period in which it is determined to be impaired. During the third quarter of 2006, the Company performed its annual assessment of impairment of the goodwill and determined that there was no impairment.

Other property, plant and equipment, net. Other property, plant and equipment is stated at cost and primarily consists of items such as heavy equipment and rigs, furniture and fixtures and leasehold improvements. Depreciation is provided over the estimated useful life of the assets using the straight-line method. At December 31, 2006 and 2005, other property, plant and equipment was net of accumulated depreciation of $145.3 million and $131.5 million, respectively.

Asset retirement obligations. The Company accounts for asset retirement obligations in accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”). SFAS 143 amended SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” to require that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. Under the provisions of SFAS 143, asset retirement obligations are generally capitalized as part of the carrying value of the long-lived asset.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143” (“FIN 47”). FIN 47 clarifies that conditional asset retirement obligations meet the definition of liabilities and should be recognized when incurred if their fair values can be reasonably estimated. The interpretation was adopted by the Company on December 31, 2005. The adoption of FIN 47 had no impact on the Company’s financial position or results of operations.

Derivatives and hedging. The Company follows the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”). SFAS 133 requires the accounting recognition of all derivative instruments as either assets or liabilities at fair value. Derivative instruments that are not hedges must be adjusted to fair value through net income. Under the provisions of SFAS 133, the Company may designate a derivative instrument as hedging the exposure to changes in the fair value of an asset or a liability or an identified portion thereof that is attributable to a particular risk (a “fair value hedge”) or as hedging the exposure to variability in expected future cash flows that are attributable to a particular risk (a “cash flow hedge”). Both at the inception of a hedge and on an ongoing basis, a fair value hedge must be expected to be highly effective in achieving offsetting changes in fair value attributable to the hedged risk during the periods that a hedge is designated. Similarly, a cash flow hedge must be expected to be highly effective in achieving offsetting cash flows attributable to the hedged risk during the term of the hedge. The expectation of hedge effectiveness must be supported by matching the essential terms of the hedged asset, liability or forecasted transaction to the derivative hedge contract or by effectiveness assessments using statistical measurements. The Company’s policy is to assess hedge effectiveness at the end of each calendar quarter.

Under the provisions of SFAS 133, changes in the fair value of derivative instruments that are fair value hedges are offset against changes in the fair value of the hedged assets, liabilities, or firm commitments through net income. Effective changes in the fair value of derivative instruments that are cash flow hedges are recognized in accumulated other comprehensive income (loss) — net deferred hedge losses, net of tax (“AOCI — Hedging”) in the stockholders’ equity section of the Company’s Consolidated Balance Sheets until such time as the hedged items are recognized in net income. Ineffective portions of a derivative instrument’s change in fair value are immediately recognized in earnings.

See Note J for a description of the specific types of derivative transactions in which the Company participates.

Environmental. The Company’s environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Expenditures that extend the life of the related property or mitigate or prevent future environmental contamination are capitalized. Liabilities are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are undiscounted unless the timing of cash payments for the liability is fixed or reliably determinable.

Treasury stock. Treasury stock purchases are recorded at cost. Upon reissuance, the cost of treasury shares held is reduced by the average purchase price per share of the aggregate treasury shares held. During 2006, the Company retired 22.9 million treasury shares resulting in a reduction in treasury stock of $1.0 billion.

Revenue recognition. The Company does not recognize revenues until they are realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller’s price to the buyer is fixed or determinable and (iv) collectibility is reasonably assured.

The Company uses the entitlements method of accounting for oil, natural gas liquid (“NGL”) and gas revenues. Sales proceeds in excess of the Company’s entitlement are included in other liabilities and the Company’s share of sales taken by others is included in other assets in the accompanying Consolidated Balance Sheets.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

The Company had no material oil or NGL entitlement assets or liabilities as of December 31, 2006 or 2005. The following table presents the Company’s gas entitlement assets and liabilities and their associated volumes as of December 31, 2006 and 2005:


	December 31,
	2006				2005
	Amount		MMcf		Amount		MMcf
			($ in millions)
Entitlement assets	$	13.0		4,201	$	12.1		4,007
Entitlement liabilities	$	3.9		1,082	$	8.5		7,206

Stock-based compensation. On January 1, 2006, the Company adopted SFAS No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123(R)”) to account for stock-based compensation. Among other items, SFAS 123(R) eliminates the use of the Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”), intrinsic value method of accounting and requires companies to recognize the cost of employee services received in exchange for awards of equity instruments based on the grant date fair value of those awards in the financial statements. The Company elected to use the modified prospective method for adoption of SFAS 123(R), which requires compensation expense to be recorded for all unvested stock options and other equity-based compensation beginning in the first quarter of adoption. For all unvested stock options outstanding as of January 1, 2006, the previously measured but unrecognized compensation expense, based on the fair value on the date of grant, was recognized in the Company’s financial statements over their remaining vesting periods, which ended in August 2006. For equity-based compensation awards granted or modified subsequent to January 1, 2006, compensation expense, based on the fair value on the date of grant, is being recognized in the Company’s financial statements over the vesting period. The Company utilizes the Black-Scholes option pricing model to measure the fair value of stock options and utilizes the stock price on the date of grant for the fair value of restricted stock awards. Prior to the adoption of SFAS 123(R), the Company followed the intrinsic value method in accordance with APB 25 to account for stock options. Prior period financial statements have not been restated. The modified prospective method requires the Company to estimate forfeitures in calculating the expense related to stock-based compensation as opposed to its prior policy of recognizing forfeitures as they occurred. The Company recorded no cumulative effect as a result of adopting SFAS 123(R).

Additionally, under the provisions of SFAS 123(R), deferred compensation recorded under APB 25 related to equity-based awards should be eliminated against the appropriate equity accounts. As a result, upon adoption of SFAS 123(R), the Company eliminated $45.8 million of deferred compensation cost in stockholders’ equity and reduced a like amount of additional paid-in capital in the accompanying Consolidated Balance Sheets.

For the year ended December 31, 2006, the Company recorded $32.1 million of compensation costs for all stock-based plans. The impact to net income of adopting SFAS 123(R) was $1.6 million for the year ended December 31, 2006, or less than $.02 per diluted share. For the year ended December 31, 2006, the adoption impact is comprised of $959 thousand of compensation expense associated with stock options and $669 thousand of compensation expense associated with the Company’s Employee Stock Purchase Plan (the “ESPP”), which is a compensatory plan under the provisions of SFAS 123(R).

Pursuant to the provisions of SFAS 123(R), the Company’s issued shares, as reflected in the accompanying Consolidated Balance Sheets at December 31, 2006 and 2005, do not include 1,946,211 shares and 1,756,180 shares, respectively, related to unvested restricted stock awards.

As of December 31, 2006, there was approximately $39.8 million of unrecognized compensation expense related to unvested share-based compensation plan awards, primarily related to restricted stock awards. This compensation will be recognized on a straight-line basis over the remaining vesting periods of the awards, which is a remaining period of less than three years.

The following table illustrates the pro forma effect on net income and net income per share as if the Company had applied the fair value recognition provisions of SFAS No. 123(R) to stock-based compensation during the years ended December 31, 2005 and 2004:

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004


	Year Ended December 31,
	2005			2004
	(in thousands, except
	per share amounts)
Net income, as reported	$	534,568		$	312,854
Plus: Stock-based compensation expense included in net income for all awards, net of tax (a)		17,054			7,939
Deduct: Stock-based compensation expense determined under fair value based method for all awards, net of tax (a)		(19,772	)		(13,985	)

Pro forma net income	$	531,850		$	306,808

Net income per share:
Basic — as reported	$	3.90		$	2.50

Basic — pro forma	$	3.88		$	2.45

Diluted — as reported	$	3.80		$	2.46

Diluted — pro forma	$	3.78		$	2.41


(a)		For the years ended December 31, 2005 and 2004, stock-based compensation expense included in net income is net of tax benefits of $9.8 million and $4.6 million, respectively. Similarly, stock-based compensation expense determined under the fair value based method for the years ended December 31, 2005 and 2004 is net of tax benefits of $11.4 million and $8.0 million, respectively. See Note P for additional information regarding the Company’s income taxes.

Foreign currency translation. The U.S. dollar is the functional currency for all of the Company’s international operations except Canada. Accordingly, monetary assets and liabilities denominated in a foreign currency are remeasured to U.S. dollars at the exchange rate in effect at the end of each reporting period; revenues and costs and expenses denominated in a foreign currency are remeasured at the average of the exchange rates that were in effect during the period in which the revenues and costs and expenses were recognized. The resulting gains or losses from remeasuring foreign currency denominated balances into U.S. dollars are recorded in other income or other expense, respectively. Nonmonetary assets and liabilities denominated in a foreign currency are remeasured at the historic exchange rates that were in effect when the assets or liabilities were acquired or incurred.

The functional currency of the Company’s Canadian operations is the Canadian dollar. The financial statements of the Company’s Canadian subsidiaries are translated to U.S. dollars as follows: all assets and liabilities are translated using the exchange rate in effect at the end of each reporting period; revenues and costs and expenses are translated using the average of the exchange rates that were in effect during the period in which the revenues and costs and expenses were recognized. The resulting gains or losses from translating non-U.S. dollar denominated balances are recorded in the accompanying Consolidated Statements of Stockholders’ Equity for the period through accumulated other comprehensive income (loss) — cumulative translation adjustment.

The following table presents the exchange rates used to translate the financial statements of the Company’s Canadian subsidiaries in the preparation of the consolidated financial statements as of and for the years ended December 31, 2006, 2005 and 2004:


	December 31,
	2006		2005		2004
U.S. Dollar from Canadian Dollar — Balance Sheets		.8577		.8606		.8320
U.S. Dollar from Canadian Dollar — Statements of Operations		.8817		.8279		.7699

Reclassifications. Certain reclassifications have been made to the 2005 and 2004 amounts in order to conform with the 2006 presentation. Specifically, the Company reduced its exploration and abandonments expense

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

by $39.8 million for the year ended December 31, 2005, which represents reclassification of abandonment costs for the Company’s East Cameron facility destroyed by Hurricane Rita to hurricane activity, net expense on the accompanying Consolidated Statements of Operations and Consolidated Statements of Cash Flows. Additionally, $18.2 million of unfunded check issuances were reclassified from changes in accounts payable in operating cash flows to payment of other liabilities in net cash flows from financing activities within the Consolidated Statements of Cash Flows for the year ended December 31, 2005.

New accounting pronouncements. The following discussions provide information about new accounting pronouncements that were issued by FASB during 2006:

FIN 48. In July 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”). The Interpretation clarifies the accounting for income taxes by prescribing a minimum recognition threshold that a tax position is required to meet before being recognized in the financial statements. FIN 48 also provides guidance on measurement, classification, interim accounting and disclosure. FIN 48 is effective for fiscal years beginning after December 15, 2006. The Company is continuing to assess the potential impacts of this Interpretation.

SFAS 157. In September 2006, the FASB issued SFAS No. 157, “Fair Value Measures” (“SFAS 157”). SFAS 157 defines fair value, establishes a framework for measuring fair value and enhances disclosures about fair value measures required under other accounting pronouncements, but does not change existing guidance as to whether or not an instrument is carried at fair value. SFAS 157 is effective for fiscal years beginning after November 15, 2007. The Company is continuing to assess the impact, if any, of SFAS 157.

SFAS 158. In September 2006, the FASB issued SFAS 158, “Employers’ Accounting for Defined Benefit Pension and other Postretirement Plans” (“SFAS 158”). Under SFAS 158, a business entity that sponsors one or more single-employer defined benefit plans is required to:

	•		recognize the funded status of a benefit plan in its balance sheet, measured as the difference between plan assets at fair value (with limited exceptions) and the benefit obligation,

	•		recognize as a component of other comprehensive income, net of tax, the gains or losses and prior service costs or credits that arise during the period, but are not recognized as components of net periodic benefit cost,

	•		measure defined benefit plan assets and obligations as of the date of the employer’s balance sheet and

	•		disclose in the notes to financial statements additional information about certain effects on net periodic benefit cost for the next fiscal year that arise from delayed recognition of the gains or losses, prior service costs or credits, and transition assets or obligations.

An employer with publicly traded securities is required to initially recognize the funded status of its defined benefit postretirement plans and to provide the required disclosures as of the end of the first fiscal year ending after December 15, 2006. The Company adopted the provisions of SFAS 158 effective on December 31, 2006. The Company previously recognized the funded status of its defined benefit postretirement plans and currently recognizes periodic changes in its defined benefit postretirement plans as components of service costs in the period of change as allowed by SFAS 158. Consequently, the adoption of SFAS 158 did not have a material impact on the Company’s liquidity, financial position or future results of operations. See Note H of Notes to Consolidated Financial Statements in “Item 8. Financial Statements and Supplementary Data” for additional information regarding the Company’s postretirement plans.

NOTE C. Acquisitions

Evergreen merger. On September 28, 2004, Pioneer completed a merger with Evergreen, with Pioneer being the surviving corporation for accounting purposes. The transaction was accounted for as a purchase of Evergreen by Pioneer. As a result, the financial statements for the Company prior to September 28, 2004 are those of Pioneer only. The merger with Evergreen was accomplished through the issuance of 25.4 million shares of Pioneer common stock and $851.1 million of cash paid to Evergreen shareholders at closing, net of $12.1 million of acquired cash. The cash consideration paid in the merger was financed through borrowings on the Company’s credit facilities.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

The Company recorded $327.8 million of goodwill associated with the Evergreen merger, which represented the excess of the purchase consideration over the net fair value of the identifiable net assets acquired.

Permian Basin and Onshore Gulf Coast acquisitions. During 2006 and 2005, the Company spent $71.2 million and $167.8 million, respectively, to acquire various working interests in the Spraberry and South Texas areas.

NOTE D. Exploratory Well Costs

The Company capitalizes exploratory well costs until a determination is made that the well has either found proved reserves or that it is impaired. The capitalized exploratory well costs are presented in proved properties in the Consolidated Balance Sheets. If the exploratory well is determined to be impaired, the well costs are charged to expense.

The following table reflects the Company’s capitalized exploratory well activity during each of the years ended December 31, 2006, 2005 and 2004:


	Year Ended December 31,
	2006			2005			2004
				(in thousands)
Beginning capitalized exploratory well costs	$	198,291		$	126,472		$	108,986
Additions to exploratory well costs pending the determination of proved reserves		451,109			243,272			156,937
Reclassifications due to determination of proved reserves		(193,480	)		(78,334	)		(56,639	)
Disposition of wells sold		(52,628	)		—			—
Exploratory well costs charged to exploration expense (a)		(138,239	)		(93,119	)		(82,812	)

Ending capitalized exploratory well costs	$	265,053		$	198,291		$	126,472


(a)		Includes exploratory well costs of discontinued operations of $11.1 million, $46.4 million and $58.3 million in 2006, 2005 and 2004, respectively.

The following table provides an aging as of December 31, 2006, 2005 and 2004 of capitalized exploratory well costs based on the date the drilling was completed and the number of wells for which exploratory well costs have been capitalized for a period greater than one year since the date the drilling was completed:


	Year Ended December 31,
	2006		2005		2004
	(in thousands, except well counts)
Capitalized exploratory well costs capitalized:
One year or less	$	126,749	$	84,042	$	35,046
More than one year		138,304		114,249		91,426

	$	265,053	$	198,291	$	126,472

Number of wells with exploratory well costs that have been capitalized for a period greater than one year		14		14		10

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

The following table provides the capitalized costs of exploration projects that have been suspended for more than one year as of December 31, 2006, 2005 and 2004:


	December 31,
	2006		2005		2004
			(in thousands)
United States:
Clipper (a)	$	75,242	$	—	$	—
Ozona Deep		—		19,423		19,462
Oooguruk		52,205		52,205		47,083
Thunder Hawk		—		25,769		—
United States — other		4,103		—		—
Canada — other		1,695		805		1,214
South Africa		—		7,227		14,895
Tunisia — Anaguid		5,059		8,820		8,772

Total	$	138,304	$	114,249	$	91,426


(a)		Includes $37.0 million of costs incurred in 2006.

The following discussion describes the history and status of each significant suspended exploratory project:

Clipper. During 2005, the Company drilled its first exploratory well on the Clipper prospect, which was a discovery. During 2006, the Company drilled additional wells to determine the magnitude of the discovery. The Company is currently evaluating the plans for development of the discovery, including evaluating sub-sea tie-back options to third-party production and handling facilities in the area. See Note W for additional information.

Ozona Deep and Thunder Hawk. During March 2006, the Company sold its interests in the Ozona Deep and Thunder Hawk properties as part of the Company’s deepwater Gulf of Mexico divestiture. See Note N for additional information regarding the Company’s divestiture of its deepwater Gulf of Mexico oil and gas assets.

Oooguruk. During 2003, the Company’s Alaskan Oooguruk discovery wells found quantities of oil believed to be commercial. In 2003, the Company began farm-in discussions with the owner of undeveloped discoveries in adjacent acreage given its proximity and the potential cost benefits of a larger scale project. The farm-in was completed during 2004. Along with completing the farm-in agreement, Pioneer obtained access to exploration well and seismic data to improve the Company’s understanding of the potential of the discoveries without having to drill additional wells. In late 2004, the Company completed an extensive technical and economic evaluation of the resource potential and a front-end engineering design study (“FEED study”) for the area.

During the first quarter of 2006, the Company sanctioned the development of the discovery and obtained the necessary regulatory approvals. The Company installed an offshore gravel drilling and production site during the 2006 winter construction season and completed armoring activities during the third quarter. A sub-sea flowline and facilities will be installed during 2007 to carry produced liquids to existing onshore processing facilities at the Kuparuk River Unit. Pioneer plans to drill approximately 40 horizontal wells to develop the discovery. Depending on weather conditions and facilities completion and accessibility, drilling could begin as early as the fall of 2007. The Company estimates first production will occur in 2008.

South Africa. During 2001, the Company drilled two South African discovery wells that found quantities of gas and condensate believed to be commercial. From 2002 to 2004, the Company actively reviewed the gas supply and demand fundamentals in South Africa and had discussions with a gas-to-liquids (“GTL”) plant in the area to purchase the condensate and gas. During 2004, a FEED study was authorized for the gas development and infrastructure design. The FEED study was completed in early 2005 and based on that study, the GTL plant operator initiated purchase orders for long-lead time infrastructure components. In December 2005, the Company announced the final approvals with its partner in the South Coast gas project to commence the initial development of the

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

project. As a result, the Company added 11.4 million Bbls oil equivalent (“MMBOE”) of proved reserves in 2005 and reduced the suspended exploratory costs by $7.7 million.

During 2000, the Company drilled two South African exploratory wells in the Company’s Boomslang prospect. One well was unsuccessful, but the other well found quantities of hydrocarbons believed to be commercial. The Boomslang discovery was not included in the initial development phase of the South Coast Gas project. Boomslang is an oil discovery with a significant gas cap. The Company believes the Boomslang discovery may ultimately be developed as a gas discovery, but commercialization plans have not progressed sufficiently to allow the Company to continue to capitalize the exploratory costs related to the discovery. Accordingly, the Company expensed the Boomslang discovery in the fourth quarter of 2006.

Tunisia — Anaguid. During 2003, the Company drilled two exploration wells on its Anaguid Block in Tunisia which found quantities of condensate and gas believed to be commercial. During 2004, the wells were scheduled and approved for extended production tests. However, the project operator delayed the extended production tests due to issues unrelated to the Company or the project. During 2005, the project operator, along with the Company, conducted an extended production test of one of the two existing exploration wells and drilled an offset appraisal well to the other exploration well.

The results of the extended production test were unfavorable and the Company expensed $5.1 million associated with this well in 2005. However, the appraisal well offsetting the second discovery encountered gas and condensate in a similar horizon to the initial well. The Company has concluded studies on the appraisal well with unfavorable results and expensed $4.2 million in the fourth quarter of 2006. Studies on the second discovery will continue to determine whether development is economical. See Note W for additional information.

NOTE E. Disclosures About Fair Value of Financial Instruments

The following table presents the carrying amounts and estimated fair values of the Company’s financial instruments as of December 31, 2006 and 2005:


	December 31,
	2006						2005
	Carrying			Fair			Carrying			Fair
	Value			Value			Value			Value
				(in thousands)
Net derivative contract liabilities:
Commodity price hedges	$	(68,228	)	$	(68,228	)	$	(748,477	)	$	(748,477	)
Terminated commodity price hedges	$	(131,131	)	$	(131,131	)	$	(870	)	$	(870	)
Financial assets:
Trading securities	$	18,582		$	18,582		$	15,237		$	15,237
Notes receivable due 2008 to 2011	$	23,607		$	23,607		$	1,429		$	1,429
Financial liabilities — long-term debt:
Line of credit	$	(328,000	)	$	(328,000	)	$	(900,000	)	$	(900,000	)
8 1/4 % senior notes due 2007	$	(32,081	)	$	(32,511	)	$	(32,199	)	$	(33,477	)
6 1/2 % senior notes due 2008	$	(3,761	)	$	(3,798	)	$	(348,714	)	$	(356,965	)
5 7/8% senior notes due 2012	$	(6,235	)	$	(5,903	)	$	(6,255	)	$	(5,947	)
5 7/8% senior notes due 2016	$	(427,588	)	$	(497,054	)	$	(421,327	)	$	(506,590	)
6 7/8% senior notes due 2018	$	(449,579	)	$	(452,430	)	$	—		$	—
4 3/4 % senior convertible notes due 2021	$	—		$	—		$	(100,000	)	$	(201,225	)
7 1/5% senior notes due 2028	$	(249,918	)	$	(253,150	)	$	(249,917	)	$	(265,200	)

Cash and cash equivalents, accounts receivable, other current assets, accounts payable, interest payable and other current liabilities. The carrying amounts approximate fair value due to the short maturity of these instruments.

Commodity price swap and collar contracts, interest rate swaps and foreign currency swap contracts. The fair value of commodity price swap and collar contracts, interest rate swaps and foreign currency contracts are

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

estimated from quotes provided by the counterparties to these derivative contracts and represent the estimated amounts that the Company would expect to receive or pay to settle the derivative contracts. See Note J for a description of each of these derivatives, including whether the derivative contract qualifies for hedge accounting treatment or is considered a speculative derivative contract.

Financial assets. The carrying amounts of the trading securities approximate fair value due to the short maturity of these instruments. The fair value of the notes receivable approximates the carrying value at December 31, 2006 due to the proximity of the execution dates of the notes to December 31. The current portion of the notes receivable, amounting to $5.1 million and $.4 million as of December 31, 2006 and 2005, respectively, is included in other current assets, net in the Company’s Consolidated Balance Sheets. The trading securities and the noncurrent portions of the notes receivable are included in other assets, net in the Company’s Consolidated Balance Sheets.

Long-term debt. The carrying amount of borrowings outstanding under the Company’s corporate credit facility approximates fair value because these instruments bear interest at variable market rates. The fair values of each of the senior note issuances were determined based on quoted market prices for each of the issues. See Note F for additional information regarding the Company’s long-term debt.

NOTE F. Long-term Debt

Long-term debt, including the effects of net deferred fair value hedges losses and issuance discounts and premiums, consisted of the following components at December 31, 2006 and 2005 (See Note W for additional information):


	December 31,
	2006			2005
	(in thousands)
Outstanding debt principal balances:
Line of credit	$	328,000		$	900,000
8 1/4% senior notes due 2007		32,075			32,075
6 1/2% senior notes due 2008		3,777			350,000
5 7/8% senior notes due 2012		6,110			6,110
5 7/8% senior notes due 2016		526,875			526,875
6 7/8% senior notes due 2018		450,000			—
4 3/4% senior convertible notes due 2021		—			100,000
7 1/5% senior notes due 2028		250,000			250,000

		1,596,837			2,165,060
Issuance discounts and premiums, net		(96,284	)		(102,347	)
Net deferred fair value hedge losses		(3,391	)		(4,301	)

Total long-term debt	$	1,497,162		$	2,058,412

Lines of credit. The Company has an Amended and Restated 5-Year Revolving Credit Agreement (the “Credit Agreement”), which originally had a maturity date in September 2010 unless extended in accordance with the terms of the Credit Agreement. The terms of the Credit Agreement provide for initial aggregate loan commitments of $1.5 billion, which may be increased to a maximum aggregate amount of $1.8 billion if the lenders increase their loan commitments or if loan commitments of new financial institutions are added to the Credit Agreement. Effective September 29, 2006, participating lenders extended the maturity date on $1.395 billion of aggregate loan commitments under the Credit Agreement to September 2011.

Borrowings under the Credit Agreement may be in the form of revolving loans or swing line loans. Aggregate outstanding swing line loans may not exceed $100 million. Revolving loans bear interest, at the option of the Company, based on (a) a rate per annum equal to the higher of the prime rate announced from time to time by JPMorgan Chase Bank (8.25 percent per annum at December 31, 2006) or the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System during the last preceding business day (5.17 percent per annum at December 31, 2006) plus .5 percent or (b) a base Eurodollar rate, substantially equal to LIBOR (5.33 percent per annum at December 31, 2006), plus a margin (the “Applicable Margin”) that is

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

determined by reference to a grid based on the Company’s debt rating (.875 percent per annum at December 31, 2006). The Applicable Margin is increased by .10 percent to .125 percent per annum, depending on the Company’s debt ratings, if total borrowings under the Credit Agreement exceed 50 percent of the aggregate loan commitments. Swing line loans bear interest at a rate per annum equal to the “ASK” rate for Federal funds periodically published by the Dow Jones Market Service plus the Applicable Margin. The Company pays commitment fees on the undrawn amounts under the Credit Agreement that are determined by reference to a grid based on the Company’s debt rating (.175 percent per annum at December 31, 2006).

As of December 31, 2006, the Company had $153.8 million of undrawn letters of credit, of which $150.2 million were undrawn commitments under the Credit Agreement. The letters of credit outstanding under the Credit Agreement are subject to a per annum fee, based on a grid of the Company’s debt rating, representing the Company’s LIBOR margin (.875 percent at December 31, 2006) plus .125 percent. As of December 31, 2006, the Company had unused borrowing capacity of $1.0 billion under the Credit Agreement.

The Credit Agreement contains certain financial covenants, which include the (i) maintenance of a ratio of the Company’s earnings before gain or loss on the disposition of assets, interest expense, income taxes, depreciation, depletion and amortization expense, exploration and abandonments expense and other noncash charges and expenses to consolidated interest expense of at least 3.5 to 1.0; (ii) maintenance of a ratio of total debt to book capitalization less intangible assets, accumulated other comprehensive income and certain noncash asset impairments not to exceed .60 to 1.0; and (iii) maintenance of an annual ratio of the net present value of the Company’s oil and gas properties to total debt of at least 1.50 to 1.0 through March 2007 and 1.75 to 1.0 thereafter. The lenders may declare any outstanding obligations under the Credit Agreement immediately due and payable upon the occurrence, and during the continuance of, an event of default, which includes a defined change in control of the Company. As of December 31, 2006, the Company was in compliance with all of its debt covenants.

Senior notes. During May 2006, the Company issued $450 million of 6.875% notes and received proceeds, net of issuance discount and underwriting cost, of $447.4 million.

The Company’s senior notes are general unsecured obligations ranking equally in right of payment with all other senior unsecured indebtedness of the Company and are senior in right of payment to all existing and future subordinated indebtedness of the Company. The Company is a holding company that conducts all of its operations through subsidiaries; consequently, the senior notes are structurally subordinated to all obligations of its subsidiaries. Interest on the Company’s senior notes is payable semiannually.

Senior convertible notes. During 2006, holders of all of the $100 million of 4 3/4% Senior Convertible Notes exercised their conversion rights. Associated therewith, the Company paid $79.9 million in cash, issued 2.3 million shares of common stock and recorded a $22 million increase to stockholders’ equity.

Early extinguishment of debt. During 2006, the Company repurchased $346.2 million of its outstanding $350 million of 6.50% senior notes due 2008 (the “6.50% Notes”). The Company recognized a charge of $8.1 million in the second quarter of 2006 associated with the early extinguishment of the 6.50% Notes, which is included in other expense in the accompanying Consolidated Statements of Operations. During 2005, the Company (i) redeemed the remaining principal amounts of its outstanding 9 5/8% senior notes due 2010 and its 7.50% senior notes due 2012 of $64.0 million and $16.2 million, respectively, and (ii) accepted tenders to purchase for cash $188.4 million in principal amount of its 5 7/8% senior notes due 2012. Consequently, the Company recognized a charge for the early extinguishment of debt of $26.5 million included in other expense in the accompanying Consolidated Statements of Operations on these redemptions and tenders for 2005.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

Principal maturities. Principal maturities of long-term debt at December 31, 2006 are as follows (in thousands):


2007	$	32,075
2008	$	3,777
2009	$	—
2010	$	22,960
2011	$	305,040
Thereafter	$	1,232,985

Interest expenses. The following amounts have been incurred and charged to interest expense for the years ended December 31, 2006, 2005 and 2004:


	Year Ended December 31,
	2006			2005			2004
	(in thousands)
Cash payments for interest	$	114,745		$	129,769		$	109,940
Accretion/amortization of discounts or premiums on loans		7,133			6,186			3,683
Accretion of discount on derivative obligations		2,529			—			—
Amortization of net deferred hedge (gains) losses (see Note J)		14			(4,052	)		(19,220	)
Amortization of capitalized loan fees		1,366			2,265			2,059
Kansas ad valorem tax		—			—			65
Net changes in accruals		(6,571	)		(7,092	)		7,476

Interest incurred		119,216			127,076			104,003
Less capitalized interest		(12,166	)		(1,089	)		(2,016	)

Total interest expense	$	107,050		$	125,987		$	101,987

NOTE G. Related Party Transactions

The Company, through a wholly-owned subsidiary, serves as operator of properties in which it and its affiliated partnerships have an interest. Accordingly, the Company receives producing well overhead, drilling well overhead and other fees related to the operation of the properties. The affiliated partnerships also reimburse the Company for their allocated share of general and administrative charges. Reimbursements of fees are recorded as reductions to general and administrative expenses in the Company’s Consolidated Statements of Operations.

The activities with affiliated partnerships are summarized for the following related party transactions for the years ended December 31, 2006, 2005 and 2004:


	Year Ended December 31,
	2006		2005		2004
	(in thousands)
Receipt of lease operating and supervision charges in accordance with standard industry operating agreements	$	1,551	$	1,493	$	1,458
Reimbursement of general and administrative expenses	$	348	$	348	$	193

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

NOTE H. Incentive Plans

Retirement Plans

Deferred compensation retirement plan. In August 1997, the Compensation Committee of the Board of Directors (the “Board”) approved a deferred compensation retirement plan for the officers and certain key employees of the Company. Each officer and key employee is allowed to contribute up to 25 percent of their base salary and 100 percent of their annual bonus. The Company will provide a matching contribution of 100 percent of the officer’s and key employee’s contribution limited to the first 10 percent of the officer’s base salary and eight percent of the key employee’s base salary. The Company’s matching contribution vests immediately. A trust fund has been established by the Company to accumulate the contributions made under this retirement plan. The Company’s matching contributions were $1.3 million, $1.2 million and $.9 million for the years ended December 31, 2006, 2005 and 2004, respectively.

401(k) plan. The Pioneer Natural Resources USA, Inc. (“Pioneer USA”) 401(k) and Matching Plan (the “401(k) Plan”) is a defined contribution plan established under the Internal Revenue Code Section 401. All regular full-time and part-time employees of Pioneer USA are eligible to participate in the 401(k) Plan on the first day of the month following their date of hire. Participants may contribute an amount of not less than two percent nor more than 30 percent of their annual salary into the 401(k) Plan. Matching contributions are made to the 401(k) Plan in cash by Pioneer USA in amounts equal to 200 percent of a participant’s contributions to the 401(k) Plan that are not in excess of five percent of the participant’s base compensation (the “Matching Contribution”). Each participant’s account is credited with the participant’s contributions, Matching Contributions and allocations of the 401(k) Plan’s earnings. Participants are fully vested in their account balances except for Matching Contributions and their proportionate share of 401(k) Plan earnings attributable to Matching Contributions, which proportionately vest over a four-year period that begins with the participant’s date of hire. During the years ended December 31, 2006, 2005 and 2004, the Company recognized compensation expense of $9.3 million, $8.0 million and $5.4 million, respectively, as a result of Matching Contributions.

Long-Term Incentive Plan

In May 2006, the Company’s stockholders approved a new Long-Term Incentive Plan, which provides for the granting of incentive awards in the form of stock options, stock appreciation rights, performance units and restricted stock to directors, officers and employees of the Company. The Long-Term Incentive Plan provides for the issuance of 4.6 million awards.

The following table shows the number of awards available under the Company’s Long-Term Incentive Plan at December 31, 2006:


Approved and authorized awards	4,600,000
Awards issued after May 3, 2006	(74,549	)


Awards available for future grant	4,525,451

For the 2006-2007 director year, the Company’s non-employee directors were offered a choice to receive their annual fee retainers (i) 100 percent in restricted stock units, (ii) 100 percent in cash or (iii) a combination of 50/50 of cash and restricted stock units. All non-employee directors also received an annual equity grant of restricted stock units.

Stock option awards. In accordance with the Evergreen merger agreement, on September 28, 2004, the Company assumed fully-vested options to purchase 2,384,657 shares of the Company’s common stock at various exercise prices, the weighted average price per share of which was $11.18. The assumed options were outstanding awards to Evergreen employees when the Evergreen merger occurred.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

During 2004, the Company’s stock-based compensation philosophy shifted its emphasis from the awarding of stock options to restricted stock awards. There were no options granted after 2003.

Restricted stock awards. During 2006, 2005 and 2004 the Company issued 736,642, 1,411,269 and 630,937, respectively, restricted shares of the Company’s common stock as compensation to directors, officers and employees of the Company.

During 2004, the Company assumed 214,186 restricted stock units in exchange for Evergreen restricted stock units outstanding on September 28, 2004. The Company recorded $6.0 million of deferred compensation for future expected service associated with certain of the restricted stock units assumed from Evergreen. The deferred compensation was amortized as charges to compensation expense over the periods in which the restrictions on the units lapsed.

Compensation costs. On January 1, 2006, the Company adopted SFAS 123(R), as more fully described in Note B, and eliminated $45.8 million of deferred compensation in stockholders’ equity and reduced a like amount of additional paid-in capital in the Consolidated Balance Sheets. Prior to adoption of SFAS 123(R), the Company recorded $56.2 million and $19.1 million of deferred compensation associated with restricted stock awards in stockholders’ equity during 2005 and 2004, respectively. Such amounts will be amortized to compensation expense over the vesting periods of the awards.

Adoption of SFAS 123(R), required the Company to prospectively (i) recognize the value of the unvested stock options, which was approximately $959 thousand and (ii) recognize compensation expense associated with the Company’s ESPP. The Company’s recognition of compensation of restricted stock did not change upon adoption of SFAS 123(R).

During 2006, 2005 and 2004, the Company recognized compensation costs associated with stock-based compensation of $32.1 million, $26.9 million and $12.5 million, respectively. At December 31, 2006, the Company has unrecognized unvested stock-based compensation costs of approximately $39.8 million, which will amortize to earnings over the next three years.

The following table reflects the outstanding restricted stock awards as of December 31, 2006, 2005 and 2004 and activity related thereto for the years then ended:


	Year Ended December 31,
	2006					2005					2004
				Weighted					Weighted					Weighted
	Number			Average		Number			Average		Number			Average
	Of Shares			Price		Of Shares			Price		Of Shares			Price
Restricted stock awards:
Outstanding at beginning of year		1,966,223		$	36.90		1,447,987		$	28.46		676,973		$	24.79
Evergreen awards assumed		—		$	—		—		$	—		214,186		$	32.58
Shares granted		736,642		$	43.44		1,411,269		$	39.79		630,937		$	31.29
Shares forfeited		(190,538	)	$	39.32		(174,046	)	$	33.99		(32,174	)	$	30.99
Lapse of restrictions		(385,780	)	$	34.84		(718,987	)	$	26.26		(41,935	)	$	31.09

Outstanding at end of year		2,126,547		$	39.32		1,966,223		$	36.90		1,447,987		$	28.46

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

A summary of the Company’s stock option plans as of December 31, 2006, 2005 and 2004, and changes during the years then ended, are presented below:


	Year Ended December 31,
	2006					2005					2004
				Weighted					Weighted					Weighted
	Number			Average		Number			Average		Number			Average
	Of Shares			Price		Of Shares			Price		Of Shares			Price
Non-statutory stock options (a):
Outstanding at beginning of year		2,685,398		$	20.32		5,180,584		$	18.60		5,274,116		$	20.13
Evergreen options assumed		—		$	—		—		$	—		2,384,657		$	11.18
Options forfeited		(267,851	)	$	22.60		(65,190	)	$	22.94		(102,890	)	$	22.24
Options exercised		(816,052	)	$	19.22		(2,429,996	)	$	15.95		(2,375,299	)	$	14.39

Outstanding at end of year		1,601,495		$	20.50		2,685,398		$	20.32		5,180,584		$	18.60

Exercisable at end of year		1,601,495		$	20.50		2,382,714		$	19.74		3,970,996		$	17.08


(a)		The Company did not grant any stock options during 2006, 2005 or 2004.

The following table summarizes information about the Company’s stock options outstanding and exercisable at December 31, 2006:


	Options Outstanding and Exercisable
	Number		Weighted	Weighted		Intrinsic
	Outstanding at		Average	Average		Value at
Range of	December 31,		Remaining	Exercise		December 31,
Exercise Price	2006		Contractual Life	Price		2006
						(in thousands)
$5-$11		139,402	2.0 years	$	9.90		$ 4,153
$12-$18		691,611	2.1 years	$	17.50		15,347
$19-$26		755,483	3.2 years	$	24.81		11,242
$31-$43		14,999	0.1 years	$	40.31		—

		1,601,495					$30,742

Employee Stock Purchase Plan

The Company has an ESPP that allows eligible employees to annually purchase the Company’s common stock at a discounted price. Officers of the Company are not eligible to participate in the ESPP. Contributions to the ESPP are limited to 15 percent of an employee’s pay (subject to certain ESPP limits) during the eight-month offering period. Participants in the ESPP purchase the Company’s common stock at a price that is 15 percent below the closing sales price of the Company’s common stock on either the first day or the last day of each offering period, whichever closing sales price is lower.

Postretirement Benefit Obligations

As of December 31, 2006 and 2005, the Company had recorded $19.8 million and $18.6 million, respectively, of unfunded accumulated postretirement benefit obligations, the current and noncurrent portions of which are included in other current liabilities and other liabilities and minority interests, respectively, in the accompanying Consolidated Balance Sheets. These obligations are comprised of five plans of which four relate to predecessor entities that the Company acquired in prior years. These plans had no assets as of December 31, 2006 or 2005. Other than the Company’s retirement plan, the participants of these plans are not current employees of the Company.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

As of December 31, 2006, the accumulated postretirement benefit obligations pertaining to these plans were determined by independent actuaries for four plans representing $15.7 million of unfunded accumulated postretirement benefit obligations and by the Company for one plan representing $4.1 million of unfunded accumulated postretirement benefit obligations. Interest costs at an annual rate of 5.95 percent of the periodic undiscounted accumulated postretirement benefit obligations were employed in the valuations of the benefit obligations. Certain of the aforementioned plans provide for medical and dental cost subsidies for plan participants. Annual medical cost escalation trends of 10 percent in 2007, declining to five percent in 2012 and thereafter, and annual dental cost escalation trends of seven percent in 2007, declining to five percent in 2011 and thereafter, were employed to estimate the accumulated postretirement benefit obligations associated with the medical and dental cost subsidies.

The following table reconciles changes in the Company’s unfunded accumulated postretirement benefit obligations during the years ended December 31, 2006, 2005 and 2004:


	Year Ended December 31,
	2006			2005			2004
	(in thousands)
Beginning accumulated postretirement benefit obligations	$	18,576		$	15,534		$	15,556
Net benefit payments		(1,234	)		(1,393	)		(1,497	)
Service costs		816			324			258
Net actuarial losses (gains)		642			3,211			(32	)
Accretion of interest		1,037			900			909
Fair value of Evergreen obligations assumed		—			—			340

Ending accumulated postretirement benefit obligations	$	19,837		$	18,576		$	15,534

Estimated benefit payments and service/interest costs associated with the plans for the year ending December 31, 2007 are $1.5 million and $2.2 million, respectively.

As discussed above in Note B, the Company has adopted the provisions of SFAS 158 effective on December 31, 2006. The Company previously recognized the funded status of its defined benefit postretirement plans and currently recognizes periodic changes in its defined benefit postretirement plans as components of service costs in the period of change as allowed by SFAS 158. Consequently, the adoption of SFAS 158 did not have a material impact on the Company’s liquidity, financial position or future results of operations for the year ended December 31, 2006.

NOTE I. Commitments and Contingencies

Severance agreements. The Company has entered into severance and change in control agreements with its officers, subsidiary company officers and certain key employees. The current annual salaries for the parent company officers, the subsidiary company officers and key employees covered under such agreements total $35.4 million.

Indemnifications. The Company has indemnified its directors and certain of its officers, employees and agents with respect to claims and damages arising from acts or omissions taken in such capacity, as well as with respect to certain litigation.

Legal actions. The Company is party to the legal actions that are described below. The Company is also party to other proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to such other proceedings and claims will not have a material adverse effect on the Company’s consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. The Company will continue to evaluate its litigation matters on a quarter-by-quarter basis and will adjust its litigation reserves as appropriate to reflect its assessment of the then current status of litigation. See Note W for additional information.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

Alford. The Company is party to a 1993 class action lawsuit filed in the 26th Judicial District Court of Stevens County, Kansas by two classes of royalty owners, one for each of the Company’s gathering systems connected to the Company’s Satanta gas plant. The plaintiffs in the case assert that they were improperly charged expenses (primarily field compression), which plaintiffs allege are a “cost of production,” and for which the plaintiffs claim they, as royalty owners, are not responsible. Plaintiffs also claim that they are entitled to 50 percent of the value of the helium extracted at the Company’s Satanta gas plant.

During the third quarter of 2006, the Company reached an agreement to settle the claims made in the lawsuit. Under the terms of the agreement, the Company agreed to make cash payments to settle the plaintiffs’ claims with respect to production occurring on and before December 31, 2005. The Company’s portion of the cash payments is expected to be $32.7 million, of which approximately $17.0 million was paid during the third quarter of 2006 and the remaining approximately $15.7 million will be paid in the third quarter of 2007. The Company also agreed to adjust the manner in which royalty payments to the class members will be calculated for production occurring on and after January 1, 2006, which change is not expected to have a material effect on the Company’s liquidity, financial position or future results of operations.

Final approval was received from the Court on February 9, 2007, and the settlement is expected to be final within 60 days of final approval assuming no appeals are filed. If no appeals are made or if any appeals made are resolved, it is expected that the settlement will be final in the second quarter of 2007.

MOSH Holding. On April 11, 2005, the Company and its principal United States subsidiary, Pioneer Natural Resources USA, Inc., were named as defendants in MOSH Holding, L.P. v Pioneer Natural Resources Company; Pioneer Natural Resources USA, Inc.; Woodside Energy (USA) Inc.; and JPMorgan Chase Bank, NA, as Trustee of the Mesa Offshore Trust, which is before the Judicial District Court of Harris County, Texas (334^th Judicial District). On December 8, 2006, Dagger-Spine Hedgehog Corporation (“Dagger-Spine”) filed a Petition In Intervention in the lawsuit to assert the same claims as MOSH Holding, L.P. (“MHLP”). MHLP and Dagger-Spine (collectively, “Plaintiffs”) are unitholders in the Trust, which was created in 1982 as the sole limited partner in a partnership that holds an overriding royalty interest in certain oil and gas leases offshore Louisiana and Texas. The Company owns the managing general partner interest in the partnership. Plaintiffs allege that the Company, together with Woodside Energy (USA) Inc. (“Woodside”), concealed the value of the royalty interest and worked to terminate the Mesa Offshore Trust prematurely and to capture for itself and Woodside profits that belong to the Mesa Offshore Trust (“MOT”). Plaintiffs also allege breaches of fiduciary duty, misapplication of trust property, common law fraud, gross negligence, and breach of the conveyance agreement for the overriding royalty interest. The relief sought by the plaintiffs includes monetary and punitive damages and certain equitable relief, including an accounting of expenses, a setting aside of certain farmouts, and a temporary and permanent injunction.

The Trustee and the Company have reached a conditional settlement of all claims in the lawsuit that MOT has or might have against the Company. Plaintiffs are not signatories to the settlement and they, or other unitholders of MOT, may comment on or object to the settlement. The settlement is subject to certain conditions and is not final until approved by the court and any appeals are resolved. The court has set the settlement review hearing for May 21, 2007.

Dorchester Refining Company Site. A subsidiary of the Company has been notified by a letter from the Texas Commission on Environmental Quality (“TCEQ”) dated August 24, 2005 that the TCEQ considers the subsidiary to be a potentially responsible party with respect to the Dorchester Refining Company State Superfund Site located in Mount Pleasant, Texas. In connection with the acquisition of oil and gas assets in 1991, the Company acquired a group of companies, one of which was an entity that had owned a refinery located at the Mount Pleasant site from 1977 until 1984. According to the TCEQ, this refinery was responsible for releases of hazardous substances into the environment. Pursuant to applicable Texas law, the Company’s subsidiary, which does not own any material assets or conduct any material operations, may be subject to strict, joint and several liability for the costs of conducting a study to evaluate potential remedial options and for the costs of performing any remediation ultimately required by the TCEQ. The Company does not know the nature and extent of the alleged contamination, the potential costs of remediation or the portion, if any, of such costs that may be allocable to the Company’s subsidiary; however, the Company has noted that there appear to be other operators or owners who may share responsibility for these costs and does not expect that any such additional liability will have a material adverse effect on its consolidated financial position as a whole or on its liquidity, financial position or future annual results of operations.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

Environmental Protection Agency Investigation. On November 4, 2005, the Company learned from the U.S. Environmental Protection Agency that the agency was conducting a criminal investigation into a 2003 spill that occurred at a Company-operated drilling rig located on an ice island offshore Harrison Bay, Alaska. The investigation is being conducted in conjunction with the U.S. Attorney’s Office for the District of Alaska. The spill was previously investigated by the Alaska Department of Environmental Conservation (“ADEC”) and, following completion of a clean up, the ADEC issued a letter stating its determination that, at that time, the site did not pose a threat to human health, safety or welfare, or the environment. The Company is fully cooperating with the government’s investigation.

Argentine obligations. The Company has provided the purchaser of its Argentine assets certain indemnifications and remains responsible for certain contingent liabilities, subject to defined limitations. The Company does not currently believe that these obligations, which primarily pertain to matters of litigation, environmental contingencies, royalty obligations and income taxes, are probable of having a material impact on its liquidity, financial position or future results of operations.

Lease agreements. The Company leases offshore production facilities, drilling rigs, equipment and office facilities under noncancellable operating leases. Rental expenses associated with these operating leases for the years ended December 31, 2006, 2005 and 2004 were approximately $46.8 million, $64.5 million and $51.8 million, respectively, which includes $9.8 million, $27.1 million and $16.2 million, respectively, associated with discontinued operations. Future minimum lease commitments under noncancellable operating leases at December 31, 2006 are as follows (in thousands):


2007	$	29,065
2008	$	14,560
2009	$	13,346
2010	$	6,720
2011	$	709
Thereafter	$	—

Drilling commitments. The Company periodically enters into contractual arrangements under which the Company is committed to expend funds to drill wells in the future. The Company also enters into agreements to secure drilling rig services, which require the Company to make future minimum payments to the rig operators. The Company records drilling commitments in the periods in which well capital is expended or rig services are provided.

Transportation agreements. Associated with the Evergreen merger, the Company assumed gas transportation commitments for specified volumes of gas per year through 2014. During 2006, the Company expanded these commitments to support production increases, primarily in the Raton gas field. The transportation commitments averaged approximately 190 million cubic feet (“MMcf”) of gross gas sales volumes per day during 2006, including associated fuel commitments. These commitments will average approximately 201 MMcf of gross gas volumes per day during 2007, decrease to approximately 198 MMcf of gross gas volumes per day during 2008, and decline thereafter to approximately 69 MMcf of gross gas volumes per day during 2013, before terminating in January 2014.

The Company’s Canadian subsidiaries are parties to pipeline transportation service agreements, with aggregate remaining terms of approximately 10 years, whereby they have committed to transport specified volumes of gas each year principally from Canada to a point in Chicago, Illinois. Such gas volumes totaled approximately 86 MMcf of gas per day during 2006 and 78 MMcf of gas per day during 2005 and 2004, and are comprised of a significant portion of the Company’s Canadian net gas production, augmented with certain volumes purchased at market prices in Canada. The committed volumes to be transported under the pipeline transportation service agreements are approximately 85 MMcf of gas per day during 2007 and decline to approximately 75 MMcf of gas per day by the end of the commitment term. The net gas marketing gains or losses resulting from purchasing third party gas in Canada and selling it in Chicago are recorded as other income or other expense in the accompanying

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

Consolidated Statements of Operations. Associated with these agreements, the Company recognized $2.0 and $4.1 million of pretax gas marketing gains in income from discontinued operations, net of tax during the years ended December 31, 2006 and 2005, respectively, and $1.2 million of pretax gas marketing losses in income from discontinued operations, net of tax during the year ended December 31, 2004.

Future minimum transportation fees under the Company’s gas transportation commitments at December 31, 2006 are as follows (in thousands):


2007	$	68,630
2008	$	68,938
2009	$	68,458
2010	$	66,749
2011	$	64,243
Thereafter	$	170,546

NOTE J. Derivative Financial Instruments

The Company uses financial derivative contracts to manage exposures to commodity price, interest rate and foreign currency fluctuations. The Company generally does not enter into derivative financial instruments for speculative or trading purposes. The Company also may enter physical delivery contracts to effectively provide commodity price hedges. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. Therefore, these contracts are not recorded in the financial statements.

All derivatives are recorded on the balance sheet at estimated fair value. Fair value is generally determined based on the difference between the fixed contract price and the underlying market price at the determination date, and/or the value confirmed by the counterparty. Changes in the fair value of effective cash flow hedges are recorded as a component of accumulated other comprehensive income (loss), which is later transferred to earnings when the hedged transaction occurs. Changes in the fair value of derivatives that are not designated as hedges, as well as the ineffective portion of the hedge derivatives, are recorded in earnings. The ineffective portion is calculated as the difference between the change in fair value of the derivative and the estimated change in cash flows from the item hedged.

Fair value hedges. The Company monitors the debt capital markets and interest rate trends to identify opportunities to enter into and terminate interest rate swap contracts with the objective of reducing costs of capital. As of December 31, 2006 and 2005, the Company was not a party to any open fair value hedges.

As of December 31, 2006, the carrying value of the Company’s long-term debt in the accompanying Consolidated Balance Sheets included a $3.4 million reduction in the carrying value attributable to net deferred hedge losses on terminated fair value hedges that are being amortized as net increases to interest expense over the original terms of the terminated agreements. The amortization of net deferred hedge losses on terminated interest rate swaps increased the Company’s reported interest expense by $14 thousand during the year ended December 31, 2006, as compared to deferred gains amortization, which reduced the Company’s reported interest expense by $4.1 million and $19.2 million during the years ended December 31, 2005 and 2004, respectively.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

The following table sets forth, as of December 31, 2006, the scheduled amortization of net deferred hedge losses on terminated interest rate hedges (including terminated fair value and cash flow hedges) that will be recognized as increases to the Company’s future interest expense:


	Net Deferred Interest Rate Hedge Losses
	Fair Value		Cash Flow		Total
	(in thousands)
2007	$	231	$	94	$	325
2008	$	257	$	114	$	371
2009	$	281	$	135	$	416
2010	$	307	$	159	$	466
2011	$	337	$	184	$	521
Thereafter	$	1,978	$	1,032	$	3,010

Cash flow hedges. The Company utilizes commodity swap and collar contracts to (i) reduce the effect of price volatility on the commodities the Company produces and sells, (ii) support the Company’s annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. As of December 31, 2006, all of the Company’s open commodity hedges are designated as hedges of Canadian and United States forecasted sales. The Company also, from time to time, utilizes interest rate contracts to reduce the effect of interest rate volatility on the Company’s indebtedness and forward currency exchange agreements to reduce the effect of U.S. dollar to Canadian dollar exchange rate volatility.

Oil prices. All material physical sales contracts governing the Company’s oil production have been tied directly or indirectly to the New York Mercantile Exchange (“NYMEX”) prices. As of December 31, 2006, all of the Company’s oil hedges were designated as hedges of United States forecasted sales. The following table sets forth the volumes hedged in barrels (“Bbl”) underlying the Company’s outstanding oil hedge contracts and the weighted average NYMEX prices per Bbl for those contracts as of December 31, 2006:


	First		Second		Third		Fourth		Outstanding
	Quarter		Quarter		Quarter		Quarter		Average
Average daily oil production hedged:
2007 — Swap Contracts Volume (Bbl)		3,689		4,341		5,000		5,000		4,512
Price per Bbl	$	31.63	$	31.47	$	31.35	$	31.35	$	31.44
2008 — Swap Contracts Volume (Bbl)		6,500		6,500		6,500		6,500		6,500
Price per Bbl	$	31.19	$	31.19	$	31.19	$	31.19	$	31.19

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

The Company reports average oil prices per Bbl including the effects of oil quality adjustments, amortization of deferred volumetric production payment (“VPP”) revenue and the net effect of oil hedges. The following table sets forth (i) the Company’s oil prices from continuing operations, both reported (including hedge results and amortization of deferred VPP revenue) and realized (excluding hedge results and amortization of deferred VPP revenue), (ii) amortization of deferred VPP revenue to oil revenue from continuing operations and (iii) the net effect of settlements of oil price hedges on oil revenue from continuing operations for the years ended December 31, 2006, 2005 and 2004:


	Year Ended December 31,
	2006		2005		2004
Average price reported per Bbl	$	65.51	$	38.61	$	32.52
Average price realized per Bbl	$	63.42	$	53.72	$	39.04
VPP increase to oil revenue (in millions)	$	116.1	$	—	$	—
Reduction to oil revenue from hedging activity (in millions) (a)	$	97.6	$	176.6	$	80.0


(a)		Excludes hedge losses of $12.3 million, $52.0 million and $27.2 million attributable to discontinued operations for the years ended December 31, 2006, 2005 and 2004, respectively.

Natural gas liquids prices. During the years ended December 31, 2006, 2005 and 2004, the Company did not enter into any NGL hedge contracts. There were no outstanding NGL hedge contracts at December 31, 2006.

Gas prices. The Company employs a policy of hedging a portion of its gas production based on the index price upon which the gas is actually sold in order to mitigate the basis risk between NYMEX prices and actual index prices, or based on NYMEX prices, if NYMEX prices are highly correlated with the index price. As of December 31, 2006, all of the Company’s gas hedges were designated as hedges of United States and Canadian forecasted sales. The following table sets forth the volumes hedged in million British thermal units (“MMBtu”) under outstanding gas hedge contracts and the weighted average index prices per MMBtu for those contracts as of December 31, 2006:


	First		Second		Third		Fourth		Outstanding
	Quarter		Quarter		Quarter		Quarter		Average
Average daily gas production hedged:
2007 — Swap Contracts Volume (MMBtu)		89,841		85,000		85,000		85,000		86,194
Price per MMBtu	$	7.97	$	8.18	$	8.18	$	8.18	$	8.13
2007 — Collar Contracts Volume (MMBtu)		25,000		—		—		—		6,164
Price per MMBtu	$	9.00-$11.52	$	—	$	—	$	—	$	9.00-$11.52
2008 — Swap Contracts Volume (MMBtu)		15,000		15,000		15,000		15,000		15,000
Price per MMBtu	$	8.62	$	8.62	$	8.62	$	8.62	$	8.62

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

The Company reports average gas prices per Mcf including the effects of Btu content, gas processing, shrinkage adjustments, amortization of deferred VPP revenue and the net effect of gas hedges. The following table sets forth (i) the Company’s gas prices from continuing operations, both reported (including hedge results and amortization of deferred VPP revenue) and realized (excluding hedge results and amortization of deferred VPP revenue), (ii) amortization of deferred VPP revenue to gas revenue from continuing operations and (iii) the net effect of settlements of gas price hedges on gas revenue from continuing operations for the years ended December 31, 2006, 2005 and 2004:


	Year Ended December 31,
	2006		2005		2004
Average price reported per Mcf	$	6.15	$	6.94	$	4.99
Average price realized per Mcf	$	5.96	$	7.26	$	5.46
VPP increase to gas revenue (in millions)	$	74.2	$	75.8	$	—
Reduction to gas revenue from hedging activity (in millions) (a)	$	53.6	$	108.2	$	35.7


(a)		Excludes hedge losses of $1.2 million, $94.7 million and $90.0 million attributable to discontinued operations for the year ended December 31, 2006, 2005 and 2004, respectively.

Interest rate. During April 2006, the Company entered into costless collar contracts and designated the contracts as cash flow hedges of the forecasted interest rate risk associated with the coupon rate on the Company’s 6.875% Notes, which were issued on May 1, 2006. The Company terminated these costless collar contracts for a gain of $1.3 million, which was recorded in AOCI - Hedging. The Company did not realize any ineffectiveness in connection with the costless collar contracts during 2006. See Note F for information regarding the 6.875% Notes.

Hedge ineffectiveness. The Company recognized ineffectiveness amounts related to (i) hedged volumes that exceeded revised forecasts of production volumes due to delays in the start up of production in certain fields and (ii) reduced correlations between the indexes of the financial hedge derivatives and the indexes of the hedged forecasted production for certain fields. Ineffectiveness can be associated with closed contracts (i.e. realized) or can be associated with open positions (i.e. unrealized). The following table sets forth the hedge ineffectiveness attributable to continuing operations recognized in the Consolidated Statements of Operations for the years ended December 31, 2006, 2005 and 2004:


	Year Ended December 31,
	2006		2005			2004
	(in millions)
Interest and other income	$	7.4	$	—		$	—
Other expense		10.6		(29.8	)		(4.2	)

Total ineffectiveness (a)	$	18.0	$	(29.8	)	$	(4.2	)


(a)		Hedge ineffectiveness income (loss) attributable to discontinued operations was $7.4 million, $(22.6) million and $(171) thousand during 2006, 2005 and 2004, respectively.

AOCI — Hedging. As of December 31, 2006 and 2005, AOCI — Hedging represented net deferred losses of $167.2 and $506.6 million, respectively. The AOCI — Hedging balance as of December 31, 2006 was comprised of $71.0 million of net deferred losses on the effective portions of open cash flow hedges, $193.7 million of net deferred losses on terminated cash flow hedges (including $1.7 million of net deferred losses on terminated cash flow interest rate hedges) and $97.5 million of associated net deferred tax benefits. The AOCI — Hedging balance as of December 31, 2005 was comprised of $767.8 million of net deferred losses on the effective portions of open cash flow hedges, $30.0 million of net deferred losses on terminated cash flow hedges (including $3.2 million of net deferred losses on terminated cash flow interest rate hedges) and $291.2 million of associated net deferred tax benefits. The decrease in AOCI — Hedging during the year ended December 31, 2006 was primarily attributable to

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

the reclassification of net deferred hedge losses to net income as derivatives matured and, to a lesser extent, decreases in future commodity prices relative to the commodity prices stipulated in the hedge contracts. The net deferred losses associated with open cash flow hedges remain subject to market price fluctuations until the positions are either settled under the terms of the hedge contracts or terminated prior to settlement. The net deferred losses on terminated cash flow hedges are fixed.

During the year ending December 31, 2007, based on current estimates of future commodity prices, the Company expects to reclassify $5.3 million of net deferred gains associated with open commodity hedges and $106.3 million of net deferred losses on terminated commodity hedges from AOCI - Hedging to oil and gas revenues. The Company also expects to reclassify approximately $38.7 million of net deferred income tax benefits associated with commodity hedges during the year ending December 31, 2007 from AOCI — Hedging to income tax benefit.

Terminated commodity hedges. At times, the Company terminates open commodity hedge positions when the underlying commodity prices reach a point that the Company believes will be the high or low price of the commodity prior to the scheduled settlement of the open commodity position. This allows the Company to maximize gains or minimize losses associated with the open hedge positions. At the time of termination of the hedges, the amounts recorded in AOCI — Hedging are maintained and amortized to earnings over the periods the production was scheduled to occur.

The following table sets forth, as of December 31, 2006, the scheduled amortization of net deferred losses on terminated commodity hedges that will be recognized as decreases to the Company’s future oil and gas revenues:


	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter		Total
	(in thousands)
2007 net deferred hedge losses	$	29,619	$	27,609	$	25,153	$	23,905	$	106,286
2008 net deferred hedge losses	$	20,285	$	17,541	$	17,402	$	17,718		72,946
2009 net deferred hedge losses	$	2,330	$	232	$	230	$	822		3,614
2010 net deferred hedge losses	$	667	$	620	$	578	$	539		2,404
2011 net deferred hedge losses	$	873	$	889	$	902	$	907		3,571
2012 net deferred hedge losses	$	810	$	791	$	783	$	773		3,157

									$	191,978

Non-hedge derivatives. During January and April 2005, the Company entered into non-hedge interest rate swaps. The Company terminated the interest rate swaps during January and April 2005 for an aggregate net loss of $1.5 million, which amount is included in other expense in the Company’s accompanying Consolidated Statement of Operations for 2005.

NOTE K. Major Customers and Derivative Counterparties

Sales to major customers. The Company’s share of oil and gas production is sold to various purchasers who must be prequalified under the Company’s credit risk policies and procedures. The Company records allowances for doubtful accounts based on the agings of accounts receivable and the general economic condition of its customers and, depending on facts and circumstances, may require customers to provide collateral or otherwise secure their accounts. The Company is of the opinion that the loss of any one purchaser would not have an adverse effect on the ability of the Company to sell its oil and gas production.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

The following United States customers individually accounted for ten percent or more of the consolidated oil, NGL and gas revenues, including the revenues from discontinued operations and the results of commodity hedges, in at least one of the years, during the years ended December 31, 2006, 2005 and 2004:


	Year Ended December 31,
	2006			2005			2004
Oneok Resources		12	%		6	%		3	%
Plains Marketing LP		12	%		7	%		4	%
Occidental Energy Marketing, Inc.		11	%		9	%		6	%
Williams Power Company, Inc.		4	%		9	%		14	%

Derivative counterparties. The Company uses credit and other financial criteria to evaluate the credit standing of, and to select, counterparties to its derivative instruments. Although the Company does not obtain collateral or otherwise secure the fair value of its derivative instruments, associated credit risk is mitigated by the Company’s credit risk policies and procedures. As of December 31, 2006, the Company had no derivative counterparties with significant credit risks.

NOTE L. Asset Retirement Obligations

The Company’s asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. The Company does not provide for a market risk premium associated with asset retirement obligations because a reliable estimate cannot be determined. The Company has no assets that are legally restricted for purposes of settling asset retirement obligations. The following table summarizes the Company’s asset retirement obligation transactions during the years ended December 31, 2006, 2005 and 2004:


	Year Ended December 31,
	2006			2005			2004
	(in thousands)
Beginning asset retirement obligations	$	157,035		$	120,879		$	105,036
New wells placed on production and changes in estimates (a)		122,685			57,405			4,591
Liabilities assumed in acquisitions		981			3,183			10,488
Disposition of wells		(44,042	)		(23,101	)		—
Liabilities settled		(16,219	)		(9,508	)		(8,562	)
Accretion of discount on continuing operations		3,726			3,349			3,557
Accretion of discount on discontinued operations		1,904			4,527			4,653
Currency translation		(157	)		301			1,116

Ending asset retirement obligations	$	225,913		$	157,035		$	120,879


(a)		Includes, for the years ended December 31, 2006 and 2005, respectively, a $75.0 million and a $39.8 million increase in the abandonment estimate of the East Cameron facilities that were destroyed by Hurricane Rita, which is reflected in hurricane activity, net in the Consolidated Statements of Operations.

The Company records the current and noncurrent portions of asset retirement obligations in other current liabilities and other liabilities and minority interests, respectively, in the accompanying Consolidated Balance Sheets.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

NOTE M. Interest and Other Income

The following table provides the components of the Company’s interest and other income during the years ended December 31, 2006, 2005 and 2004:


	Year Ended December 31,
	2006		2005		2004
	(in thousands)
Business interruption insurance claim (see Note U)	$	7,647	$	14,200	$	—
Minority interest in subsidiary net loss (see Note B)		4,892		5,206		—
Interest income		14,369		1,510		328
Sales and other tax refunds		645		1,792		—
Credit card rebate		837		835		—
Seismic data sales		413		467		53
Deferred compensation plan income		879		500		202
Foreign currency remeasurement and exchange gains (a)		361		236		98
Derivative ineffectiveness (see Note J)		7,371		—		—
Exploration incentive tax credits		5,570		—		—
Other income		5,406		1,714		1,156

Total interest and other income	$	48,390	$	26,460	$	1,837


(a)		The Company’s operations in Argentina and Africa periodically recognize monetary assets and liabilities in currencies other than their functional currencies (see Note B for information regarding the functional currencies of subsidiary entities). Associated therewith, the Company realizes foreign currency remeasurement and transaction gains and losses.

NOTE N. Asset Divestitures

During the years ended December 31, 2006, 2005 and 2004, the Company completed asset divestitures for net proceeds of $1.8 billion, $1.2 billion and $1.7 million, respectively. Associated therewith, the Company recorded gains (losses) on disposition of assets in continuing operations of $(7.9) million, $59.8 million and $39 thousand during the years ended December 31, 2006, 2005 and 2004, respectively, and gains of $733.3 million and $166.1 million in discontinued operations in 2006 and 2005, respectively. The following represent the significant divestitures:

Deepwater Gulf of Mexico and Argentine divestitures. During 2006, the Company sold its interests in certain oil and gas properties in the deepwater Gulf of Mexico for net proceeds of $1.2 billion, resulting in a gain of $726.2 million and its Argentine assets for net proceeds of $669.6 million, resulting in a gain of $10.9 million. Pursuant to SFAS 144, the gain and the results of operations from these assets have been reclassified to discontinued operations. See Note V for additional information.

Volumetric production payments. During 2005, the Company sold three VPPs for proceeds of $892.6 million. No gain or loss was recognized. See Note T for additional information.

Canadian and Gulf of Mexico Shelf divestitures. During 2005, the Company sold its interests in the Martin Creek, Conroy Black and Lookout Butte areas in Canada for net proceeds of $197.2 million, resulting in a gain of $138.3 million and certain assets on the Gulf of Mexico shelf for net proceeds of $59.2 million, resulting in a gain of $27.9 million. Pursuant to SFAS 144, the gain and the results of operations from these assets have been reclassified to discontinued operations. See Note V for additional information.

East Texas divestiture. During the year ended December 31, 2005, the Company sold its interests in certain East Texas properties for $25.3 million of net cash proceeds with no corresponding gain or loss recognized.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

Gabon divestiture. In October 2005, the Company closed the sale of the shares in a Gabonese subsidiary that owns the interest in the Olowi block for $47.9 million of net proceeds. A gain was recognized during the fourth quarter of 2005 of $47.5 million with no associated income tax effect either in Gabon or the United States. In addition, Pioneer retains the potential, under certain circumstances, to receive additional payments for production from deeper reservoirs discovered on the block.

NOTE O. Other Expense

The following table provides the components of the Company’s other expense during the years ended December 31, 2006, 2005 and 2004:


	Year Ended December 31,
	2006			2005		2004
	(in thousands)
Derivative ineffectiveness (see Note J)	$	(10,595	)	$	29,829	$	4,168
Loss on early extinguishment of debt (see Note F)		8,076			25,975		—
Contingency accrual adjustments (see Note I)		10,119			9,455		10,866
Foreign currency remeasurement and exchange losses (a)		580			109		302
Noncompete agreement amortization		1,670			3,914		798
Minority interest in subsidiaries’ net income (see Note B)		2,629			3,482		896
Postretirement obligation revaluation		642			3,211		—
Bad debt expense		4,733			367		3,674
Debt exchange offer costs (see Note F)		—			—		2,248
Non-hedge derivative losses		6,517			3,860		—
Load loss insurance charge		4,000			—		—
Legal settlements		1,489			—		150
Abandoned acquisitions		1,775			13		—
Well servicing operations		1,722			—		—
Other charges		3,562			508		2,496

Total other expense	$	36,919		$	80,723	$	25,598


(a)		The Company’s operations in Argentina and Africa periodically recognize monetary assets and liabilities in currencies other than their functional currencies (see Note B for information regarding the functional currencies of subsidiary entities). Associated therewith, the Company realizes foreign currency remeasurement and transaction gains and losses.

NOTE P. Income Taxes

The Company accounts for income taxes in accordance with the provisions of SFAS No. 109, “Accounting for Income Taxes” (“SFAS 109”). The Company and its eligible subsidiaries file a consolidated United States federal income tax return. Certain subsidiaries are not eligible to be included in the consolidated United States federal income tax return and separate provisions for income taxes have been determined for these entities or groups of entities. The tax returns and the amount of taxable income or loss are subject to examination by United States federal, state, local and foreign taxing authorities. Current and estimated tax payments of $153.2 million, $41.4 million and $19.2 million were made during the years ended December 31, 2006, 2005 and 2004, respectively.

SFAS 109 requires that the Company continually assess both positive and negative evidence to determine whether it is more likely than not that deferred tax assets can be realized prior to their expiration. Pioneer monitors Company-specific, oil and gas industry and worldwide economic factors and assesses the likelihood that the Company’s net operating loss carryforwards (“NOLs”) and other deferred tax attributes in the United States, state, local and foreign tax jurisdictions will be utilized prior to their expiration. As of December 31, 2006 and 2005, the Company’s valuation allowances related to foreign and domestic tax jurisdictions were $94.7 million and $95.8 million, respectively.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

The Company’s effective tax rate on continuing operations of 48.4 percent and 44.7 percent for the years ended December 31, 2006 and 2005, respectively, differs from the combined United States federal and state statutory rate of approximately 36.5 percent primarily due to:

	•		foreign tax rates,

	•		adjustments to the deferred tax liability for changes in enacted tax laws and rates, as discussed below,

	•		statutes in foreign jurisdictions that differ from those in the United States,

	•		recognition of $8.4 million of deferred tax benefit, during 2006, as a result of conversion of senior convertible notes prior to the Company’s repayment of the debt principal (see Note F),

	•		recognition of $7.2 million of taxes during 2005 associated with the repatriation of foreign earnings pursuant to the American Jobs Creation Act of 2004 (“AJCA”) and

	•		expenses for unsuccessful well costs and associated acreage costs in foreign locations where the Company does not expect to receive income tax benefits.

During May 2006, the State of Texas enacted legislation that changed the existing Texas franchise tax from a tax based on net income or taxable capital to an income tax based on a defined calculation of gross margin (the “Texas margin tax”). Also, during 2006, the Canadian federal and provincial governments enacted tax rate reductions that will be phased in over several years. SFAS 109 requires that deferred tax balances be adjusted to reflect tax rate changes during the periods in which the tax rate changes are enacted. The adjustment due to the enactment of the Texas margin tax and the Canadian tax rate changes resulted in a $13.5 million United States tax expense and a $10.2 million Canadian tax benefit, which, for Canada, is reflected in income from discontinued operations, net of tax, during the year ended December 31, 2006, respectively.

In October 2004, the AJCA was signed into law. The AJCA includes a deduction of 85 percent of qualified foreign earnings that are repatriated, as defined in the AJCA. During 2005, the Company determined that it was advantageous to apply the provisions of the AJCA to qualified foreign earnings that could be repatriated. The Company formalized repatriation plans in 2005 and repatriated $322.5 million from Canada, South Africa and Tunisia. Approximately $177 million of the repatriated funds qualified for the dividend exclusion. The Company is obligated by the provisions of the AJCA to invest the qualifying dividends in the United States within a reasonable period of time.

Included in the Company’s income tax provision from continuing operations for the year ended December 31, 2005 is the reversal of a $26.9 million tax benefit recorded in 2004 as a result of the cancellation of the development of the Olowi block and the Company’s decision to exit Gabon. Reversal of the tax benefit was the result of signing an agreement in June 2005 to sell the Company’s shares in the subsidiary that owns the interest in the Olowi block to an unaffiliated buyer, which made it more likely than not that the Company would not realize the originally recorded tax benefit. The Company completed the sale of the Gabonese subsidiary during 2005.

The Company’s income tax provision (benefit) and amounts separately allocated were attributable to the following items for the years ended December 31, 2006, 2005 and 2004:


	Year Ended December 31,
	2006			2005			2004
				(in thousands)
Income from continuing operations	$	141,021		$	149,231		$	62,086
Income from discontinued operations		295,501			215,614			104,273
Changes in goodwill — tax benefits related to stock-based compensation		(1,742	)		(7,255	)		(8,955	)
Changes in stockholders’ equity:
Net deferred hedge gains (losses)		193,719			(166,572	)		(73,340	)
Tax benefits related to stock-based compensation		(4,247	)		(18,752	)		(6,612	)
Translation adjustment		8,421			3,685			(314	)

	$	632,673		$	175,951		$	77,138

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

The Company’s income tax provision (benefit) attributable to income from continuing operations consisted of the following for the years ended December 31, 2006, 2005 and 2004:


	Year Ended December 31,
	2006			2005			2004
	(in thousands)
Current:
U.S. federal	$	(54,004	)	$	13,104		$	2,500
U.S. state and local		(52	)		(254	)		602
Foreign		33,316			37,002			14,463

		(20,740	)		49,852			17,565


Deferred:
U.S. federal		126,215			90,988			45,413
U.S. state and local		18,438			3,038			1,094
Foreign		17,108			5,353			(1,986	)

		161,761			99,379			44,521

	$	141,021		$	149,231		$	62,086

Income from continuing operations before income taxes consists of the following for the years ended December 31, 2006, 2005 and 2004:


	Year Ended December 31,
	2006		2005		2004
	(in thousands)
U.S. federal	$	235,049	$	194,993	$	210,786
Foreign		56,189		138,543		4,471

	$	291,238	$	333,536	$	215,257

Reconciliations of the United States federal statutory tax rate to the Company’s effective tax rate for income from continuing operations are as follows for the years ended December 31, 2006, 2005 and 2004:


	Year Ended December 31,
	2006			2005			2004
	(in percentages)
U.S. federal statutory tax rate		35.0			35.0			35.0
State income taxes (net of federal benefit)		1.7			1.1			1.2
U.S. valuation allowance changes		0.3			0.2			—
Foreign valuation allowances		8.8			0.3			7.8
Rate differential on foreign operations		4.7			2.8			11.2
Change in statutory rates		1.0			0.1			—
Gabon investment deduction		—			7.4			(13.1	)
Gabon tax free book gain		—			(4.7	)		—
Repatriation of foreign earnings		—			2.0			—
Conversion of senior convertible notes		(2.7	)		—			—
Other		(0.4	)		0.5			(13.3	)

Consolidated effective tax rate		48.4			44.7			28.8

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities are as follows as of December 31, 2006 and 2005:


	December 31,
	2006			2005
	(in thousands)
Deferred tax assets:
Net operating loss carryforwards	$	102,251		$	191,314
Alternative minimum tax credit carryforwards		—			10,725
Net deferred hedge losses		97,717			291,216
Asset retirement obligations		76,509			54,338
Other		99,330			95,073

Total deferred tax assets		375,807			642,666
Valuation allowances		(94,745	)		(95,750	)

Net deferred tax assets		281,062			546,916

Deferred tax liabilities:
Oil and gas properties, principally due to differences in basis, depletion and the deduction of intangible drilling costs for tax purposes		1,232,025			1,053,989
Other		138,272			101,378

Total deferred tax liabilities		1,370,297			1,155,367

Net deferred tax liability	$	(1,089,235	)	$	(608,451	)

At December 31, 2006, the Company had NOLs in the United States, Canada, South Africa and other African countries for income tax purposes as set forth below, which are available to offset future regular taxable income in each respective tax jurisdiction, if any. Additionally, the Company has alternative minimum tax NOLs (“AMT NOLs”) in the United States which are available to reduce future alternative minimum taxable income, if any. These carryforwards expire as follows:


							South		Other
	U.S.				Canada		Africa		African
Expiration Date	NOL		AMT NOL		NOL		NOL		NOLs (a)
	(in thousands)
2009	$	29,999	$	32,003	$	—	$	—	$	—
2010		49,858		47,854		—		—		—
2020		5,588		5,055		—		—		—
2021		53		—		—		—		—
2026		—		—		6,269		—		—
Indefinite		—		—		—		49,247		118,190

	$	85,498	$	84,912	$	6,269	$	49,247	$	118,190


(a)		The Company believes that it is more likely than not that these other African NOLs will not offset future taxable income and has provided a valuation allowance against these deferred tax assets.

The remaining $85 million of the U.S. NOLs and AMT NOLs are subject to Section 382 of the Internal Revenue Code and will become available to offset future regular or alternative minimum taxable income over the next four years. During the years ended December 31, 2006, 2005 and 2004, the Company utilized $409.8 million, $311.6 million and $151.1 million of NOLs, respectively.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

The Company’s income tax provision (benefit) attributable to income from discontinued operations consisted of the following for the years ended December 31, 2006, 2005 and 2004:


	Year Ended December 31,
	2006			2005		2004
				(in thousands)
Current:
U.S. federal	$	145,623		$	2,438	$	—
U.S. state and local		1,421			104		—
Foreign		4,633			5,290		7,723

		151,677			7,832		7,723


Deferred:
U.S. federal		144,387			153,030		93,309
U.S. state and local		6,449			6,558		3,999
Foreign		(7,012	)		48,194		(758	)

		143,824			207,782		96,550

	$	295,501		$	215,614	$	104,273

NOTE Q. Income Per Share From Continuing Operations

Basic income per share from continuing operations is computed by dividing income from continuing operations by the weighted average number of common shares outstanding for the period. The computation of diluted income per share from continuing operations reflects the potential dilution that could occur if securities or other contracts to issue common stock that are dilutive to income from continuing operations were exercised or converted into common stock or resulted in the issuance of common stock that would then share in the earnings of the Company.

The following table is a reconciliation of the basic income from continuing operations to diluted income from continuing operations for the years ended December 31, 2006, 2005 and 2004:


	Year Ended December 31,
	2006		2005		2004
			(in thousands)
Basic income from continuing operations	$	150,217	$	184,305	$	153,171
Interest expense on convertible notes, net of tax		1,903		3,207		802

Diluted income from continuing operations	$	152,120	$	187,512	$	153,973

The following table is a reconciliation of the basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the years ended December 31, 2006, 2005 and 2004:


	Year Ended December 31,
	2006		2005		2004
	(in thousands)
Weighted average common shares outstanding (a):
Basic		124,359		137,110		125,156
Dilutive common stock options (b)		747		1,136		1,218
Restricted stock awards		989		844		529
Convertible notes dilution (c)		1,513		2,327		585

Diluted		127,608		141,417		127,488


(a)		During 2005, the Board approved a share repurchase program authorizing the purchase of up to $1 billion of the Company’s common stock, $640.7 million of which was completed in 2005 and $345.3 million of which was completed in 2006.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004


(b)		Common stock options to purchase 30,712 shares of common stock were outstanding but not included in the computations of diluted income per share from continuing operations for 2004 because the exercise prices of the options were greater than the average market price of the common shares and would be anti-dilutive to the computation.

(c)		During 2006, holders of all of the $100 million of 4 3/4% Senior Convertible Notes exercised their conversion rights.

NOTE R. Geographic Operating Segment Information

The Company has operations in only one industry segment, that being the oil and gas exploration and production industry; however, the Company is organizationally structured along geographic operating segments or regions. The Company has reportable continuing operations in the United States, Canada, South Africa, Tunisia and Other. Other is primarily comprised of operations in Equatorial Guinea, Gabon and Nigeria.

During 2007, the Company sold its Canadian assets. During 2006, the Company sold certain oil and gas properties in the deepwater Gulf of Mexico and all of its Argentine assets, which had carrying values of $430.6 million and $658.7 million, respectively, on their dates of sale. During 2005, the Company sold certain Canadian and United States oil and gas properties having carrying values of $58.9 million and $31.4 million, respectively, on their dates of sale. The results of operations of those properties have been reclassified as discontinued operations in accordance with SFAS 144 and, aside from costs incurred for oil and gas activities, are excluded from the geographic operating segment information provided below. See Notes B, V and W for information regarding the Company’s discontinued operations.

The following tables provide the Company’s geographic operating segment data required by SFAS No. 131, “Disclosure about Segments of an Enterprise and Related Information”, as well as results of operations of oil and gas producing activities required by SFAS No. 69, “Disclosures about Oil and Gas Producing Activities” as of and for the years ended December 31, 2006, 2005 and 2004. Geographic operating segment income tax benefits (provisions) have been determined based on statutory rates existing in the various tax jurisdictions where the Company has oil and gas producing activities. The “Headquarters” table column includes income and expenses that are not routinely included in the earnings measures internally reported to management on a geographic operating segment basis.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004


	United			South												Consolidated
	States			Africa			Tunisia			Other			Headquarters			Total
	(in thousands)
Year ended December 31, 2006:
Revenues and other income:
Oil and gas	$	1,302,029		$	99,309		$	57,602		$	—		$	—		$	1,458,940
Interest and other		—			—			—			—			48,390			48,390
Gain (loss) on disposition of assets, net		(451	)		—			—			—			(6,008	)		(6,459	)

		1,301,578			99,309			57,602			—			42,382			1,500,871

Costs and expenses:
Oil and gas production		324,049			21,795			3,222			—			—			349,066
Depletion, depreciation and amortization		276,921			9,455			4,007			—			23,698			314,081
Exploration and abandonments		172,859			7,516			14,616			55,205			—			250,196
General and administrative		—			—			—			—			116,595			116,595
Accretion of discount on asset retirement obligations		—			—			—			—			3,726			3,726
Interest		—			—			—			—			107,050			107,050
Hurricane activity, net		32,000			—			—			—			—			32,000
Other		—			—			—			—			36,919			36,919

		805,829			38,766			21,845			55,205			287,988			1,209,633

Income (loss) from continuing operations before income taxes		495,749			60,543			35,757			(55,205	)		(245,606	)		291,238
Income tax benefit (provision)		(180,948	)		(17,557	)		(22,450	)		—			79,934			(141,021	)

Income (loss) from continuing operations	$	314,801		$	42,986		$	13,307		$	(55,205	)	$	(165,672	)	$	150,217

Costs incurred for oil and gas activities (a)	$	1,184,280		$	131,763		$	46,149		$	46,756		$	264,431		$	1,673,379

Year ended December 31, 2005:
Revenues and other income:
Oil and gas	$	1,144,163		$	127,470		$	67,250		$	—		$	—		$	1,338,883
Interest and other		—			—			—			—			26,460			26,460
Gain on disposition of assets, net		12,114			—			—			47,532			417			60,063

		1,156,277			127,470			67,250			47,532			26,877			1,425,406

Costs and expenses:
Oil and gas production		277,297			28,354			4,063			—			—			309,714
Depletion, depreciation and amortization		219,045			24,494			4,758			—			19,460			267,757
Impairment of long-lived assets		—			—			—			644			—			644
Exploration and abandonments		97,126			1,211			10,898			44,544			—			153,779
General and administrative		—			—			—			—			110,104			110,104
Accretion of discount on asset retirement obligations		—			—			—			—			3,349			3,349
Interest		—			—			—			—			125,987			125,987
Hurricane activity, net		39,813			—			—			—			—			39,813
Other		—			—			—			—			80,723			80,723

		633,281			54,059			19,719			45,188			339,623			1,091,870

Income (loss) from continuing operations before income taxes		522,996			73,411			47,531			2,344			(312,746	)		333,536
Income tax benefit (provision)		(190,894	)		(21,289	)		(32,422	)		—			95,374			(149,231	)

Income (loss) from continuing operations	$	332,102		$	52,122		$	15,109		$	2,344		$	(217,372	)	$	184,305

Costs incurred for oil and gas activities (a)	$	903,390		$	18,541		$	21,317		$	75,411		$	260,877		$	1,279,536


(a)		Costs incurred for Headquarters represents Canadian and Argentine cost incurred prior to divestment.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004


	United			South												Consolidated
	States			Africa			Tunisia			Other			Headquarters			Total
							(in thousands)
Year ended December 31, 2004:
Revenues and other income:
Oil and gas	$	799,242		$	129,856		$	33,064		$	—		$	—		$	962,162
Interest and other		—			—			—			—			1,837			1,837
Gain on disposition of assets, net		51			—			—			—			241			292

		799,293			129,856			33,064			—			2,078			964,291

Costs and expenses:
Oil and gas production		174,583			28,478			3,032			—			—			206,093
Depletion, depreciation and amortization		149,282			44,091			3,744			—			11,199			208,316
Impairment of long-lived assets		—			—			—			39,684			—			39,684
Exploration and abandonments		55,010			530			2,042			36,727			—			94,309
General and administrative		—			—			—			—			69,490			69,490
Accretion of discount on asset retirement obligations		—			—			—			—			3,557			3,557
Interest		—			—			—			—			101,987			101,987
Other		—			—			—			—			25,598			25,598

		378,875			73,099			8,818			76,411			211,831			749,034

Income (loss) from continuing operations before income taxes		420,418			56,757			24,246			(76,411	)		(209,753	)		215,257
Income tax benefit (provision)		(153,452	)		(17,027	)		(12,124	)		—			120,517			(62,086	)

Income (loss) from continuing operations	$	266,966		$	39,730		$	12,122		$	(76,411	)	$	(89,236	)	$	153,171

Costs incurred for oil and gas activities (a)	$	2,876,185		$	9,473		$	17,015		$	48,418		$	223,078		$	3,174,169


(a)		Costs incurred for Headquarters represents Canadian and Argentine cost incurred prior to divestment.


	December 31,
	2006		2005		2004
			(in thousands)
Total Assets:
United States	$	6,395,046	$	5,899,637	$	5,460,708
Argentina		2,444		735,191		708,391
Canada		547,012		363,773		316,124
South Africa		176,789		64,071		74,250
Tunisia		72,142		59,125		37,924
Other		41,238		47,288		10,899
Headquarters		120,728		160,149		125,191

Total consolidated assets	$	7,355,399	$	7,329,234	$	6,733,487

NOTE S. Impairment of Oil and Gas Properties

During October 2004, the Company concluded that a $39.7 million charge for impairment was required under SFAS 144 for its Gabonese Olowi field as development of the discovery was canceled. Due to significant increases in projected field development costs, primarily due to increases in steel costs, the project did not offer competitive returns. The Olowi field was the Company’s only Gabonese investment. During 2005, the Company recorded an incremental impairment charge of $644 thousand to eliminate the carrying value of the Company’s Gabonese Olowi field.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

NOTE T. Volumetric Production Payments

During 2005, the Company sold 27.8 MMBOE of proved reserves by means of three VPP agreements for net proceeds of $892.6 million, including the assignment of the Company’s obligations under certain derivative hedge agreements. Proceeds from the VPPs were initially used to reduce outstanding indebtedness. The first VPP sold 58 Bcf of gas volumes over an expected five-year term that began in February 2005. The second VPP sold 10.8 million barrels of oil (“MMBbls”) of oil volumes over an expected seven-year term that began in January 2006. The third VPP sold 6.0 Bcf of gas volumes over an expected 32-month term that began in May 2005 and 6.2 MMBbls of oil volumes over an expected five-year term that began in January 2006.

The Company’s VPPs represent limited-term overriding royalty interests in oil and gas reserves which: (i) entitle the purchaser to receive production volumes over a period of time from specific lease interests; (ii) are free and clear of all associated future production costs and capital expenditures; (iii) are nonrecourse to the Company (i.e., the purchaser’s only recourse is to the assets acquired); (iv) transfer title to the purchaser; and (v) allow the Company to retain the assets after the VPPs volumetric quantities have been delivered.

Under SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” a VPP is considered a sale of proved reserves. As a result, the Company (i) removed the proved reserves associated with the VPPs; (ii) recognized the VPP proceeds as deferred revenue which are being amortized on a unit-of-production basis to oil and gas revenues over the terms of the VPPs; (iii) retained responsibility for 100 percent of the production costs and capital costs related to VPP interests; and (iv) no longer recognizes production associated with the VPP volumes.

The following table provides information about the deferred revenue carrying values of the Company’s VPPs:


	Gas			Oil			Total
				(in thousands)
Deferred revenue at December 31, 2005	$	249,323		$	605,515		$	854,838
Less 2006 amortization		(74,235	)		(116,092	)		(190,327	)

Deferred revenue at December 31, 2006	$	175,088		$	489,423		$	664,511

The above deferred revenue amounts will be recognized in oil and gas revenues in the Consolidated Statements of Operations as noted below, assuming the related VPP production volumes are delivered as scheduled (in thousands):


2007	$	181,232
2008		158,138
2009		147,906
2010		90,215
2011		44,951
2012		42,069

	$	664,511

NOTE U. Insurance Claims

Hurricane Ivan. During September 2004, the Company sustained damages as a result of Hurricane Ivan at its Devils Tower and Canyon Express platform facilities in the deepwater Gulf of Mexico. The damages delayed scheduled well completions and interrupted production during the second half of 2004 and during the first half of 2005. The Company maintains business interruption insurance coverage for such circumstances. During 2004 and 2005, the Company filed claims with its insurance providers for its estimated losses associated with Hurricane Ivan.

Based on a settlement agreement between the Company and the insurance providers, the Company’s recoverable business interruption loss related to Hurricane Ivan was $67.0 million. The Company recorded $7.6

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

million and $59.4 million of the claims in 2004 and 2005, respectively, in income from discontinued operations in the accompanying Consolidated Statements of Operations.

Fain Plant. During May 2005, the Company sustained damages as a result of a fire at its Fain gas plant in the West Panhandle field. The damages interrupted production from mid-May through mid-July of 2005. The Company maintained business interruption and physical damage insurance coverage for such circumstances. The Company recognized a total of $17.9 million in business interruption recoveries and $4.4 million in physical damage recoveries associated with the Fain gas plant fire. The Company recognized $14.2 million of the business interruption recoveries in 2005 and the remaining $3.7 million in 2006, which is included in other income in the accompanying Consolidated Statements of Operations.

Hurricanes Katrina and Rita. During August and September 2005, the Company sustained damages as a result of Hurricanes Katrina and Rita at various facilities in the Gulf of Mexico. Other than the East Cameron facility discussed further below, the damages to the facilities were covered by physical damage insurance.

The Company filed a business interruption claim with its insurance provider related to its Devils Tower field resulting from its inability to sell production as a result of damages to third-party facilities. During 2006, the Company settled its business interruption claim with its insurance provider for $18.5 million, which is included in income from discontinued operations in the accompanying Consolidated Statements of Operations.

As a result of Hurricane Rita, the Company’s East Cameron facility, located in the Gulf of Mexico shelf, was destroyed and the Company does not plan to rebuild the facility based on the economics of the field. During the fourth quarter of 2006, the Company’s application to “reef in-place” a substantial portion of the East Cameron debris was denied. As a result, the Company, at December 31, 2006, estimates that it will cost approximately $119 million to reclaim and abandon the East Cameron facility. The estimate to reclaim and abandon the East Cameron facility is based upon an analysis and fee proposal prepared by a third-party engineering firm for the majority of the work and an estimate by the Company for the remainder. During 2006 and 2005, the Company recorded additional abandonment obligation charges of $75.0 million and $39.8 million, respectively, which amounts are included in hurricane activity, net in the accompanying Consolidated Statements of Operations. The operations to reclaim and abandon the East Cameron facilities began in January 2007 and the Company expects to incur a substantial portion of the costs in 2007.

The $119 million estimate to reclaim and abandon the East Cameron facilities contains a number of assumptions that could cause the ultimate cost to be higher or lower as there are many uncertainties when working offshore and underwater with damaged equipment and wellbores. The Company currently believes costs could range from $119 million to $175 million; however, at this point no better estimate than any other amount within the range can be determined, thus the Company has recorded the estimated provision of $119 million.

The Company has filed a claim with its insurance providers regarding the loss at East Cameron. Under the Company’s insurance policies, the East Cameron facility had the following coverages: (a) $14 million of scheduled property value for the platform, (b) $4 million of scheduled business interruption insurance after a deductible waiting period, (c) $100 million of well restoration and safety, in total, for all assets per occurrence and (d) $400 million for debris removal coverage for all assets per occurrence.

In December 2005, the Company received the $14 million of scheduled property value for the East Cameron assets and recognized a gain of $9.7 million associated therewith. The Company received the $4 million of business interruption recoveries in 2006, which is reflected in interest and other income in the accompanying Consolidated Statements of Operations. During the fourth quarter of 2006, the Company recorded estimated insurance recoveries of $43 million, which is reflected in other current assets in the accompanying Consolidated Balance Sheet and in hurricane activity, net in the accompanying Consolidated Statements of Operations, related to the estimated costs for the debris removal portion of the claim as the Company believes that it is probable that it will be successful in asserting coverage under the debris removal part of its insurance coverage. At the present, no recoveries have been reflected related to the well restoration and safety coverages as the Company is working to resolve coverage issues

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

regarding coverage under this section of the insurance policies. Overall, the Company ultimately expects a substantial portion of the loss to be covered by insurance. See Note W for additional information.

NOTE V. Discontinued Operations

During 2005, 2006 and 2007, the Company sold its interests in the following significant oil and gas assets:


Country	Description of Assets	Date Divested	Net Proceeds			Gain
			(in millions)
Canada	Martin Creek, Conroy Black and Lookout Butte fields	May 2005	$	197.2		$	138.3

United States	Two Gulf of Mexico shelf fields	August 2005	$	59.2		$	27.9

United States	Deepwater Gulf of Mexico fields	March 2006	$	1,156.9	(a)	$	726.2

Argentina	Argentine assets	April 2006	$	669.6		$	10.9

Canada	Canadian assets	November 2007		(b	)		(b	)


(a)		Net proceeds do not reflect the cash payment of $164.3 million for terminated hedges associated with the deepwater Gulf of Mexico assets.

(b)		See Notes B and W for additional information regarding this 2007 transaction.

Pursuant to SFAS 144, the Company has reflected the results of operations of the above divestitures as discontinued operations, rather than as a component of continuing operations. The following table represents the components of the Company’s discontinued operations for the years ended December 31, 2006, 2005 and 2004:


	Year Ended December 31,
	2006			2005			2004
				(in thousands)
Revenues and other income:
Oil and gas	$	322,426		$	920,704		$	870,501
Interest and other		33,550			70,590			12,238
Gain (loss) on disposition of assets (a)		731,827			166,521			(253	)

		1,087,803			1,157,815			882,486

Costs and expenses:
Oil and gas production		80,514			154,032			139,411
Depletion, depreciation and amortization (a)		82,770			311,472			366,558
Exploration and abandonments (a)		21,275			73,400			87,379
General and administrative		14,501			14,619			11,038
Accretion of discount on asset retirement obligations (a)		1,904			4,527			4,653
Interest		442			1,800			1,401
Other		1,382			32,088			8,090

		202,788			591,938			618,530

Income from discontinued operations before income taxes		885,015			565,877			263,956
Income tax provision:
Current		(151,677	)		(7,832	)		(7,723	)
Deferred (a)		(143,824	)		(207,782	)		(96,550	)

Income from discontinued operations	$	589,514		$	350,263		$	159,683


(a)		Represents the significant noncash components of discontinued operations included in the Company’s Consolidated Statements of Cash Flows.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

NOTE W. Subsequent Events (Unaudited)

Canadian divestiture. In August 2007, the Company entered into a share purchase agreement for the sale of all of the common stock of its Canadian subsidiaries for cash proceeds of $540 million, subject to normal closing adjustments. During November 2007, the Company completed the divestiture of the common stock of its Canadian subsidiaries. Associated therewith, the Company will report a gain of approximately $100 million during the fourth quarter of 2007 and has reclassified the historic results of operations, comprehensive income and cash flows of its Canadian assets to discontinued operations in accordance with SFAS 144.

Line of credit. During April 2007, the Company entered into an Amended and Restated 5-Year Revolving Credit Agreement (the “Credit Facility”), as amended, that matures in April 2012 unless extended in accordance with the terms of the Credit Facility. The Credit Facility provides for initial aggregate loan commitments of $1.5 billion, which may be increased to a maximum aggregate amount of $2.0 billion if the lenders increase their loan commitments or if loan commitments of new financial institutions are added.

Borrowings under the Credit Facility may be in the form of revolving loans or swing line loans. Aggregate outstanding swing line loans may not exceed $150 million. Revolving loans bear interest, at the option of the Company, based on (a) a rate per annum equal to the higher of the prime rate announced from time to time by JPMorgan Chase Bank or the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System during the last preceding business day plus .5 percent or (b) a base Eurodollar rate, substantially equal to LIBOR, plus a margin (the “Applicable Margin”) (currently .75 percent) that is determined by a reference grid based on the Company’s debt rating (currently .75 percent). Swing line loans bear interest at a rate per annum equal to the “ASK” rate for Federal funds periodically published by the Dow Jones Market Service plus the Applicable Margin. Letters of credit outstanding under the Credit Facility are subject to a per annum fee, representing the Applicable Margin plus .125 percent.

The Credit Facility contains certain financial covenants, which include the maintenance of a ratio of total debt to book capitalization less intangible assets, accumulated other comprehensive income and certain noncash asset impairments not to exceed .60 to 1.0. The covenants also include the maintenance of a ratio of the net present value of the Company’s oil and gas properties to total debt of at least 1.75 to 1.0 until the Company achieves an investment grade rating by Moody’s Investors Service, Inc. or Standard & Poors Ratings Group, Inc.

Senior notes. During March 2007, the Company issued $500 million of 6.65% senior notes due 2017 (the “6.65% Notes”) and received proceeds, net of issuance discount and underwriting costs, of $494.8 million. The Company used the net proceeds from the issuance of the 6.65% Notes to reduce indebtedness under its credit facility.

Legal actions update. Following are significant developments regarding the Company’s legal actions that have occurred during 2007 (also, see Note I for additional information):

Alford. The Company received final approval for the Alford settlement from the 26^th Judicial District Court of Stevens County, Kansas on February 9, 2007 and the settlement became final during April 2007.

MOSH Holding. In January 2007, the Company announced that they had reached a conditional settlement in the lawsuit. The settlement was subject to certain conditions, including an order by the Court approving the settlement. On June 19, 2007, the Court denied a motion to approve the settlement and as a result, the settlement is void and not effective.

On October 26, 2007, JP Morgan Chase Bank, N.A. (“JP Morgan”) and Plaintiffs announced that they had entered a conditional settlement of the claims against JP Morgan and that, as part of that arrangement, JP Morgan would resign as Trustee and Plaintiffs would seek the appointment of a temporary trustee. On December 3, 2007, JP Morgan and Plaintiffs filed motions with the Court to approve the settlement agreement and to appoint Thomas L. Easley as the temporary trustee. Those motions are set for hearing on January 16, 2008. The Company has filed notices confirming its intention to object to the terms of the proposed settlement and to the proposed substitution of a temporary trustee in place of JP Morgan. In addition, on December 20, 2007, Pioneer filed a cross-claim against

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

JP Morgan seeking, among other things, to prevent JP Morgan from resigning as Trustee on the grounds that the Trust Indenture requires that the Trust must be liquidated and terminated.

The Company believes the claims made by the Plaintiffs in the MOSH Holding lawsuit are without merit and intends to defend the lawsuit vigorously.

Dorchester Refining Company Site. The TCEQ recently informed the Company that other previous owners and operators applied for acceptance into the Texas Voluntary Cleanup Program to clean up the site. As a result, the TCEQ deleted the site from the state Superfund registry and no longer considers the Company’s subsidiary a potentially responsible party with respect to the site.

Equatorial Guinea Block H Arbitration. On June 14, 2007, a subsidiary of the Company (“Pioneer EG”) commenced arbitration in London, England against Roc Oil (Equatorial Guinea) Company (“ROC EG”), Atlas Petroleum International Limited (“Atlas”) and Osborne Resources Limited (“Osborne”) to determine the parties’ relative rights under a joint operating agreement relating to well operations in Block H in deepwater Equatorial Guinea. ROC, Atlas and Osborne have, in turn, notified Pioneer EG of various claims arising under farm-in agreements relating to Block H. In late 2006, the Republic of Equatorial Guinea ratified a new hydrocarbons law, which effectively increases the obligations of the parties subject to the underlying production sharing contract in various respects. Pursuant to the new law, Equatorial Guinea is entitled to participate in any contract area either directly or through the National Oil Company by way of a substantial additional carried interest. In addition, drilling costs for the well have increased significantly beyond those originally anticipated.

Pioneer EG and the other parties in Block H have been evaluating the effect of the new hydrocarbons law and the increased well costs, but have been unable to reach an agreement as to the parties’ obligations. Pioneer EG has asserted that it does not have an obligation under the circumstances to fund its share of the costs or its carried share of the other parties’ costs of drilling a well on the block. The view of the other parties is that Pioneer EG does not have the right to prevent the drilling of the well or to refuse to pay its share of the costs thereof. ROC EG, Atlas and Osborne have also notified Pioneer EG that they reserve the right to claim damages if the underlying production sharing contract is terminated by Equatorial Guinea.

The parties have consolidated their respective claims under the joint operating agreement and the farm-in agreements into a single arbitration to be conducted in London, England during 2008. Pioneer EG intends vigorously to assert its position in the arbitration. The Company cannot predict whether the outcome of this proceeding will negatively impact the Company’s liquidity, financial position or future results of operations.

2007 significant acquisitions. In July 2007, the Company entered into an agreement under which the Company has the option to purchase an additional 22 percent interest in the Spraberry Midkiff-Benedum gas processing system for $230 million, subject to normal closing adjustments. The additional 22 percent interest can be purchased in increments in 2008 and 2009 and, if exercised, will increase the Company’s interest in the system to 49 percent. In conjunction with this transaction, the Company extended its percent of proceeds (“POP”) contract with the plant to 2022 and negotiated incremental increases in the Company’s POP beginning in 2009.

In July 2007, the Company entered into an agreement to acquire an interest in proved and unproved properties in the Spraberry field in West Texas for $90 million, subject to normal closing adjustments. The acquisition closed during the fourth quarter of 2007.

In July 2007, the Company entered into an agreement to acquire an interest in proved and unproved properties in the Raton Basin for $205 million, subject to normal closing adjustments. The acquisition closed in the fourth quarter of 2007.

In November 2007, the Company agreed to acquire an interest in proved and unproved properties in the Barnett Shale play for $150 million, subject to normal closing adjustments. The acquisition closed during the fourth quarter of 2007.

Pioneer Southwest Energy Partners L.P. Initial Public Offering. On January 8, 2008, Pioneer Southwest Energy Partners L.P. (“Pioneer Southwest”), a subsidiary of the Company, filed an amendment to its registration statement (subject to completion) with the SEC to sell limited partner interests. Pioneer Southwest will own

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

interests in certain oil and gas properties currently owned by the Company in the Spraberry field in the Permian Basin of West Texas. Pioneer Southwest anticipates offering 7,500,000 common units in the initial public offering representing a 35.3 percent limited partner interest in Pioneer Southwest. Upon completion of this offering, the Company will own a 0.1 percent general partner interest and a 64.6 percent limited partner interest in Pioneer Southwest. The underwriters are expected to be granted a 30-day option to purchase up to 1,125,000 additional common units. The Company’s limited partner interest would be reduced to 61.4 percent if the underwriters exercise their over-allotment option in full. Assuming an initial public offering price of $20.00 per common unit and that the underwriters do not exercise their over-allotment option, estimated gross proceeds from the offering would be $150 million. The Company expects to close the offering of the limited partner interests in the first quarter of 2008, and the Company expects that it will consolidate Pioneer Southwest into its financial statements and reflect the public ownership as minority interest.

In October 2007, Pioneer Southwest entered into a $300 million unsecured revolving credit facility (“PSE Credit Agreement”), as amended, with a syndicate of banks which will mature 5 years following the closing of the offering of the limited partner interests in Pioneer Southwest. The closing of the public offering of Pioneer Southwest’s limited partner interests is a condition to the obligation of the lenders to make loans under the PSE Credit Agreement.

The PSE Credit Agreement contains certain financial covenants applicable to Pioneer Southwest, which include (i) the maintenance of a maximum leverage ratio of not more than 3.5 to 1.0, (ii) an interest coverage ratio (representing a ratio of EBITDAX to interest expense) of not less than 2.5 to 1.0 and (iii) the maintenance of a ratio of the net present value of Pioneer Southwest’s oil and gas assets to total debt of at least 1.75 to 1.0. Because of the net present value covenant, borrowings under the PSE Credit Agreement are expected to be initially limited to approximately $150 million.

This shall not constitute an offer to sell or the solicitation of an offer to buy any securities of Pioneer Southwest. Any offers, solicitations of offers to buy, or any sales of securities of Pioneer Southwest will be made only in accordance with the registration requirements of the Securities Act of 1933 or an exemption therefrom.

East Cameron abandonment estimate. As is further described in Note U, the Company’s East Cameron facility, located on the Gulf of Mexico shelf, was destroyed as a result of Hurricane Rita in 2005. During 2007, the operations to reclaim and abandon the East Cameron facility began. The estimate to reclaim and abandon the East Cameron facility contains a number of assumptions that could cause the ultimate cost to be higher or lower than estimated because there are many uncertainties when working offshore and underwater with damaged equipment and wellbores. During the nine months ended September 30, 2007, the Company recorded additional abandonment charges of $66.0 million to increase its estimate of the costs to reclaim and abandon the East Cameron facility, which increased the estimate to reclaim and abandon the East Cameron facility to $185 million. In the third quarter of 2007, the Company commenced legal actions against certain of its insurance carriers regarding policy coverage issues. However, the Company continues to expect that a substantial portion of the loss will be recoverable from insurance.

Clipper exploratory well costs. As further described in Note D, during 2005, the Company announced a discovery on the Clipper prospect in the deepwater Gulf of Mexico. During 2006, the Company drilled two appraisal wells and began evaluating plans for potential development of the discovery. Projected capital costs for the project have doubled since the evaluation began. As a result, during the fourth quarter of 2007 a determination was made by the Company that no further activities would be pursued to develop the project. Accordingly, the Company recorded a charge to earnings in the fourth quarter of 2007 of approximately $71 million. As disclosed in Note D, the Company had capitalized costs of $75.2 million attributable to the Clipper prospect as of December 31, 2006.

Tunisia — Anaguid. During 2007, the Company concluded the remaining studies on the appraisal well that was originally drilled in 2003, as discussed in Note D, and determined the well was not economical. Accordingly, the Company recorded a charge of $5.1 million in the second quarter of 2007.

Nigerian impairment. In June 2007, the Company entered into an agreement to divest its interest in a subsidiary (owned 59 percent by the Company, the “Nigeria Subsidiary”) that held an interest in the deepwater

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006, 2005 and 2004

Nigerian Block 320. The agreement was subject to governmental approval. The governmental approval was not obtained by the deadline and as a result, Pioneer terminated the agreement. Based on the terms of the agreement, which established the Company’s estimate of fair value, the Company recorded a $12.2 million impairment charge in the second quarter of 2007 to reduce the net basis to the estimated fair value. Also, as a result of due diligence efforts that emerged as part of the Company’s compliance efforts, and with assistance from outside counsel, the Company determined that it could not, consistent with its legal obligations, fund or approve future operations in connection with Block 320. As a result, during the third quarter of 2007 the Company engaged in a process to withdraw from the production sharing contract relating to Block 320 and related agreements. As a part of this process the Company disposed of its shares in the Nigeria Subsidiary to an unaffiliated third party. As a result ,the Company no longer owns any interest in the Nigeria Subsidiary or Block 320 and will not fund or participate in any future operations in connection with Block 320, and associated therewith the Company recorded a reduction of $2.6 million to the previous impairment charge.

United States impairment. During the nine months ended September 30, 2007, the Company recorded a $5.7 million impairment provision to reduce the carrying values of certain proved oil and gas properties located in Louisiana. The impairment provision was determined in accordance with SFAS 144, and reduced the carrying values of the assets to their estimated fair value.

Equatorial Guinea. During the fourth quarter of 2007, the Company recorded a charge of approximately $11 million to write-off the Company’s remaining basis in Block H in Equatorial Guinea. This charge was recorded in the context of the ongoing arbitration among the parties participating in Block H.

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2006, 2005 and 2004

Capitalized Costs


	December 31,
	2006			2005
	(in thousands)
Oil and gas properties:
Proved	$	7,967,708		$	8,499,253
Unproved		210,344			313,881

Capitalized costs for oil and gas properties		8,178,052			8,813,134
Less accumulated depletion, depreciation and amortization		(1,895,408	)		(2,577,946	)

Net capitalized costs for oil and gas properties	$	6,282,644		$	6,235,188

Costs Incurred for Oil and Gas Producing Activities (a)


	Property								Total
	Acquisition Costs				Exploration		Development		Costs
	Proved		Unproved		Costs		Costs		Incurred
	(in thousands)
Year Ended December 31, 2006:
United States	$	78,318	$	109,321	$	296,301	$	700,340	$	1,184,280
Argentina		—		2		10,223		25,542		35,767
Canada		—		19,932		103,245		105,487		228,664
South Africa		—		—		288		131,475		131,763
Tunisia		—		5,000		40,813		336		46,149
Other		—		10,584		36,172		—		46,756

Total	$	78,318	$	144,839	$	487,042	$	963,180	$	1,673,379

Year Ended December 31, 2005:
United States	$	170,827	$	60,731	$	217,723		454,109	$	903,390
Argentina		—		512		36,878		92,250		129,640
Canada		2,593		7,344		43,437		77,863		131,237
South Africa		—		259		755		17,527		18,541
Tunisia		—		—		18,395		2,922		21,317
Other		—		30,664		44,456		291		75,411

Total	$	173,420	$	99,510	$	361,644	$	644,962	$	1,279,536

Year Ended December 31, 2004:
United States	$	2,220,813	$	301,856	$	127,338	$	226,178	$	2,876,185
Argentina		—		—		49,745		52,707		102,452
Canada		50,542		20,921		33,406		15,757		120,626
South Africa		—		—		737		8,736		9,473
Tunisia		—		6,558		5,761		4,696		17,015
Other		—		11,680		26,434		10,304		48,418

Total	$	2,271,355	$	341,015	$	243,421	$	318,378	$	3,174,169


(a)		The costs incurred for oil and gas producing activities includes the following amounts of asset retirement obligations:


	Year Ended December 31,
	2006		2005		2004
	(in thousands)
Proved property acquisition costs	$	981	$	3,183	$	10,488
Exploration costs		3,376		—		—
Development costs		41,111		16,055		4,591

Total	$	45,468	$	19,238	$	15,079

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2006, 2005 and 2004

Results of Operations

Information about the Company’s results of operations for oil and gas producing activities by geographic operating segment is presented in Note R of the accompanying Notes to Consolidated Financial Statements.

Reserve Quantity Information

The estimates of the Company’s proved oil and gas reserves as of December 31, 2006, 2005 and 2004, which are located in the United States, Argentina, Canada, South Africa and Tunisia, were based on evaluations prepared by the Company’s engineers and audited by independent petroleum engineers with respect to the Company’s major properties and prepared by the Company’s engineers with respect to all other properties. Reserves were estimated in accordance with guidelines established by the United States Securities and Exchange Commission and the FASB, which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and cost escalations except by contractual arrangements. The Company reports all reserves held under production sharing arrangements and concessions utilizing the “economic interest” method, which excludes the host country’s share of proved reserves. Estimated quantities for production sharing arrangements reported under the “economic interest” method are subject to fluctuations in the prices of oil and gas and recoverable operating expenses and capital costs. If costs remain stable, reserve quantities attributable to recovery of costs will change inversely to changes in commodity prices. The reserve estimates as of December 31, 2006, 2005 and 2004 utilized respective oil prices of $60.54, $59.62 and $41.96 per Bbl (reflecting adjustments for oil quality), respective NGL prices of $29.82, $36.34 and $29.12 per Bbl, and respective gas prices of $5.13, $6.36 and $4.76 per Mcf (reflecting adjustments for Btu content, gas processing and shrinkage).

Oil and gas reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that proved reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.

The following table provides a rollforward of total proved reserves by geographic area and in total for the years ended December 31, 2006, 2005 and 2004, as well as proved developed reserves by geographic area and in total as of the beginning and end of each respective year. Oil and NGL volumes are expressed in MBbls, gas volumes are expressed in MMcf and total volumes are expressed in thousands of barrels of oil equivalent (“MBOE”).

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2006, 2005 and 2004


	Year Ended December 31,
	2006									2005									2004
																			Oil &
	Oil & NGLs			Gas						Oil & NGLs			Gas						NGLs			Gas
	(MBbls)			(MMcf) (a)			MBOE			(MBbls)			(MMcf) (a)			MBOE			(MBbls)			(MMcf) (a)			MBOE
Total Proved Reserves:
UNITED STATES
Balance, January 1		385,771			2,750,856			844,247			363,257			3,000,335			863,313			362,751			1,553,976			621,747
Revisions of previous estimates		(7,467	)		(10,664	)		(9,244	)		(5,471	)		(141,473	)		(29,049	)		4,671			25,764			8,965
Purchases of minerals-in-place		41,825			52,308			50,543			65,800			83,179			79,663			11,803			1,571,053			273,646
Extensions and discoveries		11,948			136,712			34,733			225			103,616			17,494			1,017			56,690			10,465
Production (b)		(14,091	)		(134,445	)		(36,499	)		(16,311	)		(197,391	)		(49,210	)		(16,974	)		(200,598	)		(50,407	)
Sales of minerals-in-place		(11,261	)		(108,806	)		(29,395	)		(21,729	)		(97,410	)		(37,964	)		(11	)		(6,550	)		(1,103	)

Balance, December 31		406,725			2,685,961			854,385			385,771			2,750,856			844,247			363,257			3,000,335			863,313
ARGENTINA
Balance, January 1		34,024			404,323			101,411			33,168			560,374			126,564			33,469			549,856			125,112
Revisions of previous estimates		(306	)		(2,043	)		(646	)		2,060			(137,640	)		(20,881	)		(3,040	)		(61,483	)		(13,287	)
Extensions and discoveries		135			4,576			898			2,334			31,606			7,602			6,428			116,526			25,849
Production (b)		(1,072	)		(16,025	)		(3,743	)		(3,538	)		(50,017	)		(11,874	)		(3,689	)		(44,525	)		(11,110	)
Sales of minerals-in-place		(32,781	)		(390,831	)		(97,920	)		—			—			—			—			—			—

Balance, December 31		—			—			—			34,024			404,323			101,411			33,168			560,374			126,564
CANADA
Balance, January 1		2,423			130,514			24,175			4,095			119,869			24,073			2,407			93,829			18,045
Revisions of previous estimates		(159	)		(7,953	)		(1,485	)		434			15,887			3,082			710			8,580			2,140
Purchases of minerals-in-place		—			—			—			—			292			49			823			22,127			4,511
Extensions and discoveries		217			66,801			11,351			652			55,130			9,840			541			10,656			2,317
Production (b)		(282	)		(15,853	)		(2,924	)		(311	)		(15,665	)		(2,922	)		(386	)		(15,323	)		(2,940	)
Sales of minerals-in-place		—			—			—			(2,447	)		(44,999	)		(9,947	)		—			—			—

Balance, December 31		2,199			173,509			31,117			2,423			130,514			24,175			4,095			119,869			24,073
SOUTH AFRICA
Balance, January 1		3,055			60,395			13,121			3,419			—			3,419			5,546			—			5,546
Revisions of previous estimates		1,521			116			1,541			694			—			694			1,302			—			1,302
Extensions and discoveries		—			—			—			1,347			60,395			11,413			—			—			—
Production (b)		(1,506	)		—			(1,506	)		(2,405	)		—			(2,405	)		(3,429	)		—			(3,429	)

Balance, December 31		3,070			60,511			13,156			3,055			60,395			13,121			3,419			—			3,419
TUNISIA
Balance, January 1		3,769			—			3,769			4,852			—			4,852			2,018			—			2,018
Revisions of previous estimates		1,579			59			1,588			(510	)		—			(510	)		3,177			—			3,177
Extensions and discoveries		500			8,223			1,870			696			—			696			502			—			502
Production (b)		(871	)		(436	)		(943	)		(1,269	)		—			(1,269	)		(845	)		—			(845	)

Balance, December 31		4,977			7,846			6,284			3,769			—			3,769			4,852			—			4,852
GABON
Balance, January 1		—			—			—			—			—			—			16,590			—			16,590
Revisions of previous estimates		—			—			—			—			—			—			(16,590	)		—			(16,590	)

Balance, December 31		—			—			—			—			—			—			—			—			—
TOTAL
Balance, January 1		429,042			3,346,088			986,723			408,791			3,680,578			1,022,221			422,781			2,197,661			789,058
Revisions of previous estimates		(4,832	)		(20,485	)		(8,246	)		(2,793	)		(263,226	)		(46,664	)		(9,770	)		(27,139	)		(14,293	)
Purchases of minerals-in-place		41,825			52,308			50,543			65,800			83,471			79,712			12,626			1,593,180			278,157
Extensions and discoveries		12,800			216,312			48,852			5,254			250,747			47,045			8,488			183,872			39,133
Production (b)		(17,822	)		(166,759	)		(45,615	)		(23,834	)		(263,073	)		(67,680	)		(25,323	)		(260,446	)		(68,731	)
Sales of minerals-in-place		(44,042	)		(499,637	)		(127,315	)		(24,176	)		(142,409	)		(47,911	)		(11	)		(6,550	)		(1,103	)

Balance, December 31		416,971			2,927,827			904,942			429,042			3,346,088			986,723			408,791			3,680,578			1,022,221


(a)		The proved gas reserves as of December 31, 2006, 2005 and 2004 include 316,528 MMcf, 306,303 MMcf and 271,667 MMcf, respectively, of gas that will be produced and utilized as field fuel. Field fuel is gas consumed to operate field equipment (primarily compressors) prior to the gas being delivered to a sales point.

(b)		Production for 2006, 2005 and 2004 includes approximately 17,364 MMcf, 14,452 MMcf and 9,605 MMcf of field fuel, respectively. Also, for 2006, 2005 and 2004, production includes 9,735 MBOE, 31,195 MBOE and 36,076 MBOE of production associated with discontinued operations. See Note V for additional information.

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2006, 2005 and 2004


	Year Ended December 31,
	2006						2005						2004
	Oil &						Oil &						Oil &
	NGLs		Gas				NGLs		Gas				NGLs		Gas
	(MBbls)		(MMcf)		MBOE		(MBbls)		(MMcf)		MBOE		(MBbls)		(MMcf)		MBOE
Proved Developed Reserves:
United States		210,680		1,875,866		523,324		223,749		2,045,275		564,628		209,349		1,202,264		409,727
Argentina		20,844		282,815		67,980		20,565		320,616		74,001		21,149		352,660		79,926
Canada		2,202		99,025		18,706		3,849		107,547		21,773		2,312		86,500		16,728
South Africa		1,708		—		1,708		3,419		—		3,419		5,546		—		5,546
Tunisia		3,769		—		3,769		4,852		—		4,852		1,271		—		1,271

Balance, January 1		239,203		2,257,706		615,487		256,434		2,473,438		668,673		239,627		1,641,424		513,198


United States		211,814		1,805,974		512,809		210,680		1,875,866		523,324		223,749		2,045,275		564,628
Argentina		—		—		—		20,844		282,815		67,980		20,565		320,616		74,001
Canada		2,053		117,672		21,665		2,202		99,025		18,706		3,849		107,547		21,773
South Africa		1,822		—		1,822		1,708		—		1,708		3,419		—		3,419
Tunisia		4,977		7,846		6,285		3,769		—		3,769		4,852		—		4,852

Balance, December 31		220,666		1,931,492		542,581		239,203		2,257,706		615,487		256,434		2,473,438		668,673

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows is computed by applying year-end prices of oil and gas (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and gas reserves less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, discounted using a rate of ten percent per year to reflect the estimated timing of the future cash flows. Future income taxes are calculated by comparing undiscounted future cash flows to the tax basis of oil and gas properties plus available carryforwards and credits and applying the current tax rates to the difference. The discounted future cash flow estimates do not include the effects of the Company’s commodity hedging contracts. Utilizing December 31, 2006 commodity prices held constant over each hedge contract’s term, the net present value of the Company’s hedge obligations, less associated estimated income taxes and discounted at ten percent, was a liability of approximately $82 million at December 31, 2006.

Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of oil and gas properties. Estimates of fair value should also consider probable reserves, anticipated future oil and gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise.

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2006, 2005 and 2004

The following tables provide the standardized measure of discounted future cash flows by geographic area and in total for the years ended December 31, 2006, 2005 and 2004, as well as a roll forward in total for each respective year:


	December 31,
	2006			2005			2004
	(in thousands)
UNITED STATES
Oil and gas producing activities:
Future cash inflows	$	32,162,975		$	37,171,750		$	28,373,520
Future production costs		(10,605,170	)		(10,911,204	)		(8,232,530	)
Future development costs		(3,746,920	)		(2,757,072	)		(1,829,937	)
Future income tax expense		(5,695,788	)		(7,552,644	)		(5,612,935	)

		12,115,097			15,950,830			12,698,118
10% annual discount factor		(7,925,926	)		(9,872,066	)		(7,116,815	)

Standardized measure of discounted future cash flows	$	4,189,171		$	6,078,764		$	5,581,303

ARGENTINA
Oil and gas producing activities:
Future cash inflows	$	—		$	2,256,468		$	1,747,737
Future production costs		—			(366,362	)		(289,742	)
Future development costs		—			(353,182	)		(234,309	)
Future income tax expense		—			(282,661	)		(221,733	)

		—			1,254,263			1,001,953
10% annual discount factor		—			(446,366	)		(354,661	)

Standardized measure of discounted future cash flows	$	—		$	807,897		$	647,292

CANADA
Oil and gas producing activities:
Future cash inflows	$	1,054,264		$	1,062,258		$	889,940
Future production costs		(399,248	)		(404,891	)		(286,197	)
Future development costs		(115,721	)		(46,312	)		(40,023	)
Future income tax expense		(69,693	)		(166,333	)		(96,431	)

		469,602			444,722			467,289
10% annual discount factor		(200,313	)		(190,655	)		(190,822	)

Standardized measure of discounted future cash flows	$	269,289		$	254,067		$	276,467

SOUTH AFRICA
Oil and gas producing activities:
Future cash inflows	$	509,081		$	503,499		$	140,059
Future production costs		(82,989	)		(56,987	)		(61,845	)
Future development costs		(165,318	)		(248,005	)		(13,252	)
Future income tax expense		(58,870	)		(18,510	)		—

		201,904			179,997			64,962
10% annual discount factor		(58,182	)		(70,453	)		(2,150	)

Standardized measure of discounted future cash flows	$	143,722		$	109,544		$	62,812

TUNISIA
Oil and gas producing activities:
Future cash inflows	$	329,773		$	214,982		$	193,032
Future production costs		(47,116	)		(9,164	)		(13,536	)
Future development costs		(16,265	)		(2,700	)		(1,245	)
Future income tax expense		(148,361	)		(121,675	)		(81,680	)

		118,031			81,443			96,571
10% annual discount factor		(31,224	)		(34,818	)		(21,370	)

Standardized measure of discounted future cash flows	$	86,807		$	46,625		$	75,201

TOTAL
Oil and gas producing activities:
Future cash inflows	$	34,056,093		$	41,208,957		$	31,344,288
Future production costs		(11,134,523	)		(11,748,608	)		(8,883,850	)
Future development costs (a)		(4,044,224	)		(3,407,271	)		(2,118,766	)
Future income tax expense		(5,972,712	)		(8,141,823	)		(6,012,779	)

		12,904,634			17,911,255			14,328,893
10% annual discount factor		(8,215,645	)		(10,614,358	)		(7,685,818	)

Standardized measure of discounted future cash flows	$	4,688,989		$	7,296,897		$	6,643,075


(a)		Includes $324.1 million, $357.5 million and $258.1 million of undiscounted future asset retirement expenditures estimated as of December 31, 2006, 2005 and 2004, respectively, using current estimates of future abandonment costs. See Note L for corresponding information regarding the Company’s discounted asset retirement obligations.

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2006, 2005 and 2004

Changes in Standardized Measure of Discounted Future Net Cash Flows


	Year Ended December 31,
	2006			2005			2004
	(in thousands)
Oil and gas sales, net of production costs	$	(1,516,503	)	$	(2,227,267	)	$	(1,719,990	)
Net changes in prices and production costs		(1,921,270	)		3,932,683			2,082,706
Extensions and discoveries		413,200			459,251			302,794
Development costs incurred during the period		672,572			446,978			249,890
Sales of minerals-in-place		(1,926,423	)		(1,492,864	)		(14,222	)
Purchases of minerals-in-place		280,475			645,315			2,058,195
Revisions of estimated future development costs		(1,041,343	)		(907,229	)		(447,828	)
Revisions of previous quantity estimates		(38,837	)		(595,873	)		140,950
Accretion of discount		895,455			908,047			644,238
Changes in production rates, timing and other		486,328			78,880			(167,400	)

Change in present value of future net revenues		(3,696,346	)		1,247,921			3,129,333
Net change in present value of future income taxes		1,088,438			(594,099	)		(1,069,511	)

		(2,607,908	)		653,822			2,059,822
Balance, beginning of year		7,296,897			6,643,075			4,583,253

Balance, end of year	$	4,688,989		$	7,296,897		$	6,643,075

Selected Quarterly Financial Results

The following table provides selected quarterly financial results for the nine months ended September 30, 2007 and years ended December 31, 2006 and 2005:


	Quarter
	First			Second			Third		Fourth
	(in thousands, except per share data)
Nine months ended September 30, 2007:
Oil and gas revenues:
As reported	$	391,918		$	458,032		$	458,898
Less discontinued operations		(38,336	)		(38,240	)		—

Adjusted	$	353,582		$	419,792		$	458,898


Total revenues:
As reported	$	406,094		$	483,920		$	490,447
Less discontinued operations		(38,775	)		(39,223	)		—

Adjusted	$	367,319		$	444,697		$	490,447


Total costs and expenses:
As reported	$	359,880		$	432,731		$	336,480
Less discontinued operations		(35,209	)		(41,226	)		—

Adjusted	$	324,671		$	391,505		$	336,480


Net income	$	29,593		$	36,480		$	101,927
Net income per share:
Basic	$	0.24		$	0.30		$	0.85
Diluted	$	0.24		$	0.30		$	0.84

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2006, 2005 and 2004


	Quarter
	First			Second			Third			Fourth
	(in thousands, except per share data)
Year ended December 31, 2006:
Oil and gas revenues:
As reported	$	379,468		$	407,570		$	418,106		$	376,905
Less discontinued operations		(28,362	)		(34,154	)		(33,994	)		(26,599	)

Adjusted	$	351,106		$	373,416		$	384,112		$	350,306


Total revenues:
As reported	$	396,506		$	413,908		$	432,627		$	389,840
Less discontinued operations		(34,547	)		(35,340	)		(34,934	)		(27,189	)

Adjusted	$	361,959		$	378,568		$	397,693		$	362,651


Total costs and expenses:
As reported	$	376,756		$	297,815		$	312,031		$	337,291
Less discontinued operations		(26,732	)		(27,759	)		(32,106	)		(27,663	)

Adjusted	$	350,024		$	270,056		$	279,925		$	309,628


Net income	$	543,207		$	88,039		$	80,799		$	27,686
Net income per share:
Basic	$	4.28		$	0.70		$	0.65		$	0.23
Diluted	$	4.28		$	0.69		$	0.64		$	0.22
Year ended December 31, 2005:
Oil and gas revenues:
As reported	$	520,312		$	544,600		$	558,382		$	622,207
Less discontinued operations		(216,975	)		(247,823	)		(198,274	)		(243,546	)

Adjusted	$	303,337		$	296,777		$	360,108		$	378,661


Total revenues:
As reported	$	550,866		$	592,644		$	568,236		$	691,301
Less discontinued operations		(244,011	)		(284,577	)		(201,606	)		(247,447	)

Adjusted	$	306,855		$	308,067		$	366,630		$	443,854


Total costs and expenses:
As reported	$	414,346		$	387,125		$	421,166		$	452,851
Less discontinued operations		(156,712	)		(151,781	)		(131,163	)		(143,962	)

Adjusted	$	257,634		$	235,344		$	290,003		$	308,889


Net income	$	84,657		$	185,559		$	123,573		$	140,777
Net income per share:
Basic	$	0.59		$	1.32		$	0.90		$	1.11
Diluted	$	0.58		$	1.28		$	0.88		$	1.08

In November 2007, the Company sold its Canadian assets. During March and April 2006, the Company sold all of its interests in certain oil and gas properties in the deepwater Gulf of Mexico and its Argentine assets, respectively. During May and August 2005, the Company sold certain Canadian and United States Gulf of Mexico shelf assets, respectively. These divestitures qualified as discontinued operations pursuant to SFAS 144. In accordance with SFAS 144, the Company reclassified the results of operations and gains on the sales of the divested assets from continuing operations to discontinued operations in the Company’s consolidated statements of operations. See Note V of Notes to Consolidated Financial Statements for additional information regarding these divestitures that gave rise to the adjustments in the tables above.


	Page
Consolidated Financial Statements of Pioneer Natural Resources Company:

Report of Independent Registered Public Accounting Firm		2
Consolidated Balance Sheets as of December 31, 2006 and 2005		3
Consolidated Statements of Operations for the Years Ended December 31, 2006, 2005 and 2004		4
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2006, 2005 and 2004		5
Consolidated Statements of Cash Flows for the Years Ended December 31, 2006, 2005 and 2004		7
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2006, 2005 and 2004		8
Notes to Consolidated Financial Statements		9
Unaudited Supplementary Information		51