8-K

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): January 14, 2008

PIONEER NATURAL RESOURCES COMPANY

(Exact name of registrant as specified in its charter)

Delaware	1-13245	75-2702753
(State or other jurisdiction of incorporation)	(Commission File Number)	(I.R.S. Employer Identification Number)

5205 N. O’Connor Blvd
Suite 200
Irving, Texas
(Address of principal
executive offices) 75039
(Zip code)

Registrant’s telephone number, including area code: (972) 444-9001

Not applicable
(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the Registrant under any of the following provisions:

o   Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o   Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o   Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o  Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

PIONEER NATURAL RESOURCES COMPANY

TABLE OF CONTENTS

	Page
Item 8.01. Other Events		3
Item 9.01. Financial Statements and Exhibits
(d) Exhibits		4
Signature		5
Exhibit Index
Form of Severance Agreement
Form of Change in Control Agreement
Form of Indemnification Agreement
First Amendment to Amended and Restated Credit Agreement
Consent of Ernst & Young LLP
Consent of Netherland, Sewell & Associates, Inc.
Selected Financial Data
Management's Discussion
Report of Independent Registered Public Accounting Firm

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Item 8.01. Other Events.

     Pioneer Natural Resources Company is filing this Current Report on Form 8-K for the purpose of, among other things, incorporating the contents of this report including the exhibits in a registration statement that we intend to file with the Securities and Exchange Commission on the date hereof. All references to “we,” “us,” “our” or “Company” in this report mean Pioneer Natural Resources Company and its consolidated subsidiaries, unless we indicate otherwise.

Financial Data Reflecting Discontinued Operations

     We are filing as exhibits to this report our (a) selected consolidated financial data as of and for each of the five years ended December 31, 2006, (b) management’s discussion and analysis of financial condition and results of operations as of and for each of the three years ended December 31, 2006 and (c) consolidated balance sheets 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, and related notes including “Subsequent Events (Unaudited)”, all of which reflect the reclassification of the results of operations from our Canadian assets as discontinued operations, rather than as a component of continuing operations.

Agreements with Recently Named Executive Officers

     On November 2, 2007, we designated Mr. Jay P. Still, our Executive Vice President, Domestic Operations, and Mr. David McManus, our Executive Vice President, International Operations, as executive officers of the Company. In connection with their service, we are parties with them to severance agreements, change in control agreements and indemnification agreements, the forms of which are filed as exhibits to this report and incorporated by reference.

Amendment to Credit Facility

     In November 2007, we entered into an amendment to our Amended and Restated 5-Year Revolving Credit Agreement. The Credit Agreement contains certain financial covenants, one of which requires us to maintain a ratio of the net present value of projected future cash flows from our proved reserves to total debt of at least 1.75 to 1.0 until we achieve an investment grade rating by Moody’s Investors Service, Inc. or Standard & Poors Ratings Group, Inc. Pursuant to the amendment, we are required to deliver certain reserve information quarterly, rather than annually, and the determination of compliance with this covenant will be made by reference to the most recently delivered reserve information. We have filed a copy of the amendment as an exhibit to this report and this description of the amendment is qualified in its entirety by reference to the exhibit, which we incorporate by reference.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

     The information in this report contains forward-looking statements that involve risks and uncertainties. When used in this document, the words “believes,” “plans,” “expects,” “anticipates,” “intends,” “continue,” “may,” “will,” “could,” “should,” “future,” “potential,” “estimate,” or the negative of such terms and similar expressions as they relate to us are intended to identify forward-looking statements. Forward-looking statements and our business prospects are subject to a number of risks and uncertainties that may cause our actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties include, among other things, volatility of commodity prices, product supply and demand, competition, the ability to obtain environmental and other permits and the timing thereof, other government regulation or action, third party approvals, international operations and associated international political and economic instability, litigation, the costs and results of drilling and operations, availability of drilling equipment, our ability to

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replace reserves, implement our business plans (including our plan to repurchase stock and our plan to form Pioneer Southwest Energy Partners L.P. and offer securities representing interests therein) or complete our development projects as scheduled, access to and cost of capital, the assumptions underlying production forecasts, uncertainties about estimates of reserves, quality of technical data, environmental and weather risks, and acts of war or terrorism. These and other risks are described in our 10-K and 10-Q Reports and other filings with the Securities and Exchange Commission. We undertake no duty to publicly update these statements except as required by law.

Item 9.01. Financial Statements and Exhibits.

     (d) Exhibits.

10.1	Form of Severance Agreement dated December 12, 2007, between the Company and each of Jay P. Still and David McManus.
10.2	Form of Change in Control Agreement dated September 10, 2005, between the Company and each of Jay P. Still and David McManus.
10.3	Form of Indemnification Agreement dated November 15, 2006, between the Company and each of Jay P. Still and David McManus.
10.4	First Amendment to Amended and Restated Credit Agreement dated as of November 20, 2007 among the Company, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and certain other lenders.
23.1	Consent of Ernst & Young LLP.
23.2	Consent of Netherland, Sewell & Associates, Inc.
99.1	Selected Financial Data as of and for each of the five years ended December 31, 2006.
99.2	Management’s Discussion and Analysis of Financial Condition and Results of Operations as of and for each of the three years ended December 31, 2006.
99.3	Report of Independent Registered Public Accounting Firm and consolidated balance sheets 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, and related notes.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

PIONEER NATURAL RESOURCES COMPANY
By:	/s/ Darin G. Holderness
	Darin G. Holderness
	Vice President and Chief Accounting Officer

     Dated: January 14, 2008

5

PIONEER NATURAL RESOURCES COMPANY

EXHIBIT INDEX

Exhibit No.	Description
10.1(a)	Form of Severance Agreement dated December 12, 2007, between the Company and each of Jay P. Still and David McManus.
10.2(a)	Form of Change in Control Agreement dated September 10, 2005, between the Company and each of Jay P. Still and David McManus.
10.3(a)	Form of Indemnification Agreement dated November 15, 2006, between the Company and each of Jay P. Still and David McManus.
10.4(a)	First Amendment to Amended and Restated Credit Agreement dated as of November 20, 2007 among the Company, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and certain other lenders.
23.1(a)	Consent of Ernst & Young LLP.
23.2(a)	Consent of Netherland, Sewell & Associates, Inc.
99.1(a)	Selected Financial Data as of and for each of the five years ended December 31, 2006.
99.2(a)	Management’s Discussion and Analysis of Financial Condition and Results of Operations as of and for each of the three years ended December 31, 2006.
99.3(a)	Report of Independent Registered Public Accounting Firm and consolidated balance sheets 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, and related notes.

(a) Filed herewith.

EX-10.1

Exhibit 10.1

PIONEER NATURAL RESOURCES COMPANY
SEVERANCE AGREEMENT

     This Severance Agreement (“Agreement”) is entered into, as of December 12, 2007, among Pioneer Natural Resources Company, a Delaware corporation (“Parent”), Pioneer Natural Resources USA, Inc. (“Employer”) and                      (“Employee”). As used henceforth in this Agreement, the term “Company” shall be deemed to include Parent and its direct or indirect majority-owned subsidiaries.

Recitals

     Parent and Employer acknowledge that Employee possesses skills and knowledge instrumental to the successful conduct of the Company’s business. Parent and Employer are willing to enter into this Agreement with Employee in order to better ensure themselves of access to the continued services of Employee.

     NOW, THEREFORE, for and in consideration of the mutual covenants and agreements set forth herein and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties to this Agreement hereby agree as follows:

     1. Term. The term of this Agreement shall commence on the date indicated above (the “Effective Date”) and end on September 30, 2008. Thereafter, on the date on which the term of this Agreement (as it may be extended from time to time under this paragraph 1) would otherwise expire, so long as Employee is still an employee of the Company on such date, such term will be automatically extended for 12 months, unless Parent shall have provided written notice to Employee at least 6 months before the date that the term would otherwise expire that it does not want the term to be extended. Parent may deliver a conditional notice of non-renewal that will be effective only if Employee does not agree, within the time period specified by Parent, to any amendment or modification of this Agreement that Parent shall request be executed as a condition to allowing the term hereof to be extended. Notwithstanding the foregoing, so long as Employee is in the employ of the Company on the date on which a Potential Change in Control occurs, the term of this Agreement shall continue in effect following such Potential Change in Control until the date on which the term of any separate agreement between Parent and Employer and Employee relating to the provision of severance and other benefits after a Change in Control (the “Change in Control Agreement”) expires; provided, however, that upon the occurrence of such a Change in Control, this Agreement shall terminate and such Change in Control Agreement shall govern the rights of Employee to, or obligations of Parent and Employer to provide, severance and other benefits to Employee.

     2. Certain Definitions. As used in this Agreement, the following terms shall have the meanings set forth below:

     (a) “Accrued Obligations” shall mean any vested amounts or benefits owing to Employee under any of the Company’s employee benefit plans and programs in which Employee has participated, including any compensation previously deferred by Employee (together with any accrued earnings thereon) and not yet paid.

     (b) “Across-the-Board Salary Reduction” shall mean a reduction in Employee’s Base Salary that is a part of, and is at a level consistent with, a reduction in the base salaries paid to substantially all employees of Company who are parties to an agreement with the Company that would provide them with severance and other

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termination benefits in the event of an involuntary termination of employment by the Company without cause prior to the occurrence of a Change in Control.

     (c) “Base Salary” shall mean Employee’s annualized base salary at the rate in effect at the relevant date or event as reflected in Employer’s regular payroll records.

     (d) “Change in Control” shall mean an event that constitutes a “change in control” as defined in Parent’s Long-Term Incentive Plan (the “LTIP”), as in effect on the Effective Date or as subsequently amended from time to time (except that any amendment to such definition adopted (1) on or within 180 days prior to a Change in Control or Potential Change in Control or (2) on or after a Potential Change in Control shall not be applied in determining the definition of such term under this Agreement unless such amendment is favorable to Employee).

     (e) “Date of Termination” shall mean

     (1) In the case of a termination for which a Notice of Termination is required, the date of receipt of such Notice of Termination or, if later, the date specified therein; and

     (2) In all other cases, the actual date on which Employee’s employment terminates.

     (f) “Disability” shall mean Employee’s physical or mental impairment or incapacity of sufficient severity such that

     (1) In the opinion of a qualified physician selected by Parent, after taking into account all reasonable accommodations that the Company has made or could make, Employee is unable to continue to perform Employee’s duties and responsibilities as an employee of the Company; or

     (2) Employee’s condition entitles Employee to long-term disability benefits under any employee benefit plan maintained by the Company in which Employee participates.

For purposes of subparagraph (f)(1), Employee agrees to provide such access to Employee’s medical records and to submit to such physical examinations or medical tests as, in the opinion of the physician selected by Parent, is reasonably necessary to make the determination required as to Employee’s ability to perform Employee’s duties and responsibilities. If such physician is unable to render an opinion as to Employee’s ability to perform such duties and responsibilities due to Employee’s failure to provide such access to any of Employee’s medical records or to submit to any such examination or test (unless, in the opinion of such physician such failure is a direct result of Employee’s physical or mental impairment), any failure by Employee to perform Employee’s duties and responsibilities shall be deemed not to be on account of Employee’s physical or mental impairment or incapacity.

     (g) “Earned Salary” shall mean the Base Salary earned by Employee, but unpaid, through Employee’s Date of Termination.

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     (h) “Excessive Salary Reduction” shall mean

     (1) A reduction in Employee’s Base Salary that is not an Across-the-Board Salary Reduction and that, when combined with the net effect of all prior reductions in Employee’s Base Salary (other than prior reductions that were Across-the-Board Salary Reductions), results in the Base Salary then payable to Employee being less than 80% of the highest Base Salary which Employee has ever received from the Company (as reflected in Employer’s regular payroll records); or

     (2) A reduction in Employee’s Base Salary (whether or not an Across-the-Board Salary Reduction) that, when combined with the net effect of all prior reductions in Employee’s Base Salary (whether or not Across-the-Board Salary Reductions), results in the Base Salary payable to Employee being less than 65% of the highest Base Salary which Employee has ever received from the Company (as reflected in Employer’s regular payroll records).

     (i) “Management Committee” shall mean the group of officers of Parent, as the same may be constituted from time to time during the term of this Agreement that is primarily responsible for establishing strategy, overall policy and the business plan for Parent, and approving all material business decisions affecting Parent.

     (j) “Normal Retirement Date” shall mean the date on which Employee attains age 60.

     (k) “Notice of Termination” shall mean a written notice given by the party effecting the termination of Employee’s employment which shall

     (1) Indicate the specific termination provision in this Agreement relied upon;

     (2) Set forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of Employee’s employment under the provision so indicated; and

     (3) If the Date of Termination is other than the date of receipt of such notice, specify the Date of Termination (which date shall be not more than 30 days after the giving of such notice).

The failure by Employee or Parent or Employer to set forth in the Notice of Termination any fact or circumstance which contributes to a showing of Termination for Good Reason or Termination for Cause shall not waive any right of such party hereunder or preclude such party from asserting such fact or circumstance in enforcing such party’s rights hereunder. In the event that a Potential Change in Control has occurred, any Notice of Termination by Parent or Employer intended to effect a Termination for Cause must be given with 45 days of Parent or Employer’s having actual knowledge of the events giving rise to Termination for Cause.

     (l) “Potential Change in Control” shall mean the occurrence of any of the following events:

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     (1) Any person or group shall have announced publicly an intention to effect a Change in Control, or commenced any action (such as the commencement of a tender offer for Parent’s common stock or the solicitation of proxies for the election of any of Parent’s directors) that, if successful, could reasonably be expected to result in the occurrence of a Change in Control;

     (2) Parent enters into an agreement the consummation of which would constitute a Change in Control; or

     (3) Any other event occurs which the Board of Directors of Parent (the “Board”) declares to be a Potential Change in Control.

     (m) “Separation Payment” shall mean any lump sum payment in excess of Earned Salary and Accrued Obligations payable to Employee under this Agreement.

     (n) “Termination for Cause” shall mean a termination of Employee’s employment by the Company following the occurrence of any of the following:

     (1) Employee’s continued failure to substantially perform Employee’s duties and responsibilities (other than any such failure resulting from Employee’s physical or mental impairment or incapacity);

     (2) Employee’s engaging in fraud or other misconduct that is injurious to the Company, monetarily or otherwise;

     (3) Employee’s engaging in insubordination;

     (4) Employee’s violation of, or failure to comply with, any material written policy, guideline, rule or regulation of the Company;

     (5) Employee’s conviction of (or plea of guilty or nolo contendere to a charge of) any felony, or any crime or misdemeanor involving moral turpitude or financial misconduct;

     (6) Employee’s failure, following a written request from Parent, reasonably to cooperate (including, without limitation, the refusal by Employee to be interviewed or deposed, or to give testimony) in connection with any investigation or proceeding, whether internal or external (including, without limitation, by any governmental or quasi-governmental agency) into the business practices or operations of the Company; or

     (7) A material violation by Employee of the provisions of paragraphs 5 or 6 of this Agreement.

     (o) “Termination for Good Reason” shall mean a termination of Employee’s employment by Employee within 30 days after

     (1) the earlier of receipt by Employee of (i) written notice of an Excessive Salary Reduction and (ii) Employee’s first paycheck that reflects an Excessive Salary Reduction; or

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     (2) if Employee is an officer of Parent or Employer, the demotion of Employee to either a non-officer position or an officer position with such entity that is junior to the officer position held by Employee immediately prior to such demotion, provided, however, that if Employee is a member of the Management Committee at any time during this Agreement, removal from, or exclusion from regular participation as a member of, the Management Committee shall be deemed to be a demotion to a junior officer position on the date Employee receives written notice from the Company of such removal or exclusion or, if no such notice is given, the date Employee has actual knowledge of such removal or exclusion.

     3. Termination of Employment, Relocation.

     (a) Right to Terminate. Nothing in this Agreement shall be construed in any way to limit the right of the Company to terminate Employee’s employment, with or without cause, or for Employee to terminate Employee’s employment with the Company, with or without reason; provided, however, that the Company and Employee must nonetheless comply with any duty or obligation such party has at law or under any agreement (including paragraphs 5 and 6 of this Agreement) between the parties.

     (b) Termination due to Death or Disability. Employee’s employment with the Company shall be terminated upon Employee’s death. By written notice to the other party, either the Company or Employee may terminate Employee’s employment due to Disability.

     (c) Relocation. Nothing in this Agreement shall be construed in any way to limit the right of the Company to require Employee to perform Employee’s services on behalf of the Company at a different location or locations than the one at which Employee was performing Employee’s services immediately prior to the date hereof, or to require the Company to pay or provide any benefits to Employee on account of such relocation, other than to the extent benefits would be payable to Employee under the Company’s applicable relocation policy as in effect at the relevant time.

     4. Amounts Payable Upon Termination of Employment. The following provisions shall apply to any termination of Employee’s employment:

     (a) Death, Disability or Normal Retirement. In the event that Employee’s employment terminates due to Employee’s death or Disability (regardless of whether such Disability termination is initiated by Employee or the Company), or due to the voluntary retirement by Employee (which is not a Termination for Good Reason) at or after attaining Employee’s Normal Retirement Date, Parent or Employer shall pay Employee (or, if applicable, Employee’s beneficiaries or legal representative(s)):

     (1) The Earned Salary, as soon as practicable (but not more than 10 days) following Employee’s Date of Termination;

     (2) The Accrued Obligations, in accordance with applicable law and the provisions of any applicable plan, program, policy or practice; and

     (3) A Separation Payment in an amount equal to Employee’s Base Salary, which shall be paid, in all cases other than voluntary retirement on or

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after Normal Retirement Date, within 10 days following Employee’s Date of Termination, and, in the case of voluntary retirement on or after Normal Retirement Date, 6 months and 1 day after Employee’s Date of Termination.

     (b) Cause and Voluntary Termination. If Employee’s employment is terminated by the Company in a Termination for Cause or voluntarily by Employee (other than in a Termination for Good Reason or at or after Normal Retirement Date), Parent or Employer shall pay Employee

     (1) The Earned Salary, as soon as practicable (but not more than 10 days) following Employee’s Date of Termination; and

     (2) The Accrued Obligations, in accordance with applicable law and the provisions of any applicable plan, program, policy or practice.

     (c) Termination for Good Reason or Not for Cause. If Employee terminates Employee’s employment in a Termination for Good Reason, or the Company terminates Employee’s employment for any reason other than those described in paragraphs 4(a) and (b) above, Parent or Employer shall pay or shall provide to Employee the following benefits and compensation:

     (1) The Earned Salary, as soon as practicable (but not more than 10 days) following Employee’s Date of Termination;

     (2) The Accrued Obligations, in accordance with applicable law and the provisions of any applicable plan, program, policy or practice;

     (3) A Separation Payment, as soon as practicable (but not more than 10 days) following the expiration of the revocation period stated in the General Release Agreement described in subparagraph 4(d) below, in an amount equal to the sum of

     (i) The Employee’s Base Salary;

     (ii) The product of (A) the monthly amount that, on the Date of Termination, Employee would be required to pay to continue coverage under the Employer’s group health plan(s) (as defined by the Consolidated Omnibus Budget Reconciliation Act of 1985 (“COBRA”) for Employee and Employee’s eligible dependents, if any, covered thereunder immediately prior to the Date of Termination and (B) 18; provided, however, that if Employee is covered under group health plan(s) not subject to COBRA, instead of including this amount as part of the Separation Payment, the Company shall either, at its election, provide Employee and Employee’s covered dependents continued coverage under such medical plan, at its expense, for a number of months equal to the number specified in this subparagraph (c)(3)(ii)(B) or include in the Separation Payment an amount equal to the value of such continued coverage. For the avoidance of doubt, such payment shall not in any way alter, modify or affect Employee’s right to (and the conditions upon which, and the period during which, Employee may elect to) continue coverage for Employee and Employee’s eligible

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dependents under COBRA ; and

     (iii) If the termination of employment is by the Company and if the Date of Termination is less than 30 days after the date Notice of Termination is given, an amount equal to 1/12 (one twelfth) of Employee’s Base Salary, which amount shall be paid in cash on the Date of Termination; and

     (4) Any additional rights that may be afforded to Employee in accordance with the terms of the LTIP with respect to awards made to Employee thereunder which are not vested as of such Date of Termination.

     (d) Separation Payment Contingent on Release. Any Separation Payment payable to Employee under subparagraph 4(c) shall be subject to, and contingent upon, Employee’s execution and non-revocation of a General Release Agreement in favor of the Company in substantially the form and substance as the one attached hereto as Schedule A.

     5. Nonpublic Information.

     (a) Acknowledgement of Access. Employee hereby acknowledges that, in connection with Employee’s employment with the Company, Employee has received, and will continue to receive, various information regarding the Company and its business, operations and affairs. All such information, to the extent not publicly available other than as a result of a disclosure by Employee in violation of this Agreement, is referred to herein as the “Nonpublic Information.”

     (b) Agreement to Keep Confidential. Employee hereby agrees that, from and after the Effective Date and continuing until 3 years following the Employee’s Date of Termination, Employee will keep all Nonpublic Information confidential and will not, without the prior written consent of the Board or the President of Parent, disclose any Nonpublic Information in any manner whatsoever or use any Nonpublic Information other than in connection with the performance of Employee’s services to the Company; provided, however, that the provisions of this subparagraph shall not prevent Employee from

     (1) Disclosing any Nonpublic Information to any other employee of the Company or to any representative or agent of the Company (such as an independent accountant, engineer, attorney or financial advisor) when such disclosure is reasonably necessary or appropriate (in Employee’s judgment) in connection with the performance by Employee of Employee’s duties and responsibilities;

     (2) Disclosing any Nonpublic Information as required by applicable law, rule, regulation or legal process (but only after compliance with the provisions of subparagraph (c) of this paragraph); and

     (3) Disclosing any information about this Agreement and Employee’s other compensation arrangement to Employee’s spouse, financial advisors or attorneys, or to enforce any of Employee’s rights under this Agreement.

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     (c) Commitment to Seek Protective Order. If Employee is requested pursuant to, or required by, applicable law, rule, regulation or legal process to disclose any Nonpublic Information, Employee will notify Parent promptly so that the Company may seek a protective order or other appropriate remedy or, in Parent’s sole discretion, waive compliance with the terms of this subparagraph, and Employee will fully cooperate in any attempt by the Company to obtain any such protective order or other remedy. If no such protective order or other remedy is obtained, or if Parent waives compliance with the terms of this subparagraph, Employee will furnish or disclose only that portion of the Nonpublic Information as is legally required and will exercise all reasonable efforts to obtain reliable assurance that confidential treatment will be accorded the Nonpublic Information that is so disclosed.

     6. Non-Solicitation and Non-Interference.

     (a) Non-Solicitation of Employees. During the period of Employee’s employment with the Company (the “Employment Period") and during the 2 year period following Employee’s Date of Termination (the “Restriction Period"), Employee shall not directly or indirectly induce any employee of the Company to terminate employment with such entity, and shall not directly or indirectly, either individually or as owner, agent, employee, consultant or otherwise, employ or offer employment to any person who is or was employed by the Company unless such person shall have ceased to be employed by the Company for a period of at least 6 months.

     (b) Non-Interference with Business Relationships. During the Employment Period and the Restriction Period, Employee shall not directly or indirectly take any actions which can reasonably be expected to, or are intended to, disrupt or interfere with in any significant way any existing relationship that the Company has with any third party.

     (c) No Disparaging Comments. Except to the extent otherwise required or compelled at law or under subpoena, during the Employment Period and the Restriction Period, Employee shall refrain from making any public derogatory or disparaging comment concerning the Company or any of the current or former officers, directors or employees of the Company. Notwithstanding the immediately preceding sentence, nothing herein shall be construed to preclude Employee from enforcing any rights or claims Employee may have against the Company (or to defend against any claims by the Company) arising under this Agreement.

     (d) Company Property. Promptly following Employee’s Date of Termination, Employee shall return to the Company all property of the Company, and all copies thereof in Employee’s possession or under Employee’s control.

     7. Miscellaneous Provisions.

     (a) No Mitigation, No Offset. Employee shall not be required to mitigate the amount of any payment provided for in this Agreement by seeking other employment or otherwise, and the amount of any payment provided for in this Agreement shall not be reduced by any compensation earned by Employee as the result of employment by another employer after the Date of Termination or otherwise. Except as provided in subparagraph 4(d), Parent’s or Employer’s obligation to make the payments provided

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for in this Agreement and otherwise to perform its obligations hereunder shall not be affected by any circumstances, including, without limitation, any set-off, counterclaim, recoupment, defense or other right which the Company may have against Employee or others whether by reason of the subsequent employment of Employee or otherwise.

     (b) Arbitration. Except to the extent provided in paragraph 7(d), any dispute or controversy arising under or in connection with this Agreement shall be resolved by binding arbitration. The arbitration shall be held in Dallas, Texas and except to the extent inconsistent with this Agreement, shall be conducted in accordance with the Expedited Employment Arbitration Rules of the American Arbitration Association then in effect at the time of the arbitration, and otherwise in accordance with principles which would be applied by a court of law or equity. The arbitrator shall be acceptable to both Parent and Employee. If the parties cannot agree on an acceptable arbitrator, the dispute shall be heard by a panel of three arbitrators, one appointed by each of the parties and the third appointed by the other two arbitrators. The arbitrator may award pre-judgment interest on any amount found to be due under this Agreement at a rate not in excess of the rate that would be payable with respect to judgments rendered in a Texas state court.

     (c) Attorney Fees. All legal fees and other costs incurred by Employee in connection with the resolution of any dispute or controversy under or in connection with this Agreement shall be reimbursed by the Company to Employee if such dispute or controversy is resolved in favor of Employee. The Company shall be responsible for, and shall pay, all legal fees and other costs incurred by the Company in connection with the resolution of any dispute or controversy under or in connection with this Agreement, regardless of whether such dispute or controversy is resolved in favor of the Company or Employee.

     (d) Equitable Relief Available. Employee acknowledges that remedies at law may be inadequate to protect the Company against any actual or threatened breach by Employee of the provisions of paragraphs 5 or 6. Accordingly, without prejudice to any other rights or remedies otherwise available to the Company, Employee agrees that the Company shall have the right to equitable and injunctive relief (without requirement to post any bond) to prevent any breach of the provisions of paragraphs 5 or 6 (without any requirement to post any bond), as well as to such damages or other relief as may be available to the Company by reason of any such breach that does occur.

     (e) Not A Contract of Employment. Employee acknowledges that that this Agreement is not an “employment agreement” or “employment contract” (written or otherwise), as either term is used or defined in, or contemplated by or under

     (1) Parent’s LTIP;

     (2) Any other plan or agreement to which the Company is a party; or

     (3) Applicable statutory, common or case law.

     (f) Notices. Any Notice of Termination or other communication called for by the terms of this Agreement shall be in writing and either delivered personally or by registered or certified mail (postage prepaid and return receipt requested) and shall be

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deemed given when received at the following addresses (or at such other address for a party as shall be specified by like notice):

     (1) If to Parent, Employer or the Company, 5205 North O’Connor Boulevard, Suite 900, Irving, Texas 75039, Attention: General Counsel;

     (2) If to Employee, the address of Employee set forth below Employee’s signature on the signature page of this Agreement.

     (g) Assignment. Employer may assign its duties and obligations hereunder to any other direct or indirect, majority-owned subsidiary of Parent, but shall remain secondarily liable for the performance of this Agreement by Parent and/or any such assignee. Except pursuant to the immediately preceding sentence or an assumption by a successor described in subparagraph (h) of this paragraph, the rights and obligations of Parent and Employer pursuant to this Agreement may not be assigned, in whole or in part, by Parent or Employer to any other person or entity without the express written consent of Employee. The rights and obligations of Employee pursuant to this Agreement may not be assigned, in whole or in part, by Employee to any other person or entity without the express written consent of the Board.

     (h) Successors. Parent shall require any successor (whether direct or indirect) to all or substantially all of the business or assets of Parent (whether by purchase of securities, merger, consolidation, sale of assets or otherwise), to expressly assume and agree to perform the obligations to be performed by the Company under this Agreement in the same manner and to the same extent that the Company would be required to perform if no such succession had taken place. This Agreement shall be binding on, and shall inure to the benefit of, Parent, Employer, the Company, Employee and their respective successors, permitted assigns, personal and legal representatives, executors, administrators, heirs, distributees, devisees and legatees, as applicable.

     (i) Amendments and Waivers. No provision of this Agreement may be amended or otherwise modified, and no right of any party to this Agreement may be waived, unless such amendment, modification or waiver is agreed to in a written instrument signed by Employee and Company. No waiver by either party hereto of, or compliance with, any condition or provision of this Agreement to be performed by the other party hereto shall be deemed a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time.

     (j) Complete Agreement. This Agreement replaces and supersedes all prior agreements, including, but not limited to, the Severance Agreement between Parent and Employee, as in effect immediately prior to the date hereof, among the parties with respect to payments to be made to Employee upon the termination of Employee’s employment prior to a Change in Control, and the provisions of this Agreement constitute the complete understanding and agreement among the parties with respect to such subject matter. Nothing in this subparagraph (j) is intended to, or shall be construed to (1) supercede the Change in Control Agreement or (2) limit Employee’s rights under the LTIP or any other Company plan, program, policy or practice (other than any plan, program, policy or practice primarily providing severance or other termination benefits) generally applicable to similarly situated employees.

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     (k) Governing Law. THIS AGREEMENT IS BEING MADE AND EXECUTED IN, AND IS INTENDED TO BE PERFORMED IN, THE STATE OF TEXAS AND SHALL BE GOVERNED, CONSTRUED, INTERPRETED AND ENFORCED IN ACCORDANCE WITH THE SUBSTANTIVE LAWS OF THE STATE OF TEXAS.

     (l) Counterparts. This Agreement may be executed in several counterparts, each of which shall be deemed to be an original, but all of which together will constitute one and the same agreement.

     (m) Construction. The captions of the paragraphs, subparagraphs and sections of this Agreement have been inserted as a matter of convenience of reference only and shall not affect the meaning or construction of any of the terms or provisions of this Agreement. Unless otherwise specified, references in this Agreement to a “paragraph,” “subparagraph,” “section,” “subsection” or “schedule” shall be considered to be references to the appropriate paragraph, subparagraph, section, subsection or schedule, respectively, of this Agreement. As used in this Agreement, the term “including” shall mean “including, but not limited to.”

     (n) Validity and Severability. If any term or provision of this Agreement is held to be illegal, invalid or unenforceable under the present or future laws effective during the term of this Agreement, (1) such term or provision shall be fully severable, (2) this Agreement shall be construed and enforced as if such term or provision had never comprised a part of this Agreement and (3) the remaining terms and provisions of this Agreement shall remain in full force and effect and shall not be affected by the illegal, invalid or unenforceable term or provision or by its severance from this Agreement. Furthermore, in lieu of such illegal, invalid or unenforceable term or provision, there shall be added automatically as a part of this Agreement, a term or provision as similar to such illegal, invalid or unenforceable term or provision as may be possible and be legal, valid and enforceable.

     (o) Survival. Notwithstanding anything else in this Agreement to the contrary, paragraphs 5, 6 and 7, and, to the extent that any of Parent’s and Employer’s obligations thereunder have not theretofore been satisfied, paragraph 4 of this Agreement shall survive the termination hereof.

     (p) Joint and Several Liability. Parent and Employer (or any assignee of Employer pursuant to paragraph 7(g)) shall each be jointly and severally liable to Employee hereunder with regard to any obligation imposed by the terms hereof on Parent or Employer.

(SIGNATURE PAGE ATTACHED)

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     In Witness Whereof, the parties have executed this Agreement to be effective as of the Effective Date.

PIONEER NATURAL RESOURCES COMPANY
By:
Name:	Mark Berg
Title:	EVP & General Counsel
PIONEER NATURAL RESOURCES USA, INC.
Name:	Mark Berg
Title:	EVP & General Counsel
EMPLOYEE:
Address:

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Schedule A

GENERAL RELEASE AGREEMENT

NOTICE: You should thoroughly review and understand the effect of this General Release Agreement (“Release”) before signing it, and you are advised to discuss this document with your attorney. In accordance with the requirements of the Older Workers Benefit Protection Act (“OWBPA”), you are allowed at least [number] days from the date of your receipt of this document to consider the offer made to you and to return an executed copy of this Release to the Vice President Administration. Additionally, after you have executed this Release, you have seven (7) days to reconsider and revoke your agreement.

GENERAL RELEASE: In consideration of my acceptance of the payments and benefits offered to me under the Pioneer Natural Resources Company Severance Agreement effective [date][, as amended,] (the “Agreement”), I hereby release and discharge Pioneer Natural Resources Company (the “Company”) and its subsidiaries and affiliates, and the officers, directors, employees, agents, predecessors, successors, and assigns of such entities (collectively the “Released Parties) from any and all claims, liabilities, demands, and causes of action, known or unknown, fixed or contingent, which I have or claim against any of them as a result of my employment the termination of my employment or any other act or omission relating to any matter arising on or before the date I sign this Release, including but not limited to claims arising under federal, state, or local laws prohibiting employment discrimination, including, but not limited to, the Age Discrimination in Employment Act, and including, but not limited to, claims arising out of any legal restrictions, contractual or otherwise, on the Company’s right to terminate the employment of its employees (any and all “Potential Claims”), and I do hereby agree not to file a lawsuit, arbitral proceeding or other legal action to assert such Potential Claims. I acknowledge and agree that the Released Parties may recover from me any loss, including attorney’s fees and costs of defending against any such legal action, that they may suffer arising out of my breach of this Release.

I understand that this Release is final and binding, and I agree not to challenge its enforceability other than as permitted by applicable laws. If I do challenge the enforceability of this Release other than with respect to claims of age discrimination, I agree initially to tender to the Company an amount equivalent to the payment and benefits I received pursuant to the Agreement, and invite the Company to retain such amount and agree with me to cancel this Release. In the event the Company accepts this offer, the Company shall retain such amount and this Release will be void. In the event the Company does not accept such offer, the Company shall so notify me, and shall place such amount in an interest-bearing escrow account pending the resolution of any dispute as to whether this Release shall be set aside and/or otherwise be rendered unenforceable. If I am successful in challenging the enforceability of this Release as to age discrimination claims, then, to the extent permitted by law, any damages I may recover for those claims will be offset by any payments and benefits made to me under the Agreement.

I acknowledge and agree that the Company has no legal obligation to provide the payments and/or benefits offered to me under the Agreement, except in exchange for this Release, and my acceptance of such payments and benefits constitutes my agreement to all terms and conditions set forth in this Release.

I acknowledge and agree that, except to the extent otherwise provided in the Agreement or prohibited by law (for example by the OWBPA with respect to claims of age discrimination), this Release constitutes a waiver of any and all Potential Claims that I have or may have against the Released Parties. I further acknowledge and agree that this Release has no effect on any obligations I have assumed under the Agreement with respect to confidentiality, non-solicitation, non-interference and other such matters and that any such obligations shall survive my execution of this Release in accordance with the terms of the Agreement.

I acknowledge that I have [number] days to consider this Release before executing it, although I may execute it any time during this [number] day period (but not before my last day of employment), that I may revoke this Release within 7 days after I execute it by written notice to the Company’s Vice President of Administration and that this Release will not become effective or enforceable, and the payments and benefits offered under the Agreement will not be made or provided, until expiration of this 7 day period without my revocation.

I have carefully read and fully understand all of the provisions of this Release. I further acknowledge that entering into this General Release Agreement is knowing and voluntary on my part, that I have had a reasonable time to deliberate regarding its terms, and that I have had the right to consult with an attorney prior to executing this Release if I so desired.

Date signed:	Signature of
Date signed:	Witness

EX-10.2

Exhibit 10.2

PIONEER NATURAL RESOURCES COMPANY
CHANGE IN CONTROL AGREEMENT

     This Change in Control Agreement (“Agreement”) is entered into, as of August 10, 2005, among Pioneer Natural Resources Company, a Delaware corporation (“Parent”), Pioneer Natural Resources USA, Inc. (“Employer”), and                      (“Employee”). As henceforth used in this Agreement, the term “Company” shall be deemed to include Parent and its direct or indirect majority-owned subsidiaries.

Recitals

     Parent and Employer acknowledge that Employee possesses skills and knowledge instrumental to the successful conduct of the Company’s business. Parent and Employer are willing to enter into this Agreement with Employee in order to better ensure themselves of access to the continued services of Employee both before and after a Change in Control.

     NOW, THEREFORE, for and in consideration of the mutual covenants and agreements set forth herein and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties to this Agreement hereby agree as follows:

     1. Term. The term of this Agreement shall commence on the date indicated above (the “Effective Date”) and end on September 30, 2007. Thereafter, on the date on which the term of this Agreement (as it may be extended from time to time under this paragraph 1) would otherwise expire, so long as Employee is still an employee of the Company on such date, such term will be automatically extended for 12 months, unless Parent shall have provided written notice to Employee at least 6 months before the date that the term would otherwise expire that it does not want the term to be extended. Parent may deliver a conditional notice of non-renewal that will be effective only if Employee does not agree, within the time period specified by Parent, to any amendment or modification of this Agreement that Parent shall request be executed as a condition to allowing the term hereof to be extended. Notwithstanding the foregoing, and regardless of whether Parent has theretofore delivered a notice of non-renewal and/or sought agreement from Employee to amendments to this Agreement, if a Potential Change in Control or a Change in Control occurs during the term hereof, the term of this Agreement shall be automatically extended to the second anniversary of the date on which the Change in Control occurs (the “Change in Control Date”); provided, however, that if no Change in Control has occurred prior to the first anniversary of the occurrence of a Potential Change in Control and the Board of Directors of Parent (the “Board”), acting in good faith, thereafter adopts a resolution that such Potential Change in Control will not result in the occurrence of a Change in Control, the term of this Agreement shall expire on a date specified by the Board not earlier than the first anniversary of the adoption of such resolution (unless otherwise extended pursuant to the second sentence of this paragraph 1).

     2. Operation of Agreement. Except as expressly provided below, no benefits shall be payable under this Agreement if Employee is not employed by the Company on the Change in Control Date. Notwithstanding anything else contained herein to the contrary, if Employee’s employment is terminated (a) by the Company and such termination is not a Termination for Cause and (b) after the occurrence of a Potential Change in Control but prior to a Change in Control and a Change in Control occurs within 12 months after such termination, Employee shall be deemed, solely for purposes of determining Employee’s rights under this Agreement, to

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have remained employed until the Change in Control Date and to have been terminated by the Company without cause immediately thereafter; provided, however, that, in such case, the Separation Payment payable hereunder shall be reduced by the amount of any other cash severance benefits theretofore paid to Employee in connection with such termination. If Employee is still an employee of the Company on the Change in Control Date, or Employee is deemed, for purposes of this Agreement, to continue to be in the employ of the Company until the Change in Control Date pursuant to the immediately preceding sentence, upon the occurrence of a Change in Control this Agreement shall supercede any other individual agreement between Parent and Employer and Employee the primary purpose of which is to provide Employee the right to receive severance benefits and certain other benefits ancillary to such severance benefits in connection with the termination of Employee’s employment (the “Severance Agreement”), subject, if applicable, to the offset set forth in the immediately preceding sentence.

     3. Certain Definitions. As used in this Agreement, the following terms shall have the meanings set forth below:

     (a) “Accrued Obligations” shall mean any vested amounts or benefits owing to Employee under any of the Company’s employee benefit plans and programs in which Employee has participated, including any compensation previously deferred by Employee (together with any accrued earnings thereon) and not yet paid.

     (b) “Base Salary” shall mean Employee’s annualized base salary at the rate in effect at the relevant date or event as reflected in Employer’s regular payroll records.

     (c) “Change in Control” shall mean an event that constitutes a “change in control” as defined in Parent’s Long-Term Incentive Plan (the “LTIP”), as in effect on the Effective Date or as subsequently amended from time to time (except that any amendment to such definition adopted on or after, or within 180 days prior to, a Change in Control or Potential Change in Control shall not be applied in determining the definition of such term under this Agreement unless such amendment is favorable to Employee).

     (d) "Date of Termination” shall mean

     (1) In the case of a termination for which a Notice of Termination is required, the date of receipt of such Notice of Termination or, if later, the date specified therein; and

     (2) In all other cases, the actual date on which Employee’s employment terminates.

     (e) “Disability” shall mean Employee’s physical or mental impairment or incapacity of sufficient severity such that

     (1) In the opinion of a qualified physician selected by Parent with the consent of Employee or Employee’s legal representative (which consent shall not be unreasonably withheld), after taking into account all reasonable accommodations that the Company has made or could make, Employee is

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unable to continue to perform Employee’s duties and responsibilities as an employee of the Company; and

     (2) Employee’s condition entitles Employee to long-term disability benefits under any employee benefit plan maintained by the Company or any of its affiliates that are at least comparable to those made available to Employee by the Company prior to the Change in Control.

For purposes of subparagraph (e)(1) above, Employee agrees to provide such access to Employee’s medical records and to submit to such physical examinations and medical tests as, in the opinion of the physician selected by Parent, is reasonably necessary to make the determination required as to Employee’s ability to perform Employee’s duties and responsibilities.

     (f) “Earned Salary” shall mean the Base Salary earned by Employee, but unpaid, through Employee’s Date of Termination.

     (g) “Normal Retirement Date” shall mean the date on which Employee attains age 60.

     (h) “Notice of Termination” shall mean a written notice given, in the case of a Termination for Cause, within 45 days of Parent’s or Employer’s having actual knowledge of the events giving rise to such termination, and in the case of a Termination for Good Reason, within 90 days of the later to occur of (x) the Change in Control Date or (y) Employee’s having actual knowledge of the events giving rise to such termination. Any such Notice of Termination shall

     (1) Indicate the specific termination provision in this Agreement relied upon;

     (2) Set forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of Employee’s employment under the provision so indicated; and

     (3) If the Date of Termination is other than the date of receipt of such notice, specify the Date of Termination (which date shall be not more than 30 days after the giving of such notice).

The failure by Employee to set forth in the Notice of Termination any fact or circumstance which contributes to a showing of Termination for Good Reason shall not waive any right of Employee hereunder or preclude Employee from asserting such fact or circumstance in enforcing Employee’s rights hereunder.

     (i) “Potential Change in Control” shall mean the occurrence of any of the following events:

     (1) Any person or group shall have announced publicly an intention to effect a Change in Control, or commenced any action (such as the commencement of a tender offer for Parent’s common stock or the solicitation of

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proxies for the election of any of Parent’s directors) that, if successful, could reasonably be expected to result in the occurrence of a Change in Control;

     (2) Parent enters into an agreement the consummation of which would constitute a Change in Control; or

     (3) Any other event occurs which the Board declares to be a Potential Change in Control.

     (j) “Separation Payment” shall mean any lump sum cash payment in excess of Earned Salary and Accrued Obligations payable to Employee under this Agreement.

     (k) “Target Bonus” shall mean the greater of

     (1) the average of the target bonuses made available to Employee under any Company annual bonus program (which, if not stated as the target for a full year of service, shall be annualized) for the year in which the Change in Control Date occurs and for each of the last 2 years ended prior to the year in which the Change in Control Date occurs (or, if less, the number of years prior to the year in which the Change in Control Date occurs during which Employee was employed by the Company); and

     (2) Employee’s highest target bonus made available to Employee under the annual bonus program in which Employee participated for services rendered or to be rendered by Employee in any calendar year after the calendar year in which the Change in Control Date occurs;

in either case as reflected in Employer’s records.

     (l) “Termination for Cause” shall mean a termination of Employee’s employment by Parent and Employer due to the occurrence of any of the following

     (1) Employee’s continued failure (i) to substantially perform Employee’s duties and responsibilities (other than any such failure resulting from Employee’s physical or mental impairment or incapacity) or (ii) to comply with any material written policy of the Company generally applicable to all officers of the Company and, if applicable, the successor in interest to Parent or, if such successor is a subsidiary of any other entity, the direct or indirect ultimate parent of such successor (such successor or such ultimate parent entity, the “Parent Successor”), which specifically provides that Employee may be dismissed (or Employee’s employment terminated) as a consequence of any such failure to comply, in either case more than 10 business days after written demand for substantial performance or compliance with the policy is delivered by Parent specifically identifying the manner in which Parent believes Employee has not substantially performed Employee’s duties and responsibilities or not complied with the written policy;

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     (2) Employee’s engaging in an act or acts of gross misconduct which result in, or are intended to result in, material damage to the Company’s business or reputation;

     (3) Employee’s failure, following a written request from Parent, reasonably to cooperate (including, without limitation, the refusal by Employee to be interviewed or deposed, or to give testimony) in connection with any investigation or proceeding, whether internal or external (including, without limitation, by any governmental or quasi-governmental agency), into the business practices or operations of the Company; or

     (4) Employee’s conviction of (or plea of guilty or nolo contendere to a charge of) any felony or any crime or misdemeanor, in either case, involving moral turpitude or financial misconduct which results in significant monetary damage to the Company.

For purposes of subparagraph (l)(2) above, an act, or failure to act, on Employee’s part shall only be considered “misconduct” if done, or omitted, by Employee not in good faith and without reasonable belief that such act, or failure to act, was in the best interest of the Company.

     (m) “Termination for Good Reason” shall mean a termination of Employee’s employment by Employee due to the occurrence of any of the following, without the express written consent of Employee, after the occurrence of a Potential Change in Control or a Change in Control:

     (1) (i) The assignment to Employee of any duties inconsistent in any material adverse respect with Employee’s position, authority or responsibilities as in effect immediately prior to a Potential Change in Control or a Change in Control, or (ii) any other material adverse change in such position, including titles, authority or responsibilities, which, in the case of any officer of Parent, shall be deemed to have occurred unless, following the Change in Control Date, Employee holds such position or positions with the Parent Successor that are substantially comparable to the position or positions held by Employee with Parent immediately prior to the Change in Control Date (or, if higher, immediately prior to the occurrence of a Potential Change in Control);

     (2) Any failure by the Company or the Parent Successor, other than an insubstantial or inadvertent failure remedied promptly after receipt of notice thereof given by Employee, to provide Employee with an annual Base Salary which is at least equal to the Base Salary payable to Employee immediately prior to the Change in Control Date (or, if higher, immediately prior to the occurrence of a Potential Change in Control) or, if more favorable to Employee, at the rate made available to Employee at any time thereafter (the “Protected Base Salary”);

     (3) Any failure by the Company or the Parent Successor, other than an insubstantial or inadvertent failure remedied promptly after receipt of notice thereof given by Employee, to provide Employee with a reasonably achievable opportunity (determined in a manner consistent with the Company’s practices

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prior to the Change in Control) to receive an annual bonus ranging from 100%, at targeted levels of performance, to 200%, at superior levels of performance, of Employee’s Target Bonus;

     (4) Any failure by the Company or the Parent Successor, other than an insubstantial or inadvertent failure remedied promptly after receipt of notice thereof given by Employee, to provide Employee with annual awards of long-term incentive compensation that have a value (using the same valuation methodologies used for valuing long-term incentive compensation awards of a similar type made to senior officers of Parent and, if applicable, the Parent Successor) at least equal to the average dollar value assigned thereto by the Company at the date of grant of the last three annual long-term incentive compensation awards (including, without limitation, equity and equity-based awards) granted to Employee in respect of Employee’s employment with the Company (or if Employee has received less than three such annual grants, the average of the value of the number of grants received by Employee prior to the Change in Control Date);

     (5) Any failure by the Company or the Parent Successor, other than an insubstantial or inadvertent failure remedied promptly after receipt of notice thereof given by Employee, to permit Employee (and, to the extent applicable, Employee’s dependents) to participate in or be covered under all pension, retirement, deferred compensation, savings, medical, dental, health, disability, group life, accidental death and travel accident insurance plans and programs at a level that is materially less favorable in the aggregate than the benefits provided under the plans of the Company and its affiliated companies prior to the Change in Control Date (or, if more favorable to Employee, at the level made available to Employee or other similarly situated officers at any time thereafter); or

     (6) If, not later than the Change in Control Date, any Parent Successor shall have failed to agree in writing to assume and perform this Agreement as required by paragraph 7(h) hereof.

     4. Termination of Employment.

     (a) Right to Terminate. Nothing in this Agreement shall be construed in any way to limit the right of the Company to terminate Employee’s employment, with or without cause, or for Employee to terminate Employee’s employment with the Company, with or without reason; provided, however, that the Company and Employee must nonetheless comply with any duty or obligation such party has at law or under any agreement (including paragraph 6 of this Agreement) between the parties.

     (b) Termination due to Death or Disability. Employee’s employment with the Company shall be terminated upon Employee’s death. By written notice to the other party, either the Company or Employee may terminate Employee’s employment due to Disability.

     5. Amounts Payable Upon Termination of Employment. The following provisions shall apply to any termination of Employee’s employment occurring (or which,

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pursuant to paragraph 2, is deemed to occur) at the time of, or at any time within 2 years following, a Change in Control:

     (a) Death, Disability or Normal Retirement. In the event that Employee’s employment terminates due to Employee’s death or Disability (regardless of whether such Disability termination is initiated by Employee or the Company) or due to the voluntary retirement by Employee (which is not a Termination for Good Reason) at or after attaining Normal Retirement Date, Parent or Employer shall pay Employee (or, if applicable, Employee’s beneficiaries or legal representative(s)):

     (1) The Earned Salary, as soon as practicable (but not more than 10 days) following Employee’s Date of Termination;

     (2) The Accrued Obligations, in accordance with applicable law and the provisions of any applicable plan, program, policy or practice; and

     (3) A Separation Payment in an amount equal to Employee’s Base Salary, which shall be paid, in all cases other than a voluntary retirement on or after Normal Retirement Date, within 10 days following Employee’s Date of Termination, and, in the case of a voluntary retirement on or after Normal Retirement Date, 6 months and 1 day after Employee’s Date of Termination.

     (b) Cause and Voluntary Termination. If Employee’s employment is terminated by the Company in a Termination for Cause or voluntarily by Employee (other than in a Termination for Good Reason or at or after Normal Retirement Date), Parent or Employer shall pay Employee

     (1) The Earned Salary as soon as practicable (but in no event more than 10 days), following Employee’s Date of Termination; and

     (2) The Accrued Obligations in accordance with applicable law and the provisions of any applicable plan, program, policy or practice.

     (c) Termination for Good Reason or Without Cause. If Employee terminates Employee’s employment in a Termination for Good Reason or the Company terminates Employee’s employment for any reason other than those described in paragraphs 5(a) and (b) above, Parent or Employer shall pay or shall provide to Employee the following benefits and compensation:

     (1) The Earned Salary, as soon as practicable (but not more than 10 days) following Employee’s Date of Termination;

     (2) The Accrued Obligations, in accordance with applicable law and the provisions of any applicable plan, program, policy or practice;

     (3) Continued coverage following Employee’s Date of Termination, at the same costs that apply to similarly situated active employees, for Employee and Employee’s eligible dependants under the Employer’s group health plan(s) (as defined by the Consolidated Omnibus Budget Reconciliation Act of 1985 (“COBRA”)) in which Employee was participating prior to the Date of Termination

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or, to the extent such continued coverage cannot be provided under such plan without adverse consequences for the Company or Employee due to non-discrimination requirements, then under an individual or group policy that is substantially similar in all material respects to the coverage made available under such group health plan(s), for the period over which the Protected Base Salary payable as part of the Separation Payment under subparagraph 5(c)(6) would have been payable if it had been paid over time in accordance with the Employer’s payroll practices as in effect at the Change in Control Date; provided, however, that such continued coverage shall cease if and when Employee becomes eligible for comparable coverage under the group health plans of a subsequent employer. For the avoidance of doubt, it is understood that Employee’s right, if any, to purchase continued coverage under COBRA shall commence following the expiration of the continued coverage provided under this subparagraph 5(c)(3); and

     (4) If Employee shall have relocated Employee’s principal residence to enter into the Company’s employ, or otherwise relocated such residence at the request of the Company, within 1 year of the Change in Control Date, and if Employee elects to relocate to Employee’s original location following Employee’s Date of Termination, relocation benefits under the same relocation policy as applied to Employee’s initial relocation; provided, however, that the benefits provided hereunder shall not be duplicative of any relocation benefits to which Employee is entitled in connection with the plan, policy, program or practice of any subsequent employer;

     (5) To the extent that any award granted to Employee under the LTIP and outstanding on the Change in Control Date shall not have previously become fully vested and, as applicable, exercisable, payable, distributable and free of any transfer restrictions, such award shall be and become fully vested and, as applicable, exercisable, payable or distributable to, and transferable by, Employee on Employee’s Date of Termination, without any further action by the Company or any other person(s);

     (6) A Separation Payment, as soon as practicable (but no later than 10 days) following Employee’s Date of Termination, in an amount equal to the sum of

     (i) 2.99 times the sum of Employee’s Protected Base Salary and Target Bonus;

     (ii) The product of (A) the amount of the Target Bonus and (B) a fraction, the numerator of which is the number of days in the then current calendar year which have elapsed as of the Date of Termination, and the denominator of which is 365;

     (iii) If Employee’s employment was terminated prior to the Change in Control Date, but Employee is deemed to have continued in the Company’s employment for purposes of this Agreement until the Change in Control Date pursuant to paragraph 2 hereof, an amount equal to the value (as determined based on the fair market value of the Parent’s

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common stock on the Change in Control Date, but debiting therefrom any amount Employee would be required to pay to receive the benefit of such award) of any equity awards (including, without limitation, stock options and restricted stock) granted to Employee under the LTIP that were outstanding but unvested (after taking into account any accelerated vesting thereof in connection with such termination of employment) on Employee’s Date of Termination; and

     (iv) If the termination of employment is by the Company and if the Date of Termination is less than 30 days after the date Notice of Termination is given, an amount equal to 1/12 (one twelfth) of the Protected Base Salary, which amount shall be paid in cash on the Date of Termination.

     (d) Benefits Payable Due to Forced Relocation. If Employee is not otherwise entitled to terminate Employee’s employment in a Termination for Good Reason and terminates employment voluntarily because Parent or Parent Successor requires (or notifies Employee in writing that it will require) Employee to be based at any office or location more than 50 miles from that location at which Employee principally performed services for the Company immediately prior to the Change in Control Date, except for travel reasonably required in the performance of Employee’s responsibilities, Parent or Employer shall pay or shall provide to Employee the following benefits and compensation:

     (1) The Earned Salary, as soon as practicable (but not more than 10 days) following Employee’s Date of Termination;

     (2) The Accrued Obligations, in accordance with applicable law and the provisions of any applicable plan, program, policy or practice;

     (3) Continued coverage, at the same costs that apply to similarly situated active employees, for Employee and Employee’s eligible dependants under Employer’s group health plan(s) (within the meaning of the Consolidated Omnibus Budget Reconciliation Act of 1985 (“COBRA”)) in which Employee was participating prior to the Date of Termination for a period of 12 months following Employee’s Date of Termination (or, if earlier, until Employee is eligible for comparable coverage under the group health plan(s) of a subsequent employer); and

     (4) A Separation Payment, as soon as practicable (but no later than 10 days) following Employee’s Date of Termination, in an amount equal to Employee’s Protected Base Salary.

     (e) Certain Further Payments by Parent and Employer.

     (1) Tax Reimbursement Payment. In the event that any amount or benefit paid or distributed to Employee pursuant to this Agreement, taken together with any amounts or benefits otherwise paid or distributed to Employee by the Company or any affiliated company in connection with the Change in Control that are treated as parachute payments under Section 280G of the

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Internal Revenue Code of 1986, as amended (the “Code” and such payments, collectively, the “Covered Payments”), are or become subject to the tax (the “Excise Tax”) imposed under Section 4999 of the Code or any similar tax that may hereafter be imposed, Parent or Employer shall pay to Employee at the time specified in subparagraph 5(e)(5) below an additional amount (the “Tax Reimbursement Payment”) such that the net amount retained by Employee with respect to such Covered Payments, after deduction of any Excise Tax on the Covered Payments and any Federal, state and local income tax and Excise Tax on the Tax Reimbursement Payment provided for by this paragraph 5(e), but before deduction for any Federal, state or local income or employment tax withholding on such Covered Payments, shall be equal to the amount of the Covered Payments.

     (2) Assumptions for Calculation. For purposes of determining whether any of the Covered Payments will be subject to the Excise Tax and the amount of such Excise Tax,

     (i) such Covered Payments will be treated as “parachute payments” within the meaning of Section 280G of the Code, and all “parachute payments” in excess of the “base amount” (as defined under Section 280G(b)(3) of the Code) shall be treated as subject to the Excise Tax, unless, and except to the extent that, in the good faith judgment of a public accounting firm appointed by Parent prior to the Change in Control Date or tax counsel selected by such accounting firm (the “Accountants”), the Company has a reasonable basis to conclude that such Covered Payments (in whole or in part) either do not constitute “parachute payments” or represent reasonable compensation for personal services actually rendered (within the meaning of Section 280G(b)(4)(B) of the Code) in excess of the “base amount,” or such “parachute payments” are otherwise not subject to such Excise Tax; and

     (ii) the value of any non-cash benefits or any deferred payment or benefit shall be determined by the Accountants in accordance with the principles of Section 280G of the Code.

     (3) Assumed Tax Rates. For purposes of determining the amount of the Tax Reimbursement Payment, Employee shall be deemed to pay:

     (i) Federal income taxes at the highest applicable marginal rate of Federal income taxation for the calendar year in which the Tax Reimbursement Payment is to be made; and

     (ii) any applicable state and local income taxes at the highest applicable marginal rate of taxation for the calendar year in which the Tax Reimbursement Payment is to be made, net of the maximum reduction in Federal incomes taxes which could be obtained from the deduction of such state or local taxes if paid in such year.

     (4) Subsequent Adjustment. In the event that the Excise Tax is subsequently determined by the Accountants or pursuant to any proceeding or

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negotiations with the Internal Revenue Service to be less than the amount taken into account hereunder in calculating the Tax Reimbursement Payment made, Employee shall repay to Parent or Employer, at the time that the amount of such reduction in the Excise Tax is finally determined, the portion of such prior Tax Reimbursement Payment that would not have been paid if such Excise Tax had been applied in initially calculating such Tax Reimbursement Payment, plus interest on the amount of such repayment at the rate provided in Section 1274(b)(2)(B) of the Code. Notwithstanding the foregoing, in the event any portion of the Tax Reimbursement Payment to be refunded to Parent or Employer has been paid to any Federal, state or local tax authority, repayment thereof shall not be required until actual refund or credit of such portion has been made to Employee, and interest payable to Parent or Employer shall not exceed interest received or credited to Employee by such tax authority for the period it held such portion. Employee and Parent shall mutually agree upon the course of action to be pursued (and the method of allocating the expenses thereof) if Employee’s good faith claim for refund or credit is denied.

     In the event that the Excise Tax is later determined by the Accountants or pursuant to any proceeding or negotiations with the Internal Revenue Service to exceed the amount taken into account hereunder at the time the Tax Reimbursement Payment is made (including, but not limited to, by reason of any payment the existence or amount of which cannot be determined at the time of the Tax Reimbursement Payment), Parent or Employer shall make an additional Tax Reimbursement Payment in respect of such excess (plus any interest or penalty payable with respect to such excess) at the time that the amount of such excess is finally determined.

     (5) Timing of Payments. The Tax Reimbursement Payment (or portion thereof) provided for in paragraph 5(e)(1) above shall be paid to Employee not later than 10 days following the payment of the Covered Payments; provided, however, that if the amount of such Tax Reimbursement Payment (or portion thereof) cannot be finally determined on or before the date on which payment is due, Parent or Employer shall pay to Employee by such date an amount estimated in good faith by the Accountants to be the minimum amount of such Tax Reimbursement Payment and shall pay the remainder of such Tax Reimbursement Payment (together with interest at the rate provided in Section 1274(b)(2)(B) of the Code) as soon as the amount thereof can be determined, but in no event later than 45 days after payment of the related Covered Payment. In the event that the amount of the estimated Tax Reimbursement Payment exceeds the amount subsequently determined to have been due, such excess shall constitute a loan by Parent or Employer to Employee, payable on the fifth business day after written demand by Parent or Employer for payment (together with interest at the rate provided in Section 1274(b)(2)(B) of the Code).

     6. Nonpublic Information.

     (a) Acknowledgement of Access. Employee hereby acknowledges that, in connection with Employee’s employment with the Company, Employee has received, and will continue to receive, various information regarding the Company and its

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business, operations and affairs. All such information, to the extent not publicly available other than as a result of a disclosure by Employee in violation of this Agreement, is referred to herein as the “Nonpublic Information.”

     (b) Agreement to Keep Confidential. Employee hereby agrees that, from and after the Effective Date and continuing until 3 years following Employee’s Date of Termination, Employee will keep all Nonpublic Information confidential and will not, without the prior written consent of the Board, Chief Executive Officer or the President of Parent, disclose any Nonpublic Information in any manner whatsoever or use any Nonpublic Information other than in connection with the performance of Employee’s services to the Company; provided, however, that the provisions of this subparagraph shall not prevent Employee from

     (1) Disclosing any Nonpublic Information to any other employee of the Company or to any representative or agent of the Company (such as an independent accountant, engineer, attorney or financial advisor) when such disclosure is reasonably necessary or appropriate (in Employee’s judgment) in connection with the performance by Employee of Employee’s duties and responsibilities;

     (2) Disclosing any Nonpublic Information as required by applicable law, rule, regulation or legal process (but only after compliance with the provisions of subparagraph (c) of this paragraph); and

     (3) Disclosing any information about this Agreement and Employee’s other compensation arrangement to Employee’s spouse, financial advisors or attorneys, or to enforce any of Employee’s rights under this Agreement.

     (c) Commitment to Seek Protective Order. If Employee is requested pursuant to, or required by, applicable law, rule, regulation or legal process to disclose any Nonpublic Information, Employee will notify Parent promptly so that the Company may seek a protective order or other appropriate remedy or, in Parent’s sole discretion, waive compliance with the terms of this subparagraph, and Employee will fully cooperate in any attempt by the Company to obtain any such protective order or other remedy. If no such protective order or other remedy is obtained, or Parent waives compliance with the terms of this paragraph, Employee will furnish or disclose only that portion of the Nonpublic Information as is legally required and will exercise all reasonable efforts to obtain reliable assurance that confidential treatment will be accorded the Nonpublic Information that is so disclosed.

     7. Miscellaneous Provisions.

     (a) No Mitigation, No Offset. Employee shall not be required to mitigate the amount of any payment provided for in this Agreement by seeking other employment or otherwise, and the amount of any payment provided for in this Agreement shall not be reduced by any compensation earned by Employee as the result of employment by another employer after the Date of Termination. Except as provided in subparagraph 5(c)(3), Parent’s or Employer’s obligation to make the payments provided for in this Agreement and otherwise to perform its obligations hereunder shall not be affected by any circumstances, including, without limitation, any set-off, counterclaim, recoupment,

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defense or other right which the Company may have against Employee or others whether by reason of the subsequent employment of Employee or otherwise.

     (b) Arbitration. Except to the extent provided in paragraph 7(d), any dispute or controversy arising under or in connection with this Agreement shall be resolved by binding arbitration. The arbitration shall be held in Dallas, Texas and except to the extent inconsistent with this Agreement, shall be conducted in accordance with the Expedited Employment Arbitration Rules of the American Arbitration Association then in effect at the time of the arbitration, and otherwise in accordance with principles which would be applied by a court of law or equity. The arbitrator shall be acceptable to both Parent and Employee. If the parties cannot agree on an acceptable arbitrator, the dispute shall be heard by a panel of three arbitrators, one appointed by each of the parties and the third appointed by the other two arbitrators.

     (c) Interest. Until paid, all past due amounts required to be paid by the Company to Employee under any provision of this Agreement shall bear interest at the per annum rate equal to the higher of (1) 12% or (2) the prime rate announced from time to time by the Company’s primary bank lender, plus 3%, in either case subject to the maximum rate allowed by law.

     (d) Equitable Relief Available. Employee acknowledges that remedies at law may be inadequate to protect the Company against any actual or threatened breach of the provisions of paragraph 6 by Employee. Accordingly, without prejudice to any other rights or remedies otherwise available to the Company, Employee agrees that the Company shall have the right to equitable and injunctive relief to prevent any breach of the provisions of paragraph 6 (without the requirement to post any bond), as well as to such damages or other relief as may be available to the Company by reason of any such breach as does occur.

     (e) Not A Contract of Employment. Employee acknowledges that this Agreement is not an “employment agreement” or “employment contract” (written or otherwise), as either term is used or defined in, or contemplated by or under

     (1) Parent’s LTIP;

     (2) Any other plan or agreement to which the Company is a party; or

     (3) Applicable statutory, common or case law.

     (f) Breach Not- a Defense. The representations and covenants on the part of Employee contained in paragraph 6 shall be construed as ancillary to and independent of any other provision of this Agreement, and the existence of any claim or cause of action of Employee against the Company or any officer, director, stockholder or representative of the Company, whether predicated on this Agreement or otherwise, shall not constitute a defense to the enforcement by the Company of the covenants on the part of Employee contained in paragraph 6.

     (g) Notices. Any Notice of Termination or other communication called for by the terms of this Agreement shall be in writing and either delivered personally or by registered or certified mail (postage prepaid and return receipt requested) and shall be

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deemed given when received at the following addresses (or at such other address for a party as shall be specified by like notice):

     (1) If to Parent, Employer or the Company, 5205 North O’Connor Boulevard, Suite 900, Irving, Texas 75039, Attention: General Counsel.

     (2) If to Employee, the address of Employee set forth below Employee’s signature on the signature page of this Agreement.

     (h) Assumption by Parent Successor. Parent shall require any Parent Successor (regardless of whether the Parent Successor is the direct or indirect successor to all or substantially all of the business or assets of Parent and regardless of whether it became the Parent Successor by purchase of securities, merger, consolidation, sale of assets or otherwise), to expressly assume and agree to perform the obligations to be performed by the Company under this Agreement in the same manner and to the same extent that the Company would be required to perform if no such succession had taken place.

     (i) Assignment. Employer may assign its duties and obligations hereunder to any other direct or indirect majority-owned subsidiary of Parent, but shall remain secondarily liable for the performance of this Agreement by Parent and/or any such assignee. Except pursuant to either the immediately preceding sentence or an assumption by a Parent Successor, the rights and obligations of Parent and Employer pursuant to this Agreement may not be assigned, in whole or in part, by Parent or Employer to any other person or entity without the express written consent of Employee. The rights and obligations of Employee pursuant to this Agreement may not be assigned, in whole or in part, by Employee to any other person or entity without the express written consent of the Board.

     (j) Successors. This Agreement shall be binding on, and shall inure to the benefit of, Parent, Employer, the Company, Employee and their respective successors, permitted assigns, personal and legal representatives, executors, administrators, heirs, distributees, devisees and legatees, as applicable.

     (k) Amendments and Waivers. No provision of this Agreement may be amended or otherwise modified, and no right of any party to this Agreement may be waived, unless such amendment, modification or waiver is agreed to in a written instrument signed by Employee, Parent and Company. No waiver by either party hereto of, or compliance with, any condition or provision of this Agreement to be performed by the other party hereto shall be deemed a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time.

     (l) Complete Agreement. This Agreement replaces and supersedes all prior agreements, if any, among the parties with respect to the payments to be made to Employee upon termination of employment following a Change in Control, including, but not limited to, the Change in Control Agreement between Parent, Employer and Employee, as in effect immediately prior to the date hereof, and the provisions of this Agreement constitute the complete understanding and agreement among the parties with respect to the subject matter hereof. Nothing in this subparagraph (l) is intended to, or shall be construed to, (1) supercede the Severance Agreement at any time prior to the

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time expressly provided in paragraph 2 hereof or (2) limit Employee’s rights upon the occurrence of a Change in Control under the LTIP or any other Company plan, policy, program or practice (other than any plan, policy, program or practice primarily providing severance or other termination benefits) generally applicable to similarly situated employees.

     (m) Governing Law. THIS AGREEMENT IS BEING MADE AND EXECUTED IN, AND IS INTENDED TO BE PERFORMED IN, THE STATE OF TEXAS AND SHALL BE GOVERNED, CONSTRUED, INTERPRETED AND ENFORCED IN ACCORDANCE WITH THE SUBSTANTIVE LAWS OF THE STATE OF TEXAS.

     (n) Attorney Fees. All legal fees and other costs incurred by Employee in connection with the resolution of any dispute or controversy under or in connection with this Agreement shall be reimbursed by Parent and Employer to Employee, on a quarterly basis, upon presentation of proof of such expenses, provided, however, that if Employee asserts any claim in any contest and Employee shall not prevail, in whole or in part, as to at least one material issue as to the validity, enforceability or interpretation of any provision of this Agreement, Employee shall reimburse Parent and Employer for such amounts, plus simple interest thereon at the 90-day United States Treasury Bill rate as in effect from time to time, compounded annually. The Company shall be responsible for, and shall pay, all legal fees and other costs incurred by the Company in connection with the resolution of any dispute or controversy under or in connection with this Agreement, regardless of whether such dispute or controversy is resolved in favor of the Company or Employee.

     (o) Counterparts. This Agreement may be executed in several counterparts, each of which shall be deemed to be an original, but all of which together will constitute one and the same agreement.

     (p) Construction. The captions of the paragraphs, subparagraphs and sections of this Agreement have been inserted as a matter of convenience of reference only and shall not affect the meaning or construction of any of the terms or provisions of this Agreement. Unless otherwise specified, references in this Agreement to a “paragraph,” “subparagraph,” “section,” “subsection,” or “schedule” shall be considered to be references to the appropriate paragraph, subparagraph, section, subsection, or schedule, respectively, of this Agreement. As used in this Agreement, the term “including” shall mean “including, but not limited to.”

     (q) Validity and Severability. If any term or provision of this Agreement is held to be illegal, invalid or unenforceable under the present or future laws effective during the term of this Agreement, (1) such term or provision shall be fully severable, (2) this Agreement shall be construed and enforced as if such term or provision had never comprised a part of this Agreement and (3) the remaining terms and provisions of this Agreement shall remain in full force and effect and shall not be affected by the illegal, invalid or unenforceable term or provision or by its severance from this Agreement. Furthermore, in lieu of such illegal, invalid or unenforceable term or provision, there shall be added automatically as a part of this Agreement, a term or provision as similar to such illegal, invalid or unenforceable term or provision as may be possible and be legal, valid and enforceable.

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     (r) Survival. Notwithstanding anything else in this Agreement to the contrary (including, without limitation, the termination of this Agreement in accordance with paragraph 1), paragraphs 6 and 7, and, to the extent that any of Parent’s and Employer’s obligations thereunder have not theretofore been satisfied, paragraph 5 of this Agreement shall survive the termination hereof.

     (s) Joint and Several Liability. Parent and Employer (or any assignee of Employer pursuant to paragraph 7(i)) shall each be jointly and severally liable to Employee hereunder with regard to any obligation imposed by the terms hereof on Parent or Employer.

(SIGNATURE PAGE ATTACHED)

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     In witness whereof, the parties have executed this Agreement effective as of the date first written above.

PIONEER NATURAL RESOURCES COMPANY
By:
Name:	Larry Paulsen
Title:	VP, Administration
Pioneer Natural Resources USA, Inc.
By:
Name:	Larry Paulsen
Title:	VP, Administration
EMPLOYEE:
Address:

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EX-10.3

Exhibit 10.3

PIONEER NATURAL RESOURCES COMPANY

INDEMNIFICATION AGREEMENT

     This Agreement (“Agreement”) is made and entered into as of the 15th day of November, 2006, by and between Pioneer Natural Resources Company, a Delaware corporation (the “Company”), and                                          (“Indemnitee”).

RECITALS

     A. Highly competent and experienced persons are reluctant to serve corporations as directors, executive officers or in other capacities unless they are provided with adequate protection through insurance and indemnification against claims and actions against them arising out of their service to and activities on behalf of the Company.

     B. The Board of Directors of the Company (the “Board”) has determined that the inability to attract and retain such persons would be detrimental to the best interests of the Company and its stockholders and that the Company should act to assure such persons that there will be increased certainty of such protection in the future.

     C. The Board has also determined that it is reasonable, prudent and necessary for the Company, in addition to purchasing and maintaining directors’ and officers’ liability insurance (or otherwise providing for adequate arrangements of self-insurance), contractually to obligate itself to indemnify such persons to the fullest extent permitted by applicable law so that they will serve or continue to serve the Company free from undue concern that they will not be adequately protected.

     D. Indemnitee is willing to serve, continue to serve and to take on additional service for or on behalf of the Company on the condition that Indemnitee be so indemnified to the fullest extent permitted by law.

     E. Article Twelfth of the Amended and Restated Certificate of Incorporation of the Company provides for indemnification of directors and officers to the fullest extent permitted by law.

     In consideration of the foregoing and the mutual covenants herein contained, and other good and valuable consideration, the sufficiency and receipt of which are hereby acknowledged, the parties hereby agree as follows:

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ARTICLE I

Certain Definitions

     As used herein, the following words and terms shall have the following respective meanings (whether singular or plural):

     “Acquiring Person” means any Person other than (i) the Company, (ii) any of the Company’s Subsidiaries, (iii) any employee benefit plan of the Company or of a Subsidiary of the Company or of a Company owned directly or indirectly by the stockholders of the Company in substantially the same proportions as their ownership of stock of the Company, or (iv) any trustee or other fiduciary holding securities under an employee benefit plan of the Company or of a Subsidiary of the Company or of a Company owned directly or indirectly by the stockholders of the Company in substantially the same proportions as their ownership of stock of the Company.

     “Change in Control” means the occurrence of any of the following events:

     (i) The acquisition by any Person of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 40% or more of either (x) the then outstanding shares of Common Stock of the Company (the “Outstanding Company Common Stock”) or (y) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors (the “Outstanding Company Voting Securities”); provided, however, that for purposes of this Subparagraph (i), the following acquisitions shall not constitute a Change of Control: (A) any acquisition directly from the Company, (B) any acquisition by the Company, (C) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company or (D) any acquisition by any corporation pursuant to a transaction which complies with clauses (A), (B) and (C) of paragraph (iii) below; or

     (ii) Members of the Incumbent Board cease for any reason to constitute at least a majority of the Board; or

     (iii) Consummation of a reorganization, merger or consolidation or sale or other disposition of all or substantially all of the assets of the Company or an acquisition of assets of another corporation (a “Business Combination”), in each case, unless, following such Business Combination, (A) all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Company Common Stock and Outstanding Company Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination (including, without limitation, a corporation which as a result of such transaction owns the Company or all or substantially all of the Company’s assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership, immediately

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prior to such Business Combination of the Outstanding Company Common Stock and Outstanding Company Voting Securities, as the case may be, (B) no Person (excluding any employee benefit plan (or related trust) of the Company or the corporation resulting from such Business Combination) beneficially owns, directly or indirectly, 40% or more of, respectively, the then outstanding shares of common stock of the corporation resulting from such Business Combination or the combined voting power of the then outstanding voting securities of such corporation except to the extent that such ownership results solely from ownership of the Company that existed prior to the Business Combination and (C) at least a majority of the members of the board of directors of the corporation resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement, or of the action of the Board, providing for such Business Combination; or

     (iv) Approval by the stockholders of the Company of a complete liquidation or dissolution of the Company.

     “Claim” means an actual or threatened claim or request for relief which was, is or may be made by reason of anything done or not done by Indemnitee in, or by reason of any event or occurrence related to, Indemnitee’s Corporate Status.

     “Corporate Status” means the status of a person who is, becomes or was a director, officer, employee, agent or fiduciary of the Company or is, becomes or was serving at the request of the Company as a director, officer, partner, venturer, proprietor, trustee, employee, agent, fiduciary or similar functionary of another foreign or domestic corporation, partnership, joint venture, sole proprietorship, trust, employee benefit plan or other enterprise. For purposes of this Agreement, the Company agrees that Indemnitee’s service on behalf of or with respect to any Subsidiary of the Company shall be deemed to be at the request of the Company.

     “DGCL” means the Delaware General Corporation Law and any successor statute thereto, as either of them may from time to time be amended.

     “Disinterested Director” with respect to any request by Indemnitee for indemnification hereunder, means a director of the Company who at the time of the vote is not a named defendant or respondent in the Proceeding in respect of which indemnification is sought by Indemnitee.

     “Exchange Act” means the Securities Exchange Act of 1934.

     “Expenses” means all attorneys’ fees and disbursements, retainers, accountant’s fees and disbursements, private investigator fees and disbursements, court costs, transcript costs, fees and expenses of experts, witness fees and expenses, travel expenses, duplicating costs, printing and binding costs, telephone charges, postage, delivery service fees and all other disbursements, costs or expenses of the types customarily incurred in connection with prosecuting, defending (including affirmative defenses and counterclaims), preparing to prosecute or defend, investigating, being or preparing to be a witness in, or participating in or preparing to participate in (including on appeal) a Proceeding and all interest or finance charges attributable to any

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thereof. Should any payments by the Company under this Agreement be determined to be subject to any federal, state or local income or excise tax, “Expenses” shall also include such amounts as are necessary to place Indemnitee in the same after-tax position (after giving effect to all applicable taxes) as Indemnitee would have been in had no such tax been determined to apply to such payments.

     “Incumbent Board” means the individuals who, as of the date of this Agreement, constitute the Board and any other individual who becomes a director of the Company after that date and whose election or appointment by the Board or nomination for election by the Company’s stockholders was approved by a vote of at least a majority of the directors then comprising the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Incumbent Board.

     “Independent Counsel” means a law firm, or a member of a law firm, that is experienced in matters of corporation law and neither contemporaneously is, nor in the five years theretofore has been, retained to represent: (a) the Company or Indemnitee in any matter material to either such party (other than as Independent Counsel under this Agreement or similar agreements), (b) any other party to the Proceeding giving rise to a claim for indemnification hereunder or (c) the beneficial owner, directly or indirectly, of securities of the Company representing 5% or more of the combined voting power of the Company’s then outstanding voting securities (other than, in each such case, with respect to matters concerning the rights of Indemnitee under this Agreement, or of other indemnitees under similar indemnification agreements). Notwithstanding the foregoing, the term “Independent Counsel” shall not include any person who, under the applicable standards of professional conduct then prevailing, would have a conflict of interest in representing either the Company or Indemnitee in an action to determine Indemnitee’s rights under this Agreement.

     “Independent Directors” means the directors on the Board that are independent directors as defined in Section 303A of the New York Stock Exchange Listed Company Manual or successor provision, or, if the Company’s common stock is not then quoted on the NYSE, that qualify as independent, disinterested, or a similar term as defined in the rules of the principal securities exchange or inter-dealer quotation system on which the Company’s common stock is then listed or quoted.

     “Person” means any individual, entity or group (within the meaning of Sections 13(d)(3) and 14(d)(2) of the Exchange Act).

     “Potential Change in Control” shall be deemed to have occurred if (i) any Person shall have announced publicly an intention to effect a Change in Control, or commenced any action (such as the commencement of a tender offer for the Company’s Common Stock or the solicitation of proxies for the election of any of the Company’s directors) that, if successful, could reasonably be expected to result in the occurrence of a Change in Control; (ii) the Company enters into an agreement, the consummation of which would constitute a Change in

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Control; or (iii) any other event occurs which the Board declares to be a Potential Change of Control.

     “Proceeding” means any threatened, pending or completed action, suit, arbitration, investigation, inquiry, alternate dispute resolution mechanism, administrative or legislative hearing, or any other proceeding (including, without limitation, any securities laws action, suit, arbitration, alternative dispute resolution mechanism, hearing or procedure) whether civil, criminal, administrative, arbitrative or investigative and whether or not based upon events occurring, or actions taken, before the date hereof, and any appeal in or related to any such action, suit, arbitration, investigation, hearing or proceeding and any inquiry or investigation (including discovery), whether conducted by or in the right of the Company or any other Person, that Indemnitee in good faith believes could lead to any such action, suit, arbitration, alternative dispute resolution mechanism, hearing or other proceeding or appeal thereof.

     “Subsidiary” means, with respect to any Person, any corporation or other entity of which a majority of the voting power of the voting equity securities or equity interest is owned, directly or indirectly, by that Person.

     “Voting Securities” means any securities that vote generally in the election of directors, in the admission of general partners, or in the selection of any other similar governing body.

ARTICLE II

Services by Indemnitee

     Indemnitee is serving as a officer of the Company. Indemnitee may from time to time also agree to serve, as the Company may request from time to time, in another capacity for the Company (including another officer or director position) or as a director, officer, partner, venturer, proprietor, trustee, employee, agent, fiduciary or similar functionary of another foreign or domestic corporation, partnership, joint venture, sole proprietorship, trust, employee benefit plan or other enterprise. Indemnitee and the Company each acknowledge that they have entered into this Agreement as a means of inducing Indemnitee to serve, or continue to serve, the Company in such capacities. Indemnitee may at any time and for any reason resign from such position or positions (subject to any other contractual obligation or any obligation imposed by operation of law). The Company shall have no obligation under this Agreement to continue Indemnitee in any such position or positions.

ARTICLE III

Indemnification

     Section 3.1 General. Subject to the provisions set forth in Article IV, the Company shall indemnify, and advance Expenses to, Indemnitee to the fullest extent permitted by applicable law in effect on the date hereof and to such greater extent as applicable law may hereafter from time to time permit. The other provisions set forth in this Agreement are provided

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in addition to and as a means of furtherance and implementation of, and not in limitation of, the obligations expressed in this Article III. No requirement, condition to or limitation of any right to indemnification or to advancement of Expenses under this Article III shall in any way limit the rights of Indemnitee under Article VII.

     Section 3.2 Additional Indemnity of the Company. Indemnitee shall be entitled to indemnification pursuant to this Section 3.2 if, by reason of anything done or not done by Indemnitee in, or by reason of any event or occurrence related to, Indemnitee’s Corporate Status, Indemnitee is, was or becomes, or is threatened to be made, a party to, or witness or other participant in any Proceeding. Pursuant to this Section 3.2, Indemnitee shall be indemnified against any and all Expenses, judgments, penalties (including excise or similar taxes), fines and amounts paid in settlement (including all interest, assessments and other charges paid or payable in connection with or in respect of any such Expenses, judgments, penalties, fines and amounts paid in settlement) actually and reasonably incurred by Indemnitee or on Indemnitee’s behalf in connection with such Proceeding or any Claim, issue or matter therein. Notwithstanding the foregoing, the obligations of the Company under this Section 3.2 shall be subject to the condition that no determination (which, in any case in which Independent Counsel is involved, shall be in a form of a written opinion) shall have been made pursuant to Article IV that Indemnitee would not be permitted to be indemnified under applicable law. Nothing in this Section 3.2 shall limit the benefits of Section 3.1 or any other Section hereunder.

     Section 3.3 Advancement of Expenses. The Company shall pay all reasonable Expenses incurred by, or in the case of retainers to be incurred by, or on behalf of Indemnitee (or, if applicable, reimburse Indemnitee for any and all Expenses reasonably incurred by Indemnitee and previously paid by Indemnitee) in connection with any Claim or Proceeding, whether brought by the Company or otherwise, in advance of any determination respecting entitlement to indemnification pursuant to Article IV hereof within 10 days after the receipt by the Company of (a) a written request from Indemnitee requesting such payment or payments from time to time, whether prior to or after final disposition of such Proceeding, and (b) a written affirmation from Indemnitee of Indemnitee’s good faith belief that Indemnitee has met the standard of conduct necessary for Indemnitee to be permitted to be indemnified under applicable law. Any such payment by the Company is referred to in this Agreement as an “Expense Advance.” In connection with any request for an Expense Advance, if requested by the Company, Indemnitee or Indemnitee’s counsel shall also submit an affidavit stating that the Expenses incurred were, or in the case of retainers to be incurred are, reasonable. Any dispute as to the reasonableness of any Expense shall not delay an Expense Advance by the Company, and the Company agrees that any such dispute shall be resolved only upon the disposition or conclusion of the underlying Claim against Indemnitee. Indemnitee hereby undertakes and agrees that Indemnitee will reimburse and repay the Company without interest for any Expense Advances to the extent that it shall ultimately be determined (in a final adjudication by a court from which there is no further right of appeal or in a final adjudication of an arbitration pursuant to Section 5.1 if Indemnitee elects to seek such arbitration) that Indemnitee is not entitled to be indemnified by the Company against such Expenses. Indemnitee shall not be required to provide collateral or otherwise secure the undertaking and agreement described in the prior sentence.

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     Section 3.4 Indemnification for Additional Expenses. The Company shall indemnify Indemnitee against any and all costs and expenses (of the types described in the definition of Expenses in Article I) and, if requested by Indemnitee, shall (within two business days of that request) advance those costs and expenses to Indemnitee, that are incurred by Indemnitee in connection with any claim asserted against, or action brought by, Indemnitee for (i) indemnification or an Expense Advance by the Company under this Agreement or any other agreement or provision of the Company’s Certificate of Incorporation or Bylaws now or hereafter in effect relating to any Claim or Proceeding, (ii) recovery under any directors’ and officers’ liability insurance policies maintained by the Company, or (iii) enforcement of, or claims for breaches of, any provision of this Agreement, in each of the foregoing situations regardless of whether Indemnitee ultimately is determined to be entitled to that indemnification, advance expense payment, insurance recovery, enforcement, or damage claim, as the case may be and regardless of whether the nature of the proceeding with respect to such matters is judicial, by arbitration, or otherwise.

     Section 3.5 Partial Indemnity. If Indemnitee is entitled under any provision of this Agreement to indemnification by the Company for some or a portion of the Expenses, judgments, fines, penalties, and amounts paid in settlement of a Claim or Proceeding but not, however, for all of the total amount thereof, the Company shall nevertheless indemnify Indemnitee for the portion thereof to which Indemnitee is entitled. Moreover, notwithstanding any other provision of this Agreement, to the extent that Indemnitee has been successful on the merits or otherwise in defense of any or all Claims or Proceedings, or in defense of any issue or matter therein, including dismissal without prejudice, Indemnitee shall be indemnified against all Expenses incurred in connection therewith.

ARTICLE IV

Procedure for Determination of Entitlement
to Indemnification

     Section 4.1 Request by Indemnitee. To obtain indemnification under this Agreement, Indemnitee shall submit to the Company a written request, including therein or therewith such documentation and information as is reasonably available to Indemnitee and is reasonably necessary to determine whether and to what extent Indemnitee is entitled to indemnification. The Secretary or an Assistant Secretary of the Company shall, promptly upon receipt of such a request for indemnification, advise the Board in writing that Indemnitee has requested indemnification.

     Section 4.2 Determination of Request. Upon written request by Indemnitee for indemnification pursuant to the first sentence of Section 4.1 hereof, a determination, if required by applicable law, with respect to whether Indemnitee is permitted under applicable law to be indemnified shall be made in accordance with the terms of Section 4.5, in the specific case as follows:

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     (a) If a Potential Change in Control or a Change in Control shall have occurred, by Independent Counsel (selected in accordance with Section 4.3) in a written opinion to the Board and Indemnitee, unless Indemnitee shall request that such determination be made by the Board, or a committee of the Board, in which case by the person or persons or in the manner provided for in clause (i) or (ii) of paragraph (b) below; or

     (b) If a Potential Change in Control or a Change in Control shall not have occurred, (i) by the Board by a majority vote of the Disinterested Directors even though less than a quorum of the Board, or (ii) by a majority vote of a committee solely of two or more Disinterested Directors designated to act in the matter by a majority vote of all Disinterested Directors even though less than a quorum of the Board, or (iii) by Independent Counsel selected by the Board or a committee of the Board by a vote as set forth in clauses (i) or (ii) of this paragraph (b), or if such vote is not obtainable or such a committee cannot be established, by a majority vote of all directors, or (iv) if Indemnitee and the Company agree, by the stockholders of the Company in a vote that excludes the shares held by directors who are not Disinterested Directors.

If it is so determined that Indemnitee is permitted to be indemnified under applicable law, payment to Indemnitee shall be made within 10 days after such determination. Nothing contained in this Agreement shall require that any determination be made under this Section 4.2 prior to the disposition or conclusion of a Claim or Proceeding against Indemnitee; provided, however, that Expense Advances shall continue to be made by the Company pursuant to, and to the extent required by, the provisions of Article III. Indemnitee shall cooperate with the person or persons making such determination with respect to Indemnitee’s entitlement to indemnification, including providing to such person upon reasonable advance request any documentation or information that is not privileged or otherwise protected from disclosure and that is reasonably available to Indemnitee and reasonably necessary to such determination. Any costs or expenses (including attorneys’ fees and disbursements) incurred by Indemnitee in so cooperating with the person or persons making such determination shall be borne by the Company (irrespective of the determination as to Indemnitee’s entitlement to indemnification), and the Company shall indemnify and hold harmless Indemnitee therefrom.

     Section 4.3 Independent Counsel. If a Potential Change in Control or a Change in Control shall not have occurred and the determination of entitlement to indemnification is to be made by Independent Counsel, the Independent Counsel shall be selected by (a) a majority vote of the Disinterested Directors, even though less than a quorum of the Board or (b) if there are no Disinterested Directors, by a majority vote of the Board, and the Company shall give written notice to Indemnitee, within 10 days after receipt by the Company of Indemnitee’s request for indemnification, specifying the identity and address of the Independent Counsel so selected. If a Potential Change in Control or a Change in Control shall have occurred and the determination of entitlement to indemnification is to be made by Independent Counsel, the Independent Counsel shall be selected by Indemnitee, and Indemnitee shall give written notice to the Company, within 10 days after submission of Indemnitee’s request for indemnification, specifying the identity and address of the Independent Counsel so selected (unless Indemnitee shall request that such

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selection be made by the Disinterested Directors or a committee of the Board, in which event the Company shall give written notice to Indemnitee within 10 days after receipt of Indemnitee’s request for the Board or a committee of the Disinterested Directors to make such selection, specifying the identity and address of the Independent Counsel so selected). In either event, (i) such notice to Indemnitee or the Company, as the case may be, shall be accompanied by a written affirmation of the Independent Counsel so selected that it satisfies the requirements of the definition of “Independent Counsel” in Article I and that it agrees to serve in such capacity and (ii) Indemnitee or the Company, as the case may be, may, within seven days after such written notice of selection shall have been given, deliver to the Company or to Indemnitee, as the case may be, a written objection to such selection. Any objection to selection of Independent Counsel pursuant to this Section 4.3 may be asserted only on the ground that the Independent Counsel so selected does not meet the requirements of the definition of “Independent Counsel” in Article I, and the objection shall set forth with particularity the factual basis of such assertion. If such written objection is timely made, the Independent Counsel so selected may not serve as Independent Counsel unless and until a court of competent jurisdiction (the “Court”) has determined that such objection is without merit. In the event of a timely written objection to a choice of Independent Counsel, the party originally selecting the Independent Counsel shall have seven days to make an alternate selection of Independent Counsel and to give written notice of such selection to the other party, after which time such other party shall have five days to make a written objection to such alternate selection. If, within 30 days after submission of Indemnitee’s request for indemnification pursuant to Section 4.1, no Independent Counsel shall have been selected and not objected to, either the Company or Indemnitee may petition the Court for resolution of any objection that shall have been made by the Company or Indemnitee to the other’s selection of Independent Counsel and/or for the appointment as Independent Counsel of a person selected by the Court or by such other person as the Court shall designate, and the person with respect to whom an objection is so resolved or the person so appointed shall act as Independent Counsel under Section 4.2. The Company shall pay any and all reasonable fees and expenses incurred by such Independent Counsel in connection with acting pursuant to Section 4.2, and the Company shall pay all reasonable fees and expenses incident to the procedures of this Section 4.3, regardless of the manner in which such Independent Counsel was selected or appointed. Upon the due commencement of any judicial proceeding or arbitration pursuant to Section 5.1, Independent Counsel shall be discharged and relieved of any further responsibility in such capacity (subject to the applicable standards of professional conduct then prevailing).

     Section 4.4 Establishment of a Trust. In the event of a Potential Change in Control or a Change in Control, the Company shall, upon written request by Indemnitee, create a trust for the benefit of Indemnitee (the “Trust”) and from time to time upon written request of Indemnitee shall fund the Trust in an amount sufficient to satisfy any and all Expenses reasonably anticipated at the time of each such request to be incurred in connection with investigating, preparing for, and defending any Claim, and any and all judgments, fines, penalties, and settlement amounts of any and all Claims from time to time actually paid or claimed, reasonably anticipated, or proposed to be paid. The amount to be deposited in the Trust pursuant to the foregoing funding obligation shall be determined by the Independent Counsel (or other person(s) making the determination of whether Indemnitee is permitted to be indemnified by applicable law). The terms of the Trust shall provide that, upon a Change in Control, (i) the Trust shall not

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be revoked or the principal thereof invaded, without the written consent of Indemnitee; (ii) the trustee of the Trust shall advance, within ten business days of a request by Indemnitee, any and all reasonable Expenses to Indemnitee, any required determination concerning the reasonableness of the Expenses to be made by the Independent Counsel (and Indemnitee hereby agrees to reimburse the Trust under the circumstances in which Indemnitee would be required to reimburse the Company for Expenses Advances under Section 3.3 of this Agreement); (iii) the Trust shall continue to be funded by the Company in accordance with the funding obligation set forth above; (iv) the trustee of the Trust shall promptly pay to Indemnitee all amounts for which Indemnitee shall be entitled to indemnification pursuant to this Agreement; and (v) all unexpended funds in the Trust shall revert to the Company upon a final determination by the Independent Counsel or a court of competent jurisdiction, as the case may be, that Indemnitee has been fully indemnified under the terms of this Agreement. The trustee of the Trust shall be chosen by Indemnitee and shall be an institution that is not affiliated with Indemnitee. Nothing in this Section 4.4 shall relieve the Company of any of its obligations under this Agreement.

     Section 4.5 Presumptions and Effect of Certain Proceedings.

     (a) Indemnitee shall be presumed to be entitled to indemnification under this Agreement upon submission of a request for indemnification under Section 4.1, and the Company shall have the burden of proof in overcoming that presumption in reaching a determination contrary to that presumption. Such presumption shall be used by Independent Counsel (or other person or persons determining entitlement to indemnification) as a basis for a determination of entitlement to indemnification unless the Company provides information sufficient to overcome such presumption by clear and convincing evidence or unless the investigation, review and analysis of Independent Counsel (or such other person or persons) convinces Independent Counsel by clear and convincing evidence that the presumption should not apply.

     (b) If the person or persons empowered or selected under Article IV of this Agreement to determine whether Indemnitee is entitled to indemnification shall not have made a determination within 60 days after receipt by the Company of the request by Indemnitee therefor, the requisite determination of entitlement to indemnification shall be deemed to have been made and Indemnitee shall be entitled to such indemnification; provided, however, that such 60-day period may be extended for a reasonable time, not to exceed an additional 30 days, if the person making the determination with respect to entitlement to indemnification in good faith requires such additional time for the obtaining or evaluating of documentation and/or information relating to such determination; and provided, further, that the 60-day limitation set forth in this Section 4.5(b) shall not apply and such period shall be extended as necessary (i) if within 30 days after receipt by the Company of the request for indemnification under Section 4.1 Indemnitee and the Company have agreed, and the Board has resolved to submit such determination to the stockholders of the Company pursuant to Section 4.2(b) for their consideration at an annual meeting of stockholders to be held within 90 days after such agreement and such determination is made thereat, or a special meeting of stockholders is called within 30 days after such receipt for the purpose of making such determination,

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such meeting is held for such purpose within 60 days after having been so called and such determination is made thereat, or (ii) if the determination of entitlement to indemnification is to be made by Independent Counsel pursuant to Section 4.2(a) of this Agreement, in which case the applicable period shall be as set forth in Section 5.1(c).

     (c) The termination of any Proceeding or of any Claim, issue or matter by judgment, order, settlement (whether with or without court approval) or conviction, or upon a plea of nolo contendere or its equivalent, shall not (except as otherwise expressly provided in this Agreement) by itself adversely affect the rights of Indemnitee to indemnification or create a presumption that Indemnitee failed to meet any particular standard of conduct, that Indemnitee had any particular belief, or that a court has determined that indemnification is not permitted by applicable law. Indemnitee shall be deemed to have been found liable in respect of any Claim, issue or matter only after Indemnitee shall have been so adjudged by the Court after exhaustion of all appeals therefrom.

ARTICLE V

Certain Remedies of Indemnitee

     Section 5.1 Indemnitee Entitled to Adjudication in an Appropriate Court. If (a) a determination is made pursuant to Article IV that Indemnitee is not entitled to indemnification under this Agreement; (b) there has been any failure by the Company to make timely payment or advancement of any amounts due hereunder (including, without limitation, any Expense Advances); or (c) the determination of entitlement to indemnification is to be made by Independent Counsel pursuant to Section 4.2 and such determination shall not have been made and delivered in a written opinion within 90 days after the latest of (i) such Independent Counsel’s being appointed, (ii) the overruling by the Court of objections to such counsel’s selection, or (iii) expiration of all periods for the Company or Indemnitee to object to such counsel’s selection, Indemnitee shall be entitled to commence an action seeking an adjudication in the Court of Indemnitee’s entitlement to such indemnification or advancements due hereunder, including, without limitation, Expense Advances. Alternatively, Indemnitee, at Indemnitee’s option, may seek an award in arbitration to be conducted by a single arbitrator pursuant to the commercial arbitration rules of the American Arbitration Association. Indemnitee shall commence such action seeking an adjudication or an award in arbitration within 180 days following the date on which Indemnitee first has the right to commence such action pursuant to this Section 5.1, or such right shall expire. The Company agrees not to oppose Indemnitee’s right to seek any such adjudication or award in arbitration.

     Section 5.2 Adverse Determination Not to Affect any Judicial Proceeding. If a determination shall have been made pursuant to Article IV that Indemnitee is not entitled to indemnification under this Agreement, any judicial proceeding or arbitration commenced pursuant to this Article V shall be conducted in all respects as a de novo trial or arbitration on the merits, and Indemnitee shall not be prejudiced by reason of such initial adverse determination. In any judicial proceeding or arbitration commenced pursuant to this Article V, Indemnitee shall

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be presumed to be entitled to indemnification or advancement of Expenses, as the case may be, under this Agreement and the Company shall have the burden of proof in overcoming such presumption and to show by clear and convincing evidence that Indemnitee is not entitled to indemnification or advancement of Expenses, as the case may be.

     Section 5.3 Company Bound by Determination Favorable to Indemnitee in any Judicial Proceeding or Arbitration. If a determination shall have been made or deemed to have been made pursuant to Article IV that Indemnitee is entitled to indemnification, the Company shall be irrevocably bound by such determination in any judicial proceeding or arbitration commenced pursuant to this Article V, and shall be precluded from asserting that such determination has not been made or that the procedure by which such determination was made is not valid, binding and enforceable.

     Section 5.4 Company Bound by the Agreement. The Company shall be precluded from asserting in any judicial proceeding or arbitration commenced pursuant to this Article V that the procedures and presumptions of this Agreement are not valid, binding and enforceable and shall stipulate in any such court or before any such arbitrator that the Company is bound by all the provisions of this Agreement.

ARTICLE VI

Contribution

     Section 6.1 Contribution Payment. To the extent the indemnification provided for under any provision of this Agreement is determined (in the manner hereinabove provided) not to be permitted under applicable law, then in the event Indemnitee was, is, or becomes a party to or witness or other participant in, or is threatened to be made a party to or witness or other participant in, a Proceeding by reason of (or arising in part out of) Indemnitee’s Corporate Status, the Company, in lieu of indemnifying Indemnitee, shall contribute to the amount of any and all Expenses, judgments, fines, or penalties assessed against or incurred or paid by Indemnitee on account of such Proceeding and any and all amounts paid in settlement of that Proceeding (including all interest, assessments, and other charges paid or payable in connection with or in respect of such Expenses, judgments, fines, penalties, or amounts paid in settlement) for which such indemnification is not permitted (“Contribution Amounts”), in such proportion as is appropriate to reflect the relative fault with respect to the subject matter of the Proceeding giving rise to the Contribution Amounts of Indemnitee, on the one hand, and of the Company and any and all other parties (including officers and directors of the Company other than Indemnitee) who may be at fault with respect to such matter (collectively, including the Company, the “Third Parties”) on the other hand.

     Section 6.2 Relative Fault. The relative fault of the Third Parties and Indemnitee shall be determined (i) by reference to the relative fault of Indemnitee as determined by the court or other governmental agency assessing the Contribution Amounts or (ii) to the extent such court or other governmental agency does not apportion relative fault, by the Independent Counsel (or such other party which makes a determination under Article IV) after giving effect to, among

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other things, the relative intent, knowledge, access to information, and opportunity to prevent or correct the subject matter of the Proceedings and other relevant equitable considerations of each party. The Company and Indemnitee agree that it would not be just and equitable if contribution pursuant to this Section 6.2 were determined by pro rata allocation or by any other method of allocation which does take account of the equitable considerations referred to in this Section 6.2.

ARTICLE VII

Miscellaneous

     Section 7.1 Non-Exclusivity. The rights of Indemnitee to receive indemnification and advancement of Expenses under this Agreement shall be in addition to, and shall not be deemed exclusive of, any other rights Indemnitee shall under the DGCL or other applicable law, the charter or bylaws of the Company, any other agreement, vote of stockholders or a resolution of directors, or otherwise. No amendment or alteration of the charter or bylaws of the Company or any provision thereof shall adversely affect Indemnitee’s rights hereunder and such rights shall be in addition to any rights Indemnitee may have under the charter, bylaws and the DGCL or other applicable law. To the extent that there is a change in the DGCL or other applicable law (whether by statute or judicial decision) that allows greater indemnification by agreement than would be afforded currently under the Company’s charter or bylaws and this Agreement, it is the intent of the parties hereto that Indemnitee shall enjoy by virtue of this Agreement the greater benefit so afforded by such change. Any amendment, alteration or repeal of the DGCL that adversely affects any right of Indemnitee shall be prospective only and shall not limit or eliminate any such right with respect to any Proceeding involving any occurrence or alleged occurrence of any action or omission to act that took place before such amendment or repeal.

     Section 7.2 Insurance and Subrogation.

     (a) To the extent that the Company maintains an insurance policy or policies providing liability insurance for directors, officers, employees, agents or fiduciaries of the Company or for individuals serving at the request of the Company as directors, officers, partners, venturers, proprietors, trustees, employees, agents, fiduciaries or similar functionaries of another foreign or domestic corporation, partnership, joint venture, sole proprietorship, trust, employee benefit plan or other enterprise, Indemnitee shall be covered by such policy or policies in accordance with its or their terms to the maximum extent of the coverage available for any such director, officer, employee, agent or fiduciary under such policy or policies.

     (b) In the event of any payment by the Company under this Agreement, the Company shall be subrogated to the extent of such payment to all of the rights of recovery of Indemnitee, who shall execute all papers required and take all action necessary to secure such rights, including execution of such documents as are necessary to enable the Company to bring suit to enforce such rights.

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     (c) The Company shall not be liable under this Agreement to make any payment of amounts otherwise indemnifiable hereunder if and to the extent that Indemnitee has otherwise actually received such payment under the Company’s charter or bylaws or any insurance policy, contract, agreement or otherwise.

     (d) If Indemnitee is a director of the Company, the Company will advise the Board of any proposed material reduction in the coverage for Indemnitee to be provided by the Company’s directors’ and officers’ liability insurance policy and will not effect such a reduction with respect to Indemnitee without the prior approval of at least 80% of the Independent Directors of the Company.

     (e) If Indemnitee is a director of the Company during the term of this Agreement and if Indemnitee ceases to be a director of the Company for any reason, the Company shall procure a run-off directors’ and officers’ liability insurance policy with respect to claims arising from facts or events that occurred before the time Indemnitee ceased to be a director of the Company and covering Indemnitee, which policy, without any lapse in coverage, will provide coverage for a period of six years after the time Indemnitee ceased to be a director of the Company and will provide coverage (including amount and type of coverage and size of deductibles) that are substantially comparable to the Company’s directors’ and officers’ liability insurance policy that was most protective of Indemnitee in the 12 months preceding the time Indemnitee ceased to be a director of the Company; provided, however, that:

     (i) this obligation shall be suspended during the period immediately following the time Indemnitee ceases to be a director of the Company if and only so long as the Company has a directors’ and officers’ liability insurance policy in effect covering Indemnitee for such claims that, if it were a run-off policy, would meet or exceed the foregoing standards, but in any event this suspension period shall end when a Change in Control occurs; and

     (ii) no later than the end of the suspension period provided in the preceding clause (i) (whether because of failure to have a policy meeting the foregoing standards or because a Change in Control occurs), the Company shall procure a run-off directors’ and officers’ liability insurance policy meeting the foregoing standards and lasting for the remainder of the six-year period.

     (f) Notwithstanding the preceding clause (e) including the suspension provisions therein, if Indemnitee ceases to be an officer or director of the Company in connection with a Change in Control or at or during the one-year period following the occurrence of a Change in Control, the Company shall procure a run-off directors’ and officers’ liability insurance policy covering Indemnitee and meeting the foregoing standards in clause (e) and lasting for a six-year period upon the Indemnitee’s ceasing to be an officer or director of the Company in such circumstances.

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     Section 7.3 Self Insurance of the Company; Other Arrangements. The parties hereto recognize that the Company may, but except as provided in Section 7.2(d) and Section 7.2(e) is not required to, procure or maintain insurance or other similar arrangements, at its expense, to protect itself and any person, including Indemnitee, who is or was a director, officer, employee, agent or fiduciary of the Company or who is or was serving at the request of the Company as a director, officer, partner, venturer, proprietor, trustee, employee, agent, fiduciary or similar functionary of another foreign or domestic corporation, partnership, joint venture, sole proprietorship, trust, employee benefit plan or other enterprise against any expense, liability or loss asserted against or incurred by such person, in such a capacity or arising out of the person’s status as such a person, whether or not the Company would have the power to indemnify such person against such expense or liability or loss.

     Except as provided in Section 7.2(d) and Section 7.2(e), in considering the cost and availability of such insurance, the Company (through the exercise of the business judgment of its directors and officers) may, from time to time, purchase insurance which provides for certain (i) deductibles, (ii) limits on payments required to be made by the insurer, or (iii) coverage which may not be as comprehensive as that previously included in insurance purchased by the Company or its predecessors. The purchase of insurance with deductibles, limits on payments and coverage exclusions, even if in the best interest of the Company, may not be in the best interest of Indemnitee. As to the Company, purchasing insurance with deductibles, limits on payments and coverage exclusions is similar to the Company’s practice of self-insurance in other areas. In order to protect Indemnitee who would otherwise be more fully or entirely covered under such policies, the Company shall, to the maximum extent permitted by applicable law, indemnify and hold Indemnitee harmless to the extent (i) of such deductibles, (ii) of amounts exceeding payments required to be made by an insurer, or (iii) of amounts that prior policies of directors’ and officers’ liability insurance held by the Company or its predecessors have provided for payment to Indemnitee, if by reason of Indemnitee’s Corporate Status Indemnitee is or is threatened to be made a party to any Proceeding. The obligation of the Company in the preceding sentence shall be without regard to whether the Company would otherwise be required to indemnify such officer or director under the other provisions of this Agreement, or under any law, agreement, vote of stockholders or directors or other arrangement. Without limiting the generality of any provision of this Agreement, the procedures in Article IV hereof shall, to the extent applicable, be used for determining entitlement to indemnification under this Section 7.3.

     Section 7.4 Certain Settlement Provisions. The Company shall have no obligation to indemnify Indemnitee under this Agreement for amounts paid in settlement of a Proceeding or Claim without the Company’s prior written consent. The Company shall not settle any Proceeding or Claim in any manner that would impose any fine or other obligation on Indemnitee without Indemnitee’s prior written consent. Neither the Company nor Indemnitee shall unreasonably withhold their consent to any proposed settlement.

     Section 7.5 Duration of Agreement. This Agreement shall continue for so long as Indemnitee serves as a director, officer, employee, agent or fiduciary of the Company or, at the request of the Company, as a director, officer, partner, venturer, proprietor, trustee, employee, agent, fiduciary or similar functionary of another foreign or domestic corporation, partnership,

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joint venture, sole proprietorship, trust, employee benefit plan or other enterprise, and thereafter shall survive until and terminate upon the later to occur of: (a) the expiration of 20 years after the latest date that Indemnitee shall have ceased to serve in any such capacity; (b) the final termination of all pending Proceedings in respect of which Indemnitee is granted rights of indemnification or advancement of Expenses hereunder and of any proceeding commenced by Indemnitee pursuant to Article IV relating thereto; or (c) the expiration of all statutes of limitation applicable to possible Claims arising out of Indemnitee’s Corporate Status.

     Section 7.6 Notice by Each Party. Indemnitee shall promptly notify the Company in writing upon being served with any summons, citation, subpoena, complaint, indictment, information or other document or communication relating to any Proceeding or Claim for which Indemnitee may be entitled to indemnification or advancement of Expenses hereunder; provided, however, that any failure of Indemnitee to so notify the Company shall not adversely affect Indemnitee’s rights under this Agreement except to the extent the Company shall have been materially prejudiced as a direct result of such failure. The Company shall promptly notify Indemnitee in writing as to the pendency of any Proceeding or Claim that may involve a claim against Indemnitee for which Indemnitee may be entitled to indemnification or advancement of Expenses hereunder.

     Section 7.7 Amendment. This Agreement may not be modified or amended except by a written instrument executed by or on behalf of each of the parties hereto.

     Section 7.8 Waivers. The observance of any term of this Agreement may be waived (either generally or in a particular instance and either retroactively or prospectively) by the party entitled to enforce such term only by a writing signed by the party against which such waiver is to be asserted. Unless otherwise expressly provided herein, no delay on the part of any party hereto in exercising any right, power or privilege hereunder shall operate as a waiver thereof, nor shall any waiver on the part of any party hereto of any right, power or privilege hereunder operate as a waiver of any other right, power or privilege hereunder nor shall any single or partial exercise of any right, power or privilege hereunder preclude any other or further exercise thereof or the exercise of any other right, power or privilege hereunder.

     Section 7.9 Entire Agreement. This Agreement and the documents expressly referred to herein constitute the entire agreement between the parties hereto with respect to the matters covered hereby, and any other prior or contemporaneous oral or written understandings or agreements with respect to the matters covered hereby are expressly superseded by this Agreement.

     Section 7.10 Severability. If any provision of this Agreement (including any provision within a single section, paragraph or sentence) or the application of such provision to any Person or circumstance, shall be judicially declared to be invalid, unenforceable or void, such decision will not have the effect of invalidating or voiding the remainder of this Agreement or affect the application of such provision to other Persons or circumstances, it being the intent and agreement of the parties that this Agreement shall be deemed amended by modifying such provision to the extent necessary to render it valid, legal and enforceable while preserving its intent, or if such

16

modification is not possible, by substituting therefor another provision that is valid, legal and unenforceable and that achieves the same objective. Any such finding of invalidity or unenforceability shall not prevent the enforcement of such provision in any other jurisdiction to the maximum extent permitted by applicable law.

     Section 7.11 Notices. All notices and other communications hereunder shall be in writing and shall be deemed given upon (a) transmitter’s confirmation of a receipt of a facsimile transmission if during normal business hours of the recipient, otherwise on the next business day, (b) confirmed delivery of a standard overnight courier or when delivered by hand or (c) the expiration of five business days after the date mailed by certified or registered mail (return receipt requested), postage prepaid, to the parties at the following addresses (or at such other addresses for a party as shall be specified by like notice):

     If to the Company, to it at:

Pioneer Natural Resources Company
5205 North O’Connor Blvd.
Suite 900
Irving, Texas 75039-3746
Attn: Corporate Secretary
Facsimile: (972) 969-3552

     If to Indemnitee, to Indemnitee at:

1401 17th Street
Ste 1200
Denver, CO 80202

or to such other address or to such other individuals as any party shall have last designated by notice to the other parties. All notices and other communications given to any party in accordance with the provisions of this Agreement shall be deemed to have been given when delivered or sent to the intended recipient thereof in accordance with and as provided in the provisions of this Section 7.11.

     Section 7.12 Governing Law. This Agreement shall be construed in accordance with and governed by the laws of the State of Delaware without regard to the principles of conflict of laws.

     Section 7.13 Certain Construction Rules.

     (a) The article and section headings contained in this Agreement are for reference purposes only and shall not affect in any way the meaning or interpretation of this Agreement. As used in this Agreement, unless otherwise provided to the contrary, (1) all references to days shall be deemed references to calendar days and (2) any reference to a “Section” or “Article” shall be deemed to refer to a section or article of this

17

Agreement. The words “hereof,” “herein” and “hereunder” and words of similar import referring to this Agreement refer to this Agreement as a whole and not to any particular provision of this Agreement. Whenever the words “include,” “includes” or “including” are used in this Agreement, they shall be deemed to be followed by the words “without limitation.” Unless otherwise specifically provided for herein, the term “or” shall not be deemed to be exclusive. Whenever the context may require, any pronoun used in this Agreement shall include the corresponding masculine, feminine or neuter forms, and the singular form of nouns, pronouns and verbs shall include the plural and vice versa.

     (b) For purposes of this Agreement, references to “other enterprises” shall include employee benefit plans; references to “fines” shall include any excise taxes assessed on a person with respect to any employee benefit plan; references to “serving at the request of the Company” shall include any service as a director, officer, employee or agent of the Company which imposes duties on, or involves services by, such director, nominee, officer, employee or agent with respect to an employee benefit plan, its participants or beneficiaries; and a person who acted in good faith and in a manner the person reasonably believed to be in the interests of the participants and beneficiaries of an employee benefit plan shall be deemed to have acted in a manner “not opposed to the best interest of the Company” for purposes of this Agreement and the DGCL.

     Section 7.14 Counterparts. This Agreement may be executed in two or more counterparts, each of which shall be deemed to be an original and all of which together shall be deemed to be one and the same instrument, notwithstanding that both parties are not signatories to the original or same counterpart.

     Section 7.15 Certain Persons Not Entitled to Indemnification. Notwithstanding any other provision of this Agreement (but subject to Section 7.1), Indemnitee shall not be entitled to indemnification or advancement of Expenses pursuant to the terms of this Agreement with respect to any Proceeding or any Claim, issue or matter therein, brought or made by Indemnitee against the Company, except as specifically provided in Article III, Article IV or Section 7.3. In addition, the Company shall not be obligated pursuant to the terms of this Agreement:

     (a) To indemnify Indemnitee if (and to the extent that) a final decision by a court or arbitration body having jurisdiction in the matter shall determine that such indemnification is not lawful; or

     (b) To indemnify Indemnitee for the payment to the Company of profits pursuant to Section 16(b) of the Exchange Act, or Expenses incurred by Indemnitee for Proceedings in connection with such payment under Section 16(b) of the Exchange Act.

     Section 7.16 Indemnification for Negligence, Gross Negligence, etc. Without limiting the generality of any other provision hereunder, it is the express intent of this Agreement that Indemnitee be indemnified and Expenses be advanced regardless of Indemnitee’s acts of negligence, gross negligence, intentional or willful misconduct to the extent that indemnification

18

and advancement of Expenses is allowed pursuant to the terms of this Agreement and under applicable law.

     Section 7.17 Mutual Acknowledgments. Both the Company and Indemnitee acknowledge that in certain instances, applicable law (including applicable federal law that may preempt or override applicable state law) or public policy may prohibit the Company from indemnifying the directors, officers, employees, agents or fiduciaries of the Company under this Agreement or otherwise. For example, the Company and Indemnitee acknowledge that the U.S. Securities and Exchange Commission has taken the position that indemnification of directors, officers and controlling Persons of the Company for liabilities arising under federal securities laws is against public policy and, therefore, unenforceable. Indemnitee understands and acknowledges that the Company has undertaken or may be required in the future to undertake with the Securities and Exchange Commission to submit the question of indemnification to a court in certain circumstances for a determination of the Company’s right under public policy to indemnify Indemnitee. In addition, the Company and Indemnitee acknowledge that federal law prohibits indemnifications for certain violations of the Employee Retirement Income Security Act of 1974, as amended.

     Section 7.18 Enforcement. The Company agrees that its execution of this Agreement shall constitute a stipulation by which it shall be irrevocably bound in any court or arbitration in which a proceeding by Indemnitee for enforcement of Indemnitee’s rights hereunder shall have been commenced, continued or appealed, that its obligations set forth in this Agreement are unique and special, and that failure of the Company to comply with the provisions of this Agreement will cause irreparable and irremediable injury to Indemnitee, for which a remedy at law will be inadequate. As a result, in addition to any other right or remedy Indemnitee may have at law or in equity with respect to breach of this Agreement, Indemnitee shall be entitled to injunctive or mandatory relief directing specific performance by the Company of its obligations under this Agreement. The Company agrees not to seek, and agrees to waive any requirement for the securing or posting of, a bond in connection with Indemnitee’s seeking or obtaining such relief.

     Section 7.19 Successors and Assigns. All of the terms and provisions of this Agreement shall be binding upon, shall inure to the benefit of and shall be enforceable by the parties hereto and their respective successors, assigns, heirs, executors, administrators, legal representatives.

     Section 7.20 Period of Limitations. No legal action shall be brought and no cause of action shall be asserted by or on behalf of the Company or any affiliate of the Company against Indemnitee or Indemnitee’s spouse, heirs, executors, or personal or legal representatives after the expiration of one year from the date of accrual of that cause of action, and any claim or cause of action of the Company or its affiliate shall be extinguished and deemed released unless asserted by the timely filing of a legal action within that one-year period; provided, however, that for any claim based on Indemnitee’s breach of fiduciary duties to the Company or its stockholders, the period set forth in the preceding sentence shall be three years instead of one year; and provided, further, that, if any shorter period of limitations is otherwise applicable to any such cause of action, the shorter period shall govern.

19

     IN WITNESS WHEREOF, this Agreement has been duly executed and delivered to be effective as of the date first above written.

PIONEER NATURAL RESOURCES COMPANY
By:
Name:	Mark S. Berg
Title:	Executive Vice President and General Counsel
INDEMNITEE:

20

EX-10.4

Exhibit 10.4

First Amendment

TO

AMENDED AND RESTATED CREDIT AGREEMENT

dated as of

November 20, 2007

among

PIONEER NATURAL RESOURCES COMPANY,
as the Borrower

JPMORGAN CHASE BANK, N.A.
as Administrative Agent

and
The Lenders Party Hereto

     THIS FIRST AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT (this “First Amendment”) dated as of November 20, 2007, among Pioneer Natural Resources Company, a Delaware corporation, as the Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the Lenders party hereto,.

R E C I T A L S

     A. The Borrower, the Administrative Agent, and the Lenders party thereto are parties to that certain Amended and Restated Credit Agreement dated as of April 11, 2007 (the “Credit Agreement”), pursuant to which the Lenders have made certain credit available to and on behalf of the Borrower.

     B. The Borrower has requested and the Lenders have agreed to amend certain provisions of the Credit Agreement.

     C. NOW, THEREFORE, in consideration of the premises and the mutual covenants herein contained, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

     Section 1. Defined Terms. Each capitalized term which is defined in the Credit Agreement, but which is not defined in this First Amendment, shall have the meaning ascribed such term in the Credit Agreement. Unless otherwise indicated, all section references in this First Amendment refer to sections of the Credit Agreement.

     Section 2. Amendments to Credit Agreement.

     2.1 Amendments to Section 1.01.

     (a) The definition of “Agreement” in Section 1.01 of the Credit Agreement is hereby amended in its entirety to read as follows:

     “Agreement” means this Credit Agreement, as amended by the First Amendment, as the same may from time to time be amended, modified, supplemented or restated.

     (b) The definition of “PV” in Section 1.01 of the Credit Agreement is hereby amended in its entirety to read as follows:

     “PV” means the calculation of the net present value of projected future cash flows from Proved Reserves based upon the most recently delivered Reserve Information (using the arithmetical average of the discount rate and customary price deck of JPMorgan Chase Bank, N.A. and Wachovia Bank, National Association as of the effective date of such Reserve Information, giving effect to the Borrower’s hedging arrangements and long-term contracts, and using future capital cost assumptions proposed by the Borrower and reasonably acceptable to JPMorgan Chase Bank, N.A. and Wachovia Bank, National Association). For purposes of calculating the PV, a maximum

2

of 35% of the PV value will be included from Proved Reserves that are not proved developed producing reserves. If, during any period between the effective dates of the Reserve Information, the aggregate fair market value, in the reasonable opinion of the Borrower, of Oil and Gas Properties disposed of or purchased by the Borrower and the Restricted Subsidiaries shall exceed $100,000,000, then the PV for such period shall be reduced or increased, as the case may be, from time to time, by an amount equal to the value assigned such Oil and Gas Properties in the most recent calculation of the PV for such period (or if no value was assigned, by an amount agreed to by the Borrower, JPMorgan Chase Bank, N.A. and Wachovia Bank, National Association). PV shall reflect the deferred revenue with respect to production payments included in Total Debt, at a value that is equal to the amount of deferred revenues so included in Total Debt.

     (c) The following definition is hereby added in Section 1.01 the Credit Agreement where alphabetically appropriate to read as follows:

     “First Amendment” means that certain First Amendment to Credit Agreement dated as November 20, 2007 among the Borrower, the Administrative Agent and the Lenders party thereto.

     “Reserve Information” means, the Reserve Report and internal reserve reports prepared as of March 31, June 30 and September 30 of each year by engineers who are employees of the Borrower.

     2.2 Amendment to Section 5.0l(f). Section 5.01(f) of the of the Credit Agreement is hereby amended in its entirety to read as follows:

(f) prior to the occurrence of an Investment Grade Date, (i) by March 31 of each year, the Borrower shall furnish to the Administrative Agent and to each Lender a Reserve Report, which Reserve Report shall be dated as of the immediately preceding December 31 and shall set forth the Proved Reserves attributable to all or substantially all of the Oil and Gas Properties then owned by the Borrower and its Restricted Subsidiaries and the PV attributable thereto as contemplated in the definition of Reserve Report and (ii) by May 15, August 15, and November 15 of each year, commencing November 15, 2007, the Borrower shall furnish to the Administrative Agent and to each Lender the applicable Reserve Information prepared as of the immediately preceding March 31, June 30, and September 30, respectively, and shall set forth the Proved Reserves attributable to all or substantially all of the Oil and Gas Properties then owned by the Borrower and its Restricted Subsidiaries and the PV attributable thereto; after the occurrence of an Investment Grade Date, this Section 5.01(f) will be deleted permanently;

     2.3 Waiver of Section 5.01(f).

     (a) The Borrower’s failure to comply with Section 5.01(f) because of failure to deliver the Reserve Information due on November 15, 2007 is hereby waived. Such Reserve Information was delivered on November 16, 2007.

3

     (b) The express waiver set forth in this Section 2.3 is limited to the extent described herein and shall not be construed to be a consent to or a permanent waiver of any terms, provisions, covenants, warranties or agreements contained in the Credit Agreement or in any of the other Loan Documents, unless expressly provided so herein. The Required Lenders reserve the right to exercise any rights and remedies available to them and to the Lenders in connection with any present or future defaults with respect to the Credit Agreement or any other provision of any Loan Document.

     Section 3. Conditions Precedent. The effectiveness of this First Amendment is subject to the receipt by the Administrative Agent of the following documents and satisfaction of the other conditions specified in this Section 3:

     3.1 Counterparts of First Amendment. The Administrative Agent shall have received from the Borrower and the Required Lenders multiple counterparts (in such number as may be requested by the Administrative Agent) of this First Amendment signed on behalf of each such party.

     3.2 No Default. No Default shall have occurred and be continuing as of the date hereof, after giving effect to the terms of this First Amendment.

     Section 4. Miscellaneous.

     4.1 Confirmation. The provisions of the Credit Agreement, as amended by this First Amendment, shall remain in full force and effect in accordance with its terms following the effectiveness of this First Amendment.

     4.2 Ratification and Affirmation; Representations and Warranties. The Borrower hereby (a) represents and warrants to the Lenders that as of the date hereof, after giving effect to the terms of this First Amendment, (i) all of the representations and warranties contained in each Loan Document to which it is a party are true and correct, except to the extent any such representations and warranties are expressly limited to an earlier date, in which case, such representations and warranties shall continue to be true and correct in all material respects as of such specified earlier date, and (ii) no Default has occurred and is continuing.

     4.3 Loan Document. This First Amendment is a “Loan Document” as defined and described in the Credit Agreement and all of the terms and provisions of the Credit Agreement, as amended by this First Amendment, relating to Loan Documents shall apply hereto.

     4.4 Counterparts. This First Amendment may be executed by one or more of the parties hereto in any number of separate counterparts, and all of such counterparts taken together shall be deemed to constitute one and the same instrument. Delivery of this First Amendment by facsimile transmission shall be effective as delivery of a manually executed counterpart hereof.

     4.5 No Oral Agreement. This First Amendment, the Credit Agreement and the other Loan Documents executed in connection therewith represent the final agreement between the parties and may not be contradicted by evidence of prior, contemporaneous, or unwritten oral agreements of the parties. There are no subsequent oral agreements between the parties.

4

     4.6 GOVERNING LAW. THIS FIRST AMENDMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF TEXAS.

[SIGNATURES BEGIN NEXT PAGE]

5

     IN WITNESS WHEREOF, the parties hereto have caused this First Amendment to be duly executed as of the date first written above.

BORROWER:	PIONEER NATURAL RESOURCES COMPANY
	By: Name:	/s/ Richard P. Dealy Richard P. Dealy
	Title:	EVP & CFO

Signature Page to First Amendment to Amended and Restated Credit Agreement

JPMORGAN CHASE BANK, N.A.
as a Lender and as Administrative Agent
By: Name:	/s/ Kevin Utsey Kevin Utsey
Title:	Vice President

Signature Page to First Amendment to Amended and Restated Credit Agreement

LENDER:	Wachovia Bank, National Association
	By: Name:	/s/ Shannan Townsend Shannan Townsend
	Title:	Director

Signature Page to First Amendment to Amended and Restated Credit Agreement

LENDER:	BANK OF AMERICA, N.A.
	By: Name:	/s/ Ronald E. McKaig Ronald E. McKaig
	Title:	Senior Vice President

Signature Page to First Amendment to Amended and Restated Credit Agreement

LENDER:	DEUTSCHE BANK AG NEW YORK BRANCH as a Lender
	By: Name:	/s/ Marcus Tarkington Marcus Tarkington
	Title:	Director
	By: Name:	/s/ Rainer Meier Rainer Meier
	Title:	Vice President

Signature Page to First Amendment to Amended and Restated Credit Agreement

LENDER:	Wells Fargo Bank, NA
	By: Name:	/s/ David C. Brooks David C. Brooks
	Title:	Vice President

Signature Page to First Amendment to Amended and Restated Credit Agreement

LENDER:	UBS Loan Finance LLC Name of Lender
	By: Name:	/s/ Irja R. Otsa Irja R. Otsa
	Title:	Associate Director
	By: Name:	/s/ Mary E. Evans Mary E. Evans
	Title:	Associate Director

Signature Page to First Amendment to Amended and Restated Credit Agreement

LENDER:	BMO CAPITAL MARKETS FINANCING, INC.
	By: Name:	/s/ James V. Ducote James V. Ducote
	Title:	Director

Signature Page to First Amendment to Amended and Restated Credit Agreement

LENDER:	Calyon New York Branch
	Name of Lender
	By: Name:	/s/ Dennis E. Petito Dennis E. Petito
	Title:	Managing Director
	By: Name:	/s/ Michael D. Willis Michael D. Willis
	Title:	Director

Signature Page to First Amendment to Amended and Restated Credit Agreement

LENDER:	Citibank, N.A.
	By: Name:	/s/ Ashish Sethi Ashish Sethi
	Title:	Attorney-in-Fact

Signature Page to First Amendment to Amended and Restated Credit Agreement

LENDER:	THE ROYAL BANK OF SCOTLAND plc
	By: Name:	/s/ David Slye David Slye
	Title:	Vice President

Signature Page to First Amendment to Amended and Restated Credit Agreement

LENDER:
	DnB NOR Bank ASA
	By: Name:	/s/ Philip F. Kurpiewski Philip F. Kurpiewski
	Title:	Senior Vice President
	By: Name:	/s/ Asa Jemseby Rodgers Asa Jemseby Rodgers
	Title:	Vice President

Signature Page to First Amendment to Amended and Restated Credit Agreement

LENDER:	BNP PARIBAS Name of Lender
	By: Name:	/s/ Betsy Jocher Betsy Jocher
	Title:	Director
	By: Name:	/s/ Robert Long Robert Long
	Title:	Vice President

Signature Page to First Amendment to Amended and Restated Credit Agreement

LENDER:	Mizuho Corporate Bank, Ltd.
	Name of Lender
	By: Name:	/s/ Raymond Ventura Raymond Ventura
	Title:	Deputy General Manager

Signature Page to First Amendment to Amended and Restated Credit Agreement

LENDER:	Barclays Bank PLC
	By: Name:	/s/ Nicholas Bell Nicholas Bell
	Title:	Director

LENDER:	Fortis Capital Corp. Name of Lender
	By: Name:	/s/ Michele Jones Michele Jones
	Title:	Director
	By:	/s/ Darrell Holley
	Name:	Darrell Holley
	Title:	Managing Director

Signature Page to First Amendment to Amended and Restated Credit Agreement

LENDER:	GOLDMAN SACHS CREDIT PARTNERS L.P. Name of Lender
	By: Name:	/s/ Pedro Ramirez Pedro Ramirez
	Title:	Authorized Signatory

Signature Page to First Amendment to Amended and Restated Credit Agreement

LENDER:	SOCIETE GENERALE
	By: Name:	/s/ Elena Robciuc Elena Robciuc
	Title:	Director

Signature Page to First Amendment to Amended and Restated Credit Agreement

LENDER:	Toronto Dominion (Texas) LLC Name of Lender
	By: Name:	/s/ Jackie Barrett Jackie Barrett
	Title:	Authorized Signatory

Signature Page to First Amendment to Amended and Restated Credit Agreement

LENDER:	U.S. BANK NATIONAL ASSOCIATION Name of Lender
	By: Name:	/s/ Tyler Fauerbach Tyler Fauerbach
	Title:	Vice President

Signature Page to First Amendment to Amended and Restated Credit Agreement

LENDER:	Union Bank of California N.A.
	Name of Lender
	By: Name:	/s/ Sean M. Murphy Sean M. Murphy
	Title:	Senior Vice President

Signature Page to First Amendment to Amended and Restated Credit Agreement

LENDER:	Credit Suisse, Cayman Islands Branch
	By: Name:	/s/ Brian Caldwell Brian Caldwell
	Title:	Director
	By: Name:	/s/ Nupur Kumar Nupur Kumar
	Title:	Associate

Signature Page to First Amendment to Amended and Restated Credit Agreement

LENDER:	The Bank of Nova Scotia Name of Lender
	By: Name:	/s/ Andrew Ostrov Andrew Ostrov
	Title:	Director

Signature Page to First Amendment to Amended and Restated Credit Agreement

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in the following Registration Statements:

(1)	Registration Statement (Form S-3 No. 333-88478) of Pioneer Natural Resources Company and Pioneer Natural Resources USA, Inc. and in the related Prospectus,
(2)	Registration Statement (Form S-8 No. 333-136488) pertaining to the Pioneer Natural Resources Company Executive Deferred Compensation Plan,
(3)	Registration Statement (Form S-8 No. 333-136489) pertaining to the Pioneer Natural Resources Company 2006 Long-Term Incentive Plan,
(4)	Registration Statement (Form S-8 No. 333-136490) pertaining to the Pioneer Natural Resources Company Long-Term Incentive Plan,
(5)	Registration Statement (Form S-8 No. 333-119355) pertaining to the 2000 Stock Incentive Plan of Evergreen Resources, Inc., the Carbon Energy Corporation 1999 Stock Option Plan, and the Evergreen Resources, Inc. Initial Stock Option Plan,
(6)	Registration Statement (Form S-8 No. 333-88438) pertaining to the Pioneer Natural Resources Company Long-Term Incentive Plan,
(7)	Registration Statement (Form S-8 No. 333-39153) pertaining to the Pioneer Natural Resources Company Deferred Compensation Retirement Plan,
(8)	Registration Statement (Form S-8 No 333-39249) pertaining to the Pioneer Natural Resources USA, Inc. Profit Sharing 401(k) Plan,
(9)	Registration Statement (Form S-8 No. 333-35087) pertaining to the Pioneer Natural Resources Company Long-Term Incentive Plan,
(10)	Registration Statement (Form S-8 No. 333-35165) pertaining to the Pioneer Natural Resources Company Employee Stock Purchase Plan;

of our report dated 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) with respect to the consolidated financial statements of Pioneer Natural Resources Company, included in this Current Report on Form 8-K dated January 14, 2008.

/s/ Ernst & Young LLP

Dallas, Texas

January 14, 2008

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

     We hereby consent to the incorporation by reference in the Registration Statements (No. 333-35087, No. 333-35165, No. 333-39153, No. 333-39249, No. 333-88438, No. 333-119355, No. 333-136488, No. 333-136489 and No. 333-136490) on Form S-8 and (No. 333-88478) on Form S-3 of Pioneer Natural Resources Company (the “Company”) and the related Prospectuses of the reference of Netherland, Sewell & Associates, Inc. in the Current Report on Form 8-K filed on January 14, 2008, of the Company and its subsidiaries, filed with the Securities and Exchange Commission.

NETHERLAND, SEWELL & ASSOCIATES, INC.
By:	/s/  C.H. (Scott) Rees III
	C.H. (Scott) Rees III, P.E.
	Chairman and Chief Executive Officer

Dallas, Texas
January 14, 2008

EX-99.1

Exhibit 99.1

SELECTED FINANCIAL DATA

     In November 2007, the Company completed the divestiture of its Canadian assets, which are required to be presented as discontinued operations pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”). As a result, the following selected consolidated financial data has been recast from that presented in the Company’s Annual Report on Form 10-K for the year ended December 31, 2006 to present the results of operations of the Company’s Canadian assets as discontinued operations.

     The following selected consolidated financial data as of and for each of the five years ended December 31, 2006 for the Company should be read in conjunction with the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the “Financial Statements and Supplementary Data” included herein and the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2007, which reflects the classification of the divestiture of the Company’s Canadian assets as discontinued operations.

	Year Ended December 31, (a)
	2006			2005			2004			2003		2002
	(in millions, except per share data)
Statements of Operations Data:
Revenues and other income:
Oil and gas	$	1,458.9		$	1,338.9		$	962.2		$	675.8	$	510.7
Interest and other (b )		48.4			26.4			1.8			7.0		7.4
Gain (loss) on disposition of assets, net		(6.5	)		60.1			.3			1.4		3.2
		1,500.8			1,425.4			964.3			684.2		521.3
Costs and expenses:
Oil and gas production		349.1			309.7			206.1			145.7		136.0
Depletion, depreciation and amortization		314.1			267.8			208.3			149.2		133.5
Impairment of long-lived assets (c)		—			.6			39.7					—
Exploration and abandonments		250.2			153.8			94.3			77.8		42.2
General and administrative		116.6			110.1			69.5			51.1		40.3
Accretion of discount on asset retirement obligations		3.7			3.3			3.6			2.6		—
Interest		107.0			126.0			102.0			91.1		95.5
Hurricane activity, net (d)		32.0			39.8			—			—		—
Other (e)		36.9			80.8			25.5			11.3		28.4
		1,209.6			1,091.9			749.0			528.8		475.9
Income from continuing operations before income taxes and cumulative effect of changes in accounting principle		291.2			333.5			215.3			155.4		45.4
Income tax benefit (provision) (f)		(141.0	)		(149.2	)		(62.1	)		134.2		(.8	)
Income from continuing operations before cumulative effect of change in accounting principle		150.2			184.3			153.2			289.6		44.6
Income (loss) from discontinued operations, net of tax (a)		589.5			350.3			159.7			105.6		(17.9	)
Income (loss) before cumulative effect of change in accounting principle		739.7			534.6			312.9			395.2		26.7
Cumulative effect of change in accounting principle, net of tax (g)		—			—			—			15.4		—
Net income	$	739.7		$	534.6		$	312.9		$	410.6	$	26.7
Income from continuing operations before cumulative effect of change in accounting principle per share:
Basic	$	1.21		$	1.35		$	1.22		$	2.47	$	.40
Diluted	$	1.19		$	1.32		$	1.21		$	2.44	$	.39
Net income per share:
Basic	$	5.95		$	3.90		$	2.50		$	3.50	$	.24
Diluted	$	5.81		$	3.80		$	2.46		$	3.46	$	.23
Weighted average shares outstanding:
Basic		124.4			137.1			125.2			117.2		112.5
Diluted		127.6			141.4			127.5			118.5		114.3
Dividends declared per share	$	.25		$	.22		$	.20		$	—	$	—

1

	Year Ended December 31, (a)
	2006		2005		2004		2003		2002
	(in millions, except per share data)
Balance Sheet Data (as of December 31):
Total assets	$	7,355.4	$	7,329.2	$	6,733.5	$	3,951.6	$	3,455.1
Long-term obligations and minority interests	$	3,483.7	$	4,078.8	$	3,357.2	$	1,762.0	$	1,805.6
Total stockholders’ equity	$	2,984.7	$	2,217.1	$	2,831.8	$	1,759.8	$	1,374.9

(a)	Certain amounts for periods prior to January 1, 2006 have been reclassified (i) in accordance with SFAS 144 to reflect the results of operations of certain assets disposed of during 2005, 2006 and 2007 as discontinued operations, rather than as a component of continuing operations (see Notes B and V of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for additional discussion) and (ii) to conform with the current year presentation.
(b)	Interest and other income in 2006 and 2005 include $7.6 million and $14.2 million, respectively, of income associated with various business interruption insurance claims. See Notes M and U of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein.
(c)	During 2005 and 2004, the Company recorded $.6 million and $39.7 million of impairment charges for its Gabonese Olowi field because development of the discovery was canceled due to significant increases in projected field development costs. See Note S of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein.
(d)	Hurricane activity, net, for 2006 and 2005 includes $75.0 million and $39.8 million, respectively, of charges to reclaim and abandon the East Cameron facilities destroyed by Hurricane Rita. In 2006, the Company recorded $43.0 million of estimated insurance recoveries associated with debris removal. See Note U of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein.
(e)	Other expense for 2006, 2005, 2003 and 2002 includes losses on the early extinguishment of debt of $8.1 million, $26.0 million, $1.5 million and $22.3 million, respectively. Other expense for 2006, 2005, 2004, 2003 and 2002 includes $(10.6) million, $29.8 million, $4.2 million, $2.8 million and $1.6 million, respectively, of derivative ineffectiveness charges (credits). See Note O of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein.
(f)	Income tax benefit for 2003 includes a $197.7 million adjustment to reduce United States deferred tax asset valuation allowances.
(g)	Cumulative effect of change in accounting principle for 2003 relates to the adoption of SFAS No. 143 “Accounting for Asset Retirement Obligations” on January 1, 2003.

2

EX-99.2

Exhibit 99.2

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS

     In November 2007, the Company completed the divestiture of its Canadian assets, which are required to be presented as discontinued operations pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”). As a result, the Company has recast the Management’s Discussion and Analysis of Financial Condition and Results of Operations presented in its Annual Report on Form 10-K for the year ended December 31, 2006, to present the results of operations of the Company’s Canadian assets as discontinued operations. In addition, the Company has recast its Consolidated Financial Statements as of December 31, 2006 and 2005, and for each of the years in the three-year period ended December 31, 2006, and the notes thereto, to reflect the Company’s Canadian assets as discontinued operations, and the recast financial statements are included in this report. The following discussion should be read in conjunction with the recast financial statements included herein and the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2007, which reflects the classification of the sale of its Canadian assets as discontinued operations.

     Certain terms and conventions used in this Management’s Discussion and Analysis of Financial Condition and Results of Operations are defined in “Definitions of Certain Terms and Conventions Used Herein.”

Strategic Initiatives and Goals

     During 2006, the Company accomplished significant goals underlying the strategic initiatives established in 2005 to enhance shareholder value and investment returns. Together with other important accomplishments, the Company:

• Substantially completed a $1 billion share repurchase program, $640.7 million of which was completed during 2005 and $345.3 million of which was completed during 2006

• Completed the divestiture of the Company’s assets in Argentina for net proceeds of $669.6 million, resulting in a gain of $10.9 million

• Completed the divestiture of the Company’s assets in the deepwater Gulf of Mexico for net proceeds of $1.2 billion, resulting in a gain of $726.2 million

• Reduced higher-risk, higher-impact exploration spending to approximately five percent of the total capital spent in 2006

• Focused capital spending on lower-risk North American onshore development and extension drilling

• Produced 33.0 MMBOE in 2006 from continuing operations

• Increased the semiannual dividend to shareholders to $0.13 per share

Financial and Operating Performance

     Pioneer’s financial and operating performance for 2006 included the following highlights:

• Average daily sales volumes, on a BOE basis, decreased four percent in 2006 as compared to 2005, primarily due to a 126 percent increase in the delivery of VPP volumes. Excluding the delivery of the VPP volumes in 2006 (5.6 MMBOE) and 2005 (2.5 MMBOE), the Company’s United States production increased approximately four percent, which the Company believes provides a better understanding of the actual results of the Company’s 2006 United States drilling program excluding the increased VPP deliveries.

• Oil and gas revenues increased nine percent in 2006 as compared to 2005, primarily as a result of increases in worldwide oil and NGL prices.

• Net income increased 38 percent to $739.7 million ($5.81 per diluted share) in 2006 from $534.6 million ($3.80 per diluted share) in 2005, primarily on the strength of higher oil and NGL prices and gains on the sale of deepwater Gulf of Mexico and Argentine assets.

1

• Income from continuing operations decreased to $150.2 million ($1.19 per diluted share) for 2006, as compared to $184.3 million ($1.32 per diluted share) for 2005, primarily due to higher exploration and abandonment expenses in 2006.

• The Company recognized income from discontinued operations of $589.5 million ($4.62 per diluted share) during 2006, primarily attributable to the sale of deepwater Gulf of Mexico and Argentine assets and the 2007 sale of Canadian assets, as compared to income from discontinued operations of $350.3 million ($2.48 per diluted share) during 2005.

• Outstanding debt decreased to $1.5 billion at December 31, 2006 as compared to $2.1 billion at December 31, 2005, primarily due to the application of sales proceeds from the Company’s divestment of its assets in Argentina and the deepwater Gulf of Mexico.

• The Company’s debt-to-capitalization was 33 percent at December 31, 2006 as compared to 48 percent at December 31, 2005.

• Net cash provided by operating activities decreased by $522.3 million, or 41 percent as compared to that of 2005, primarily due to the sale of deepwater Gulf of Mexico and Argentine assets during 2006 and certain Canadian and Gulf of Mexico shelf assets during 2005.

• The Company added 91 MMBOE of proved reserves during 2006, resulting in total proved reserves of 904.9 MMBOE at December 31, 2006.

2007 Events

     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, which will be reported in discontinued operations.

     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 & Poor’s 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 $494.9 million. The Company used the net proceeds from the issuance of the 6.65% Notes to reduce indebtedness under its credit facility.

2

     East Cameron abandonment estimate. As is further described in Note U of the Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein, 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 is further described in Note D of the Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein, 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 of the Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein, 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 of the Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein, 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 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.

     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.

3

     In July 2007, the Company entered into an agreement to acquire an interest in approximately 44,000 gross acres of proved and unproved properties in the Spraberry field in West Texas for $90 million, subject to normal closing adjustments. Pioneer will operate the acquired properties. The acquisition closed during the fourth quarter of 2007. Currently, proved reserves associated with the acquisition are approximately 15 MMBOE. The Company estimates that the acquisition provides more than 600 potential drilling locations utilizing 40-acre spacing.

     In July 2007, the Company entered into an agreement to acquire an interest in approximately 30,000 net acres of proved and unproved properties in the Raton Basin for $205 million, subject to normal closing adjustments. The acquired interest has approximately 95 Bcf of proved reserves. The acquisition closed during the fourth quarter of 2007.

     In November 2007, the Company agreed to acquire an interest in approximately 74,000 gross acres of 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. The Company estimates proved reserves on the acreage to be approximately 81 BCFE. The acreage being acquired contains more than 300 potential drilling locations, with most locations covered by 3-D seismic data.

     Master Limited Partnership IPO. 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 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.

     2008 Capital Budgets. On December 19, 2007, the Company announced that its board of directors approved a 2008 capital budget of $1 billion (which excludes acquisitions, asset retirement obligations, capitalized interest and geological and geophysical administrative costs), down significantly from comparable 2007 capital spending. The decrease primarily relates to the completion of facilities construction for its South Coast Gas project off the coast of South Africa and its Oooguruk project on the North Slope of Alaska, the sale of all our Canadian assets and the elimination of higher-risk exploration. Using current strip prices for oil and gas, the Company anticipates that its 2008 capital budget will approximate its 2008 cash flow from operating activities.

     Share Repurchase Program. The Company’s board of directors approved a share repurchase program for $750 million of the Company’s common stock. Through September 30, 2007, the Company had repurchased approximately $207.8 million of common stock under this program.

4

Future Commodity Prices

     Significant factors that may impact future commodity prices include developments in the issues currently impacting Iraq and Iran and the Middle East in general; the extent to which members of the OPEC and other oil exporting nations are able to continue to manage oil supply through export quotas; and overall North American gas supply and demand fundamentals, including the impact of increasing LNG deliveries to the United States. Although the Company cannot predict the occurrence of events that may affect future commodity prices or the degree to which these prices will be affected, the prices for any commodity that the Company produces will generally approximate current market prices in the geographic region of the production. Pioneer will continue to strategically hedge a portion of its oil and gas price risk to mitigate the impact of price volatility on its oil, NGL and gas revenues.

Historical Acquisitions

     2006 acquisition expenditures. During 2006, the Company spent approximately $223.2 million to acquire proved and unproved properties, which was comprised of approximately $144.8 million of proved properties and $78.3 million of unproved properties. The proved properties were primarily bolt-on and acreage acquisitions in the Spraberry field and Edwards Trend area. In North America, the acquisition of unproved properties is comprised of acreage acquisitions in the Spraberry field, Edwards Trend area, Rockies area, Alaska and Canada. The Company also acquired an additional interest in its Jenein Nord block in Tunisia and recognized additional obligations associated with its Nigerian prospects during 2006.

     2005 acquisition expenditures. During 2005, the Company spent approximately $272.9 million to acquire proved and unproved properties. In July 2005, the Company completed the acquisition of approximately 70 MMBOE of substantially proved undeveloped oil reserves in the United States core areas of the Permian Basin and South Texas for $170.7 million.

     2004 Evergreen merger. During 2004, the Company spent approximately 2.6 billion to acquire proved and unproved properties. On September 28, 2004, Pioneer completed a merger with Evergreen Resources, Inc. (“Evergreen”). Pioneer acquired the common stock of Evergreen for a total purchase price of approximately $1.8 billion, which was comprised of cash and Pioneer common stock.

Historical Divestitures

     Argentina and Deepwater Gulf of Mexico. During March 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. During April 2006, the Company sold its Argentine assets for net proceeds of $669.6 million, resulting in a gain of $10.9 million. The historic results of these properties and the related gains on disposition are reported as discontinued operations.

     Volumetric production payments. During January 2005, the Company sold 20.5 MMBOE of proved reserves in the Hugoton and Spraberry fields, by means of two VPPs for net proceeds of $592.3 million, including the assignment of the Company’s obligations under certain derivative hedge agreements.

     During April 2005, the Company sold 7.3 MMBOE of proved reserves in the Spraberry field, by means of a VPP for net proceeds of $300.3 million, including the value attributable to certain derivative hedge agreements assigned to the buyer of the April VPP.

     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) transfers title of the assets to the purchaser and (v) allows the Company to retain the assets after the VPPs volumetric quantities have been delivered.

     Canada and Shelf Gulf of Mexico. During 2005, the Company sold its interests in the Martin Creek and Conroy Black areas of northeast British Columbia and the Lookout Butte area of southern Alberta for net proceeds of $197.2 million, resulting in a gain of $138.3 million. During 2005, the Company also sold all of its interests in certain oil and gas properties on the Gulf of Mexico shelf for net proceeds of $59.2 million, resulting in a gain of $27.9 million. The historic results of these properties and the related gains on disposition are reported as discontinued operations.

5

     Gabon divestiture. In 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, resulting in a gain of $47.5 million with no associated income tax effect either in Gabon or the United States.

2006 Costs Incurred

     The following table summarizes by geographic area the Company’s costs incurred during 2006:

	Property										Asset
	Acquisition Costs				Exploration			Development			Retirement
	Proved		Unproved		Costs			Costs			Obligations		Total
					(in thousands)
Permian Basin	$	51,421	$	30,703	$	12,411		$	285,980		$	1,884	$	382,399
Mid-Continent		133		—		156			35,759			2,650		38,698
Rocky Mountains		1,240		17,495		64,924			170,863			9,561		264,083
Gulf of Mexico:
Continuing operations		—		8		94,167			5,045			6,028		105,248
Discontinued operations		—		2		3,808			3,167			—		6,977
Onshore Gulf Coast		19,743		33,157		82,775			61,705			1,396		198,776
Alaska		4,800		27,956		34,684			119,309	(a)		1,350		188,099
Total United States	$	77,337	$	109,321	$	292,925		$	681,828		$	22,869	$	1,184,280
Argentina—discontinued operations		—		2		10,223			25,542			—		35,767
Canada—discontinued operations		—		19,932		103,245			97,188			8,299		228,664
South Africa		—		—		288			117,511	(a)		13,964		131,763
Tunisia		—		5,000		40,813			—			336		46,149
Other		—		—		11,358			—			—		11,358
West Africa:
Equatorial Guinea		—		—		(1,688	)		—			—		(1,688	)
Nigeria		—		10,584		26,502			—			—		37,086
Total International		—		35,518		190,741			240,241			22,599		489,099
Grand Total	$	77,337	$	144,839	$	483,666		$	922,069		$	45,468	$	1,673,379

(a) Alaska development costs includes $6.8 million of capitalized interest related to the Oooguruk project and South Africa development costs includes $5.3 million of capitalized interest related to the South Coast Gas project.

Results of Operations

     Oil and gas revenues. Oil and gas revenues totaled $1.5 billion, $1.3 billion and $1.0 billion during 2006, 2005 and 2004, respectively. The revenue increase during 2006, as compared to 2005, was due to a 70 percent increase in reported oil prices, including the effects of commodity price hedges and VPP deliveries, and an 11 percent increase in NGL prices. Partially offsetting the effects of increased oil and NGL prices was an 11 percent decrease in reported gas prices, including the effects of commodity price hedges and VPP deliveries, and a four percent decrease in average daily sales volumes on a BOE basis. The revenue increase during 2005, as compared to 2004, was due to a 19 percent increase in reported oil prices, a 27 percent increase in NGL prices and a 39 percent increase in reported gas prices, including the effects of commodity price hedges and VPP deliveries, along with increased production in 2005 on a BOE basis.

     A significant factor contributing to the increases in reported oil prices and decreases in reported oil sales volumes in 2006 as compared to 2005 was the initiation of first deliveries of oil volumes under the Company’s VPP agreements in January 2006. Similarly, reported gas prices and decreases in gas sales volumes in 2006 and 2005 as compared to 2004 were impacted by the initiation of first deliveries of gas volumes under the Company’s VPP agreements during the first half of 2005 offset by the decline in underlying gas prices. In accordance with GAAP, VPP deliveries result in VPP deferred revenue amortization being recognized in oil and gas revenues with no associated sales volumes being recorded.

6

     The following table provides average daily sales volumes from continuing operations, including the effects of delivery of the VPP volumes, by geographic area and in total, for 2006, 2005 and 2004:

	Year Ended December 31,
	2006		2005		2004
Oil (Bbls):
United States		17,716		21,942		21,863
South Africa		4,127		6,588		9,368
Tunisia		2,386		3,477		2,308
Worldwide		24,229		32,007		33,539
NGLs (Bbls):
United States		18,488		17,403		19,678
Gas (Mcf):
United States		284,732		271,033		209,371
South Africa		—		—		—
Tunisia		1,195		—		—
Worldwide		285,927		271,033		209,371
Total (BOE):
United States		83,659		84,517		76,437
South Africa		4,127		6,588		9,368
Tunisia		2,585		3,477		2,308
Worldwide		90,371		94,582		88,113

     On a BOE basis, average daily production for 2006, as compared to 2005, decreased by one percent in the United States and by 33 percent in Africa. Average daily per BOE production for 2005, as compared to 2004, increased by 11 percent in the United States and decreased by 14 percent in Africa.

     Average daily production in the United States was slightly lower during 2006, as compared to 2005, primarily due to a 126 percent increase in VPP oil and gas deliveries on a BOE basis, partially offset by accelerated development drilling in core areas. The increase in United States production volumes during 2005, as compared to 2004, was primarily due to production from properties acquired in the Evergreen merger, partially offset by first deliveries of VPP gas volumes during 2005.

     Production declined in Africa during 2006 and 2005 primarily due to (i) normal production declines from producing properties in South Africa and Tunisia, partially offset by drilling success in Tunisia and (ii) the Company’s interest in the Adam Concession in Tunisia being reduced in 2006 from 24 percent to 20 percent in accordance with the terms of the concession agreement. In Tunisia, the Company recorded gas sales volumes and revenue for the first time after finalizing a gas sales arrangement during 2006.

7

     The following table provides average daily sales volumes from discontinued operations during 2006, 2005 and 2004:

	Year Ended December 31,
	2006		2005		2004
Oil (Bbls):
United States		2,400		5,280		4,774
Argentina		2,515		7,869		8,534
Canada		311		238		137
Worldwide		5,226		13,387		13,445
NGLs (Bbls):
United States		—		65		60
Argentina		421		1,824		1,546
Canada		463		615		917
Worldwide		884		2,504		2,523
Gas (Mcf):
United States		36,038		230,171		312,468
Argentina		43,905		137,032		121,654
Canada		43,434		42,916		41,867
Worldwide		123,377		410,119		475,989
Total (BOE):
United States		8,406		43,707		56,912
Argentina		10,253		32,531		30,356
Canada		8,013		8,005		8,031
Worldwide		26,672		84,243		95,299

     The following table provides average reported prices from continuing operations, including the results of hedging activities and the amortization of VPP deferred revenue, and average realized prices from continuing operations, excluding the results of hedging activities and the amortization of VPP deferred revenue, by geographic area and in total, for 2006, 2005 and 2004:

	Year Ended December 31,
	2006		2005		2004
Average reported prices:
Oil (per Bbl):
United States	$	65.73	$	32.01	$	29.53
South Africa	$	65.92	$	53.01	$	37.87
Tunisia	$	63.16	$	52.98	$	39.14
Worldwide	$	65.51	$	38.61	$	32.52
NGL (per Bbl):
United States	$	35.24	$	31.72	$	25.05
Gas (per Mcf):
United States	$	6.15	$	6.94	$	4.99
Tunisia	$	5.97	$	—	$	—
Worldwide	$	6.15	$	6.94	$	4.99
Total (per BOE):
United States	$	42.64	$	37.09	$	28.57
South Africa	$	65.92	$	53.01	$	37.87
Tunisia	$	61.05	$	52.98	$	39.14
Worldwide	$	44.23	$	38.78	$	29.84
Average realized prices:
Oil (per Bbl):
United States	$	62.92	$	54.05	$	39.22
South Africa	$	65.74	$	53.01	$	38.60
Tunisia	$	63.16	$	52.98	$	39.14
Worldwide	$	63.42	$	53.72	$	39.04
NGL (per Bbl):
United States	$	35.24	$	31.72	$	25.05
Gas (per Mcf):
United States	$	5.96	$	7.26	$	5.46
Tunisia	$	5.97	$	—	$	—
Worldwide	$	5.96	$	7.26	$	5.46
Total (per BOE):
United States	$	41.37	$	43.86	$	32.62
South Africa	$	65.74	$	53.01	$	37.87
Tunisia	$	61.05	$	52.98	$	39.14
Worldwide	$	43.04	$	44.84	$	33.35

8

     Hedging activities. The Company, from time to time, utilizes commodity swap and collar contracts in order 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. During 2006, 2005 and 2004, the Company’s commodity price hedges decreased oil and gas revenues from continuing operations by $151.2 million, $284.8 million and $115.7 million, respectively. The effective portions of changes in the fair values of the Company’s commodity price hedges are deferred as increases or decreases to stockholders’ equity until the underlying hedged transaction occurs. Consequently, changes in the effective portions of commodity price hedges add volatility to the Company’s reported stockholders’ equity until the hedge derivative matures or is terminated. See Note J of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for information concerning the impact to oil and gas revenues during 2006, 2005 and 2004 from the Company’s hedging activities.

     Deferred revenue. During 2006 and 2005, the Company’s recognition of previously deferred VPP revenue increased oil and gas revenues from continuing operations by $190.3 million and $75.8 million, respectively. The Company’s amortization of deferred VPP revenue is scheduled to increase 2007 oil and gas revenues by $181.2 million. See Note T of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for specific information regarding the Company’s VPPs.

     Interest and other income. The Company’s interest and other income totaled $48.4 million, $26.5 million and $1.8 million during 2006, 2005 and 2004, respectively. The $21.9 million increase during 2006, as compared to 2005, is primarily attributable to (i) a $12.9 million increase in interest income primarily attributable to the investing the proceeds from the Argentine and deepwater Gulf of Mexico divestitures during 2006, (ii) $7.4 million of hedge ineffectiveness gains recorded during 2006 and (iii) $5.6 million of Alaskan exploration incentive credits received in 2006, offset by (iv) a $6.6 million decrease in business interruption insurance claims primarily attributable to the 2005 Fain plant fire in the West Panhandle field. The increase in interest and other income during 2005, as compared to 2004, is primarily attributable to the recognition of $14.2 million in business interruption insurance claims related to the Fain plant fire. See Note M of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for additional information regarding interest and other income.

     Gain (loss) on disposition of assets. The Company recorded a net loss on disposition of assets of $6.5 million in 2006, as compared to net gains of $60.1 million and $292 thousand during 2005 and 2004, respectively.

     In 2005, the gain was primarily related to (i) the sale of the stock of a subsidiary that owned the interest in the Olowi block in Gabon, which resulted in a $47.5 million gain and (ii) a $14 million insurance settlement on the Company’s East Cameron facility that was destroyed by Hurricane Rita, which resulted in a $9.7 million gain.

     During 2006, the Company recognized gains on the sale of its interest in certain oil and gas properties in the deepwater Gulf of Mexico and its Argentina assets of approximately $737.1 million. During 2005, the Company also recognized gains on the sale of certain assets in Canada and the shelf of the Gulf of Mexico of approximately $166.2 million. However, pursuant to SFAS 144, these gains and the results of operations from the assets are presented as discontinued operations.

     The net cash proceeds from asset divestitures during 2006, 2005 and 2004 were used, together with net cash flows provided by operating activities, to fund additions to oil and gas properties and stock repurchase programs, and to reduce outstanding indebtedness. See Notes N and V of Notes to Consolidated Financial Statements in the Financial Statements and Supplementary Data included herein for additional information regarding asset divestitures.

     Oil and gas production costs. The Company’s oil and gas production costs totaled $349.1 million, $309.7 million and $206.1 million during 2006, 2005 and 2004, respectively. In general, lease operating expenses and workover expenses represent the components of oil and gas production costs over which the Company has management control, while production taxes and ad valorem taxes are directly related to commodity price changes. Total production costs per BOE increased during 2006 by 18 percent as compared to 2005 primarily due to (i) the impact of a 126 percent increase in delivered volumes under VPP agreements, for which the Company bears all associated production costs and records no associated sales volumes (representing a per BOE production cost impact of approximately $1.50 during 2006 as compared to $.59 during 2005), (ii) general inflation of field service and supply costs and (iii) increases in production and ad valorem taxes and field utility costs due to increasing commodity and utility prices.

9

     Total production costs per BOE increased during 2005 by 40 percent as compared to 2004. The increase in total production costs per BOE during 2005 as compared to 2004 was primarily attributable to (i) increases in production and ad valorem taxes as a result of higher commodity prices, (ii) the retention of production costs related to VPP volumes sold (approximately $.59 per BOE, during 2005), (iii) new production added from the Evergreen merger, which are relatively higher per BOE operating cost properties and (iv) increases in field service and supply costs primarily associated with rising commodity prices.

     The following tables provide the components of the Company’s total production costs per BOE and total production costs per BOE by geographic area for 2006, 2005 and 2004:

	Year Ended December 31,
	2006		2005		2004
Lease operating expenses	$	5.94	$	4.95	$	3.82
Third-party transportation charges		.79		.64		.20
Taxes:
Ad valorem		1.35		1.17		.86
Production		1.84		1.73		1.15
Workover costs		.66		.48		.36
Total production costs	$	10.58	$	8.97	$	6.39

	Year Ended December 31,
	2006		2005		2004
United States	$	10.61	$	8.99	$	6.24
South Africa	$	14.47	$	11.79	$	8.31
Tunisia	$	3.41	$	3.20	$	3.59
Worldwide	$	10.58	$	8.97	$	6.39

     Depletion, depreciation and amortization expense. The Company’s total DD&A expense from continuing operations was $9.52, $7.76 and $6.46 per BOE for 2006, 2005 and 2004, respectively. Depletion expense from continuing operations, the largest component of DD&A expense, was $8.80, $7.19 and $6.11 per BOE during 2006, 2005 and 2004, respectively. During 2006, the increase in per BOE depletion expense was primarily due to (i) a generally increasing trend in the Company’s oil and gas properties’ cost bases per BOE of proved and proved developed reserves as a result of cost inflation in drilling rig rates and drilling supplies, (ii) the aforementioned sale of proved reserves under VPP agreements, for which the Company removed proved reserves with no corresponding decrease in cost basis, (iii) a $.50 per BOE increase in Tunisian depletion, primarily associated with 2006 and 2005 decreases in the Company’s interest in the Adam Concession, offset by (iv) a $3.91 per BOE decrease in South Africa depletion, primarily associated with 2006 and 2005 positive revisions to proved reserves based on well performance.

     During 2005, the increase in per BOE depletion expense was due to relatively higher per BOE cost basis Rocky Mountains area production acquired in the Evergreen merger and a higher depletion rate for the Hugoton and Spraberry fields as a result of the VPP volumes sold.

     The following table provides depletion expense per BOE from continuing operations by geographic area for 2006, 2005 and 2004:

	Year Ended December 31,
	2006		2005		2004
United States	$	9.07	$	7.10	$	5.34
South Africa	$	6.28	$	10.19	$	12.86
Tunisia	$	4.25	$	3.75	$	4.43
Worldwide	$	8.80	$	7.19	$	6.11

     Impairment of oil and gas properties. The Company reviews its long-lived assets to be held and used, including oil and gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. During 2005 and 2004, the Company recognized noncash impairment charges of $644 thousand and $39.7 million, respectively, to reduce the carrying value of its Gabonese Olowi field assets as development of the discovery was canceled. See “Critical Accounting Estimates” below and Notes B and S of Notes to Consolidated Financial

10

Statements included in the Financial Statements and Supplementary Data included herein for additional information pertaining to the Company’s accounting policies regarding assessments of impairment and the Gabonese Olowi field impairment, respectively.

     Exploration, abandonments, geological and geophysical costs. The following table provides the Company’s geological and geophysical costs, exploratory dry hole expense, lease abandonments and other exploration expense by geographic area for 2006, 2005 and 2004 (in thousands):

	United		South
	States		Africa			Tunisia		Other		Total
Year ended December 31, 2006:
Geological and geophysical	$	79,140	$	289		$	8,402	$	21,536	$	109,367
Exploratory dry holes		80,023		7,227			6,214		15,845		109,309
Leasehold abandonments and other		13,696		—			—		17,824		31,520
	$	172,859	$	7,516		$	14,616	$	55,205	$	250,196
Year ended December 31, 2005:
Geological and geophysical	$	63,707	$	282		$	1,857	$	32,214	$	98,060
Exploratory dry holes		24,462		804			9,041		9,135		43,442
Leasehold abandonments and other		8,957		125			—		3,195		12,277
	$	97,126	$	1,211		$	10,898	$	44,544	$	153,779
Year ended December 31, 2004:
Geological and geophysical	$	49,722	$	868		$	2,042	$	11,923	$	64,555
Exploratory dry holes		1,150		(338	)		—		24,798		25,610
Leasehold abandonments and other		4,138		—			—		6		4,144
	$	55,010	$	530		$	2,042	$	36,727	$	94,309

     During 2006, significant components of the Company’s dry hole provisions and leasehold abandonments expense included (i) $34.0 million of costs associated with the Company’s unsuccessful exploratory well on its Block 256 prospect offshore Nigeria, including $17.8 million of associated unproved leasehold impairment, (ii) $21.6 million of dry hole provisions recorded for the Company’s unsuccessful Cronus, Storms and Antigua prospects in the North Slope area of Alaska, (iii) $16.9 million of dry hole provisions and abandonment costs recognized on prospects drilled in prior periods that were being evaluated for commerciality, including $7.2 million of costs associated with the Company’s Boomslang prospect offshore South Africa, $5.5 million of costs associated with two discoveries on the Gulf of Mexico shelf in 2005 and $4.2 million of costs associated with the Company’s Anaguid permit in Tunisia, (iv) $16.0 million of dry hole provision and unproved property impairment recognized on the Company’s unsuccessful Norphlet prospect in Mississippi and (v) a $14.3 million unsuccessful well on the Company’s Flying Cloud prospect in the Gulf of Mexico. During 2006, the Company completed and evaluated 414 exploration/extension wells, 384 of which were successfully completed as discoveries.

     Significant components of the Company’s dry hole expense during 2005 included (i) $21.2 million related to Alaskan well costs, (ii) $9.5 million associated with an unsuccessful Nigerian well, (iii) $3.5 million attributable to an unsuccessful suspended well in the Company’s El Hamra permit in Tunisia, (iv) $5.1 million attributable to an unsuccessful suspended well in the Company’s Anaguid permit in Tunisia and (v) various other exploratory wells. During 2005, the Company completed and evaluated 180 exploratory/extension wells, 149 of which were successfully completed as discoveries.

     Significant components of the Company’s dry hole expense during 2004 included (i) $19.0 million on the Company’s Gabonese Olowi prospect and (ii) $5.8 million associated with the Company’s Bravo prospect offshore Equatorial Guinea. During 2004, the Company completed and evaluated 103 exploratory/extension wells, 58 of which were successfully completed as discoveries.

     General and administrative expense. General and administrative expense totaled $116.6 million, $110.1 million and $69.5 million during 2006, 2005 and 2004, respectively. The increase in general and administrative expense during 2006, as compared to 2005, was primarily due to a full year effect of the 2005 staff increases associated with the Evergreen acquisition. The Company continues to review its general and administrative expenses and remains focused on initiatives to control its expenditures.

     The increase in general and administrative expense during 2005, as compared to 2004, was primarily due to increases in administrative staff, including staff increases associated with the Evergreen merger, and performance-related compensation costs, including the amortization of restricted stock awarded to officers, directors and employees during 2005.

11

     Interest expense. Interest expense was $107.1 million, $126.0 million and $102.0 million during 2006, 2005 and 2004, respectively. The weighted average interest rate on the Company’s indebtedness for the year ended December 31, 2006 was 6.7 percent, as compared to 6.5 percent and 5.4 percent for the years ended December 31, 2005 and 2004, respectively, including the effects of interest rate derivatives. The decrease in interest expense for 2006 as compared to 2005 was primarily due to the repayment of portions of the Company’s outstanding borrowings under the Company’s credit facility with proceeds from the divestiture of the deepwater Gulf of Mexico and Argentine assets and an $11.1 million increase in interest capitalized on the Company’s Oooguruk development project in Alaska and the South Coast Gas project in South Africa, partially offset by a $4.1 million decrease in the amortization of interest rate hedge gains.

     The increase in interest expense for 2005 as compared to 2004 was primarily due to increased average borrowings under the Company’s lines of credit, primarily as a result of the cash portion of the consideration paid in the Evergreen merger and $949.3 million of stock repurchases completed during 2005, a $15.2 million decrease in the amortization of interest rate hedge gains, the assumption of $300 million of notes in connection with the Evergreen merger and higher interest rates in 2005.

     See Note F of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for additional information about the Company’s long-term debt and interest expense.

     Hurricane activity, net. The Company recorded net hurricane related activity expenses of $32.0 million and $39.8 million during 2006 and 2005, respectively, associated with the Company’s East Cameron platform facility, located on the Gulf of Mexico shelf, that was destroyed during 2005 by Hurricane Rita.

     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, as of December 31, 2006, the Company estimated that it would cost approximately $119 million to reclaim and abandon the East Cameron facility. Estimates to reclaim and abandon the East Cameron facility were 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 million and $39.8 million, respectively. 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 Company expects that a substantial portion of the total estimated cost to reclaim and abandon the facility will be covered by insurance, including 100 percent of the debris removal costs. Consequently, the Company has recorded a $43.0 million insurance recovery receivable corresponding to the estimated debris removal costs.

     See “2007 Events” for information regarding 2007 developments pertaining to the Company’s reclamation and abandonment of the East Cameron facilities.

     Other expenses. Other expenses were $36.9 million during 2006, as compared to $80.7 million during 2005 and $25.6 million during 2004. The $43.8 million decrease in other expenses during 2006, as compared to 2005, is primarily attributable to (i) a $40.4 million decrease in hedge ineffectiveness charges and (ii) a $17.9 million decrease in loss on early extinguishment of portions of the Company’s senior notes, partially offset by (iii) a $4.4 million increase in bad debt expense, (iv) a $4.0 million insurance charge, (v) a $2.7 million increase in non-hedge derivative charges and (vi) $3.4 million of other net increases in other expense components.

     The $55.1 million increase in other expenses during 2005, as compared to 2004, is primarily attributable to (i) a $26.0 million loss on the redemption and tender of portions of the Company’s senior notes, (ii) a $25.7 million increase in hedge ineffectiveness charges and (iii) a $3.9 million increase in non-hedge derivative charges. See Note O of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for a detailed description of the components included in other expenses.

12

     Income tax provision. The Company recognized income tax provisions on continuing operations of $141.0 million, $149.2 million and $62.1 million during 2006, 2005 and 2004, respectively. The Company’s effective tax rates for 2006, 2005 and 2004 were 48.4 percent, 44.7 percent and 28.8 percent, respectively, as compared to the combined United States federal and state statutory rates of approximately 36.5 percent. The effective tax rates of 2006 and 2005 differ from the combined United States federal and state statutory rates 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 the conversion of senior convertible notes prior to the Company’s repayment of the debt principal,

• 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 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 No. 109, “Accounting for Income Taxes” 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.

     See “Critical Accounting Estimates” below and Note P of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for additional information regarding the Company’s tax position.

     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

     The Company recognized income from discontinued operations of $589.5 million during 2006, as compared to $350.3 million during 2005 and $159.7 million during 2004. Pursuant to SFAS 144, the results of operations of these properties and the related gains on disposition are reported as discontinued operations. See Notes V and W of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for additional data on discontinued operations.

Capital Commitments, Capital Resources and Liquidity

     Capital commitments. The Company’s primary needs for cash are for exploration, development and acquisition of oil and gas properties, repayment of contractual obligations and working capital obligations. Funding for exploration, development and acquisition of oil and gas properties and repayment of contractual obligations may be provided by any combination of internally-generated cash flow, proceeds from the disposition of nonstrategic assets or alternative financing sources as discussed in “Capital resources” and “Financing activities” below. Generally, funding for the Company’s working capital obligations is provided by internally-generated cash flows.

13

     Payments for acquisitions, net of cash acquired. In 2004, the Company paid $880.4 million of cash, net of $12.1 million of cash acquired, and issued shares of the Company’s common stock to complete the Evergreen merger. The Company also assumed $300 million principal amount of Evergreen notes and other current and noncurrent obligations associated with the Evergreen merger. As is further discussed in “Financing activities” below, and in Note C of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein, the Company financed the cash costs utilizing credit facilities.

     Oil and gas properties. The Company’s cash expenditures for additions to oil and gas properties during 2006, 2005 and 2004 totaled $1.4 billion, $1.1 billion and $562.9 million, respectively. The Company’s 2006 expenditures for additions to oil and gas properties were funded by $754.8 million of net cash provided by operating activities and by a portion of the net proceeds from the disposition of deepwater Gulf of Mexico and Argentine assets. The Company’s 2005 and 2004 expenditures for additions to oil and gas properties were internally funded by $1.3 billion and $1.1 billion, respectively, of net cash provided by operating activities.

     The Company strives to maintain its indebtedness at levels which will provide sufficient financial flexibility to take advantage of future opportunities. For 2007, the Company’s credit facility and net cash provided by operating activities were sufficient to fund the 2007 capital expenditures budget.

     Off-balance sheet arrangements. From time-to-time, the Company enters into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations of the Company. As of December 31, 2006, the material off-balance sheet arrangements and transactions that the Company has entered into include (i) undrawn letters of credit, (ii) operating lease agreements, (iii) drilling commitments, (iv) VPP obligations (to physically deliver volumes and pay related lease operating expenses in the future) and (v) contractual obligations for which the ultimate settlement amounts are not fixed and determinable such as derivative contracts that are sensitive to future changes in commodity prices and gas transportation commitments. Other than the off-balance sheet arrangements described above, the Company has no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect the Company’s liquidity or availability of or requirements for capital resources. See “Contractual obligations” below for more information regarding the Company’s off-balance sheet arrangements.

     Contractual obligations. The Company’s contractual obligations include long-term debt, operating leases, drilling commitments (including commitments to pay day rates for drilling rigs), derivative obligations, other liabilities, transportation commitments and VPP obligations.

     The following table summarizes by period the payments due by the Company for contractual obligations estimated as of December 31, 2006:

	Payments Due by Year
			2008 and		2010 and
	2007		2009		2011		Thereafter
			(in thousands)
Long-term debt (a)	$	32,075	$	3,777	$	328,000	$	1,232,985
Operating leases (b)		29,065		27,906		7,429		—
Drilling commitments (c)		330,381		307,265		—		—
Derivative obligations (d)		78,233		121,126		—		—
Other liabilities (e)		170,156		70,932		25,750		108,660
Transportation commitments (f)		68,630		137,396		130,992		170,546
VPP obligations (g)		181,232		306,044		135,166		42,069
	$	889,772	$	974,446	$	627,337	$	1,554,260

(a)	See Note F of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein. The amounts included in the table above represent principal maturities only.
(b)	See Note I of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein.

14

(c)	Drilling commitments represent future minimum expenditure commitments for drilling rig services and well commitments under contracts to which the Company was a party on December 31, 2006.
(d)	Derivative obligations represent net liabilities for oil and gas commodity derivatives that were valued as of December 31, 2006. These liabilities include $131.1 million of liabilities that are fixed in amount and are not subject to continuing market risk. The ultimate settlement amounts of the remaining portions of the Company’s derivative obligations are unknown because they are subject to continuing market risk. See Note J of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for additional information regarding the Company’s derivative obligations.
(e)	The Company’s other liabilities represent current and noncurrent other liabilities that are comprised of benefit obligations, litigation and environmental contingencies, asset retirement obligations and other obligations for which neither the ultimate settlement amounts nor their timings can be precisely determined in advance. See Notes H, I and L of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for additional information regarding the Company’s post retirement benefit obligations, litigation contingencies and asset retirement obligations, respectively.
(f)	Transportation commitments represent estimated transportation fees on gas throughput commitments. See Note I of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for additional information regarding the Company’s transportation commitments.
(g)	These amounts represent the amortization of the deferred revenue associated with the VPPs. The Company’s ongoing obligation is to deliver the specified volumes sold under the VPPs free and clear of all associated production costs and capital expenditures. See Note T of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein.

     Environmental contingency. A subsidiary of the Company was notified by the Texas Commission on Environmental Quality (“TCEQ”) in August 2005 that the TCEQ considered 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. 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. See Notes I and W of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for additional information regarding this matter as well as other environmental and legal contingencies involving the Company.

     Capital resources. The Company’s primary capital resources are net cash provided by operating activities, proceeds from financing activities and proceeds from sales of nonstrategic assets. The Company expects that these resources will be sufficient to fund its capital commitments for the foreseeable future. For 2007, the Company’s capital commitments exceeded estimated cash flows from operations, resulting in additional borrowings under the Company’s credit facility. For 2008, the Company currently expects that cash flow from operations will be sufficient to fund the Company’s $1 billion capital budget.

     Asset divestitures. 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, the proceeds from which were utilized to reduce amounts outstanding under the Company’s credit facility. Associated therewith, the Company will report a gain of approximately $100 million during the fourth quarter of 2007. The results of operations for the Canadian assets are included in the Company’s discontinued operations.

     During March 2006, the Company sold all of 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. During April 2006, the Company sold its Argentine assets for net proceeds of $669.6 million, resulting in a gain of $10.9 million. The results of operations for these divestitures are included in the Company’s discontinued operations. The net cash proceeds from these divestitures were used to reduce outstanding indebtedness under the Company’s credit facility, to fund a portion of additions to oil and gas properties, for stock repurchases and for general corporate purposes.

15

     During May 2005, the Company sold all of its interests in the Martin Creek, Conroy Black and Lookout Butte oil and gas properties in Canada for net proceeds of $197.2 million, resulting in a gain of $138.3 million. During August 2005, the Company sold all of its interests in certain oil and gas properties on the Gulf of Mexico shelf for net proceeds of $59.2 million, resulting in a gain of $27.9 million. During October 2005, the Company sold all of its shares in a subsidiary that owns the interest in the Olowi block in Gabon for net proceeds of $47.9 million, resulting in a gain of $47.5 million. The net cash proceeds from the 2005 divestitures were used to reduce outstanding indebtedness.

     During January 2005, the Company sold 20.5 MMBOE of proved reserves, by means of two VPPs for net proceeds of $592.3 million, including the assignment of the Company’s obligations under certain derivative hedge agreements. Proceeds from the VPPs were used to reduce outstanding indebtedness.

     During April 2005, the Company sold 7.3 MMBOE of proved reserves, by means of another VPP for net proceeds of $300.3 million, including the assignment of the Company’s obligations under certain derivative hedge agreements. Proceeds from the VPP were used to reduce outstanding indebtedness.

     See Note T of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for additional information regarding the Company’s VPPs.

     Operating activities. Net cash provided by operating activities during 2006, 2005 and 2004 was $754.8 million, $1.3 billion and $1.1 billion, respectively. The decrease in net cash provided by operating activities in 2006, as compared to that of 2005, was primarily due to the loss of cash flow from the aforementioned asset divestitures. The increase in net cash provided by operating activities in 2005, as compared to that of 2004, was primarily due to higher commodity prices and the operations acquired in the Evergreen merger.

     Investing activities. Net cash provided by investing activities during 2006 was $145.5 million, as compared to net cash provided by investing activities of $84.7 million during 2005 and net cash used in investing activities of $1.5 billion during 2004. The increase in net cash provided by investing activities during 2006, as compared to 2005, was primarily due to a $396.2 million increase in proceeds from disposition of assets, partially offset by a $280.6 million increase in additions to oil and gas properties. The decrease in net cash used in investing activities during 2005, as compared to 2004, was primarily due to (i) $1.2 billion in proceeds from asset divestitures in 2005, which included $892.6 million of net proceeds received from VPPs sold during 2005 and (ii) $880.4 million of cash consideration paid in 2004 in connection with the Evergreen merger offset by an increase of $560.4 million in additions to oil and gas properties. See “Results of Operations” above and Note N of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for additional information regarding asset divestitures.

     Financing activities. Net cash used in financing activities was $913.5 million and $1.4 billion during 2006 and 2005, respectively. Net cash provided by financing activities during 2004 was $414.3 million. During 2006, significant components of financing activities included $554.7 million of net cash used to repay long-term borrowings, $348.9 million of net cash used to purchase 8.9 million shares of stock and $31.7 million of dividend payments, partially offset by $17.4 million of proceeds from the exercise of long-term incentive plan stock options and employee stock purchases. During 2005, financing activities were comprised of $353.6 million of net principal repayments on long-term debt, $60.1 million of payments of other noncurrent liabilities, primarily comprised of cash settlements of acquired hedge obligations, $30.3 million of dividends paid and $949.3 million of stock repurchases, partially offset by $41.6 million of proceeds from the exercise of long-term incentive plan stock options and employee stock purchases. During 2004, financing activities were comprised of $553.4 million of net principal borrowings on long-term debt, $54.3 million of payments of other noncurrent liabilities, primarily comprised of settlements of fair value and acquired hedge obligations and other financial obligations, $92.3 million of stock repurchases and $26.6 million of dividends paid, partially offset by $35.1 million of proceeds from the exercise of long-term incentive plan stock options and employee stock purchases.

     During September 2005, the Company announced that the board of directors had approved a share repurchase program authorizing the purchase of up to $1 billion of the Company’s common stock. During 2006 and 2005, the Company expended a total of $348.9 million to acquire 8.9 million shares of stock and $949.3 million to acquire 20.0 million shares of stock, respectively, of which $345.3 million and $940.3 million, respectively, were repurchased pursuant to the repurchase programs. In 2007, the Board authorized share repurchases of up to $750 million of the Company’s common stock. Through September 30, 2007, the Company had repurchased approximately $207.8 million of common stock under this 2007 authorized program.

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     On August 15, 2007, $32.1 million principal amount of the Company’s 8.25% senior notes matured and were repaid with borrowings under the Company’s credit facility. On January 15, 2008, $3.8 million principal amount of the Company’s 6.50% senior notes will mature. The Company intends to fund the maturities of these senior notes with borrowings under its credit facility.

     During March 2007, the Company issued $500 million of 6.65% Notes for net proceeds of $494.8 million. The Company used the net proceeds from the 6.65% Notes to reduce indebtedness under its credit facility. During April 2007, the Company entered into an amended credit facility that extended the maturity of its credit facility to April 11, 2012. See “2007 Events” above for additional information regarding the significant terms of the amended credit facility.

     During May 2006, the Company issued $450 million of 6.875% Notes for net proceeds of $447.4 million. The Company used the net proceeds, in part, from the 6.875% Notes to repurchase $346.2 million of its 6.50% Notes and for general corporate purposes.

     During 2006, holders of all of the $100 million of 4 3/4% Senior Convertible Notes due 2021 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 $22.0 million increase to stockholders’ equity.

     During April 2005, $131.0 million of the Company’s 8 7/8% senior notes due 2005 matured and were repaid. During 2005, the Company also redeemed the remaining $64.0 million and $16.2 million, respectively, of aggregate principal amount of its 9 5/8% senior notes due 2010 and its 7.50% senior notes due 2012. During September 2005, the Company accepted tenders to purchase $188.4 million in principal amount of the 5.875% senior notes due 2012 for $199.9 million. The Company utilized unused borrowing capacity under its credit facility to fund these financing activities.

     During 2007, the Company’s board of directors declared total dividends of $.27 per common share. Associated therewith, the Company paid $16.0 million of aggregate dividends during April 2007 and $17.2 million of aggregate dividends during October 2007. Future dividends are at the discretion of the Board, and, if declared, the Board may change the current dividend amount, including in response to the Company’s liquidity and capital resources at the time.

     In 2007, Pioneer Southwest filed a preliminary registration statement (subject to completion) with the SEC to sell limited partner interests. Pioneer Southwest will own 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 expects to sell 35.3 percent (before underwriters’ over-allotment option) of its limited partner interests to the public (the “Offering”). Completion of the Offering is subject to market conditions and numerous other risks beyond the control of Pioneer Southwest, and therefore it is possible that the Offering will not be completed, will not raise the planned amount of capital even if the Offering is completed, or will not be completed when planned. If completed as planned, the Offering is estimated to result in the Company’s receipt of approximately $136 million of net cash proceeds during the first quarter of 2008.

     In October 2007, Pioneer Southwest entered into a $300 million unsecured revolving credit facility (“PSE Credit Agreement”) 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. See “2007 Events” above and Note W of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for additional information regarding Pioneer Southwest and the PSE Credit Agreement.

     Alaskan Petroleum Production Tax. In 2006, the State of Alaska replaced its severance tax with a new tax called the PPT, for periods beginning after March 31, 2006. The major components of the new PPT are:

• The “basic tax”, which begins at 22.5 percent (this rate can increase based on factors tied to commodity prices) of property income for designated pools of assets in Alaska. Property income is basically defined as oil and gas revenue less lease operating expenses, qualified capital expenditures, property taxes and certain other costs. If property income is a loss then it converts to a PPT loss carryforward at a rate of 20 percent of the property loss. PPT loss carryforwards can be used to reduce future PPT liabilities or transferred to a third party. For 2006 and the nine months ended September 30, 2007, the Company estimates its PPT loss carryforwards to be approximately $21.0 million and $45.0 million, respectively.

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• A capital expenditure credit of 20 percent of qualified capital expenditures within Alaska. The credit can be (a) used to reduce a company’s current PPT liability, (b) carried forward and used to reduce future PPT liabilities or (c) transferred to a third party. Certain qualified exploration capital expenditures can receive up to an additional 20 percent capital expenditure credit on the expenditures previously discussed. For 2006 and the nine months ended September 30, 2007, the Company estimates its capital expenditure credits to be approximately $20.4 million and $44.5 million, respectively.

• Companies with production of less than 50,000 BOEPD within Alaska may also claim an annual non-transferable and non-refundable credit against PPT of $12 million per year for ten consecutive years, once the election is made to receive this credit.

• Companies that incurred qualified capital expenditures within Alaska in the five years preceding the PPT effective date can earn non-transferable transitional capital credits of 20 percent of such expenditures. These credits can be used to reduce a company’s present and future PPT liabilities. The Company estimates it has approximately $20 million of these credits to offset future PPT liabilities.

     The Company currently has no production in Alaska and accordingly has no PPT liabilities. The Company anticipates that it will recognize benefits from the carryforwards and credits as they are used to reduce future PPT liabilities, sold to third parties or refunded by the State of Alaska. Currently, the State of Alaska budgets annual amounts to provide for refunds of PPT credits; however, no assurances can be made that the State of Alaska will budget for future refunds. During the second quarter of 2007, the Company received a $25.0 million refund from the State of Alaska on earned PPT credits, and during the third quarter of 2007, the Company sold $28.3 million of earned PPT credits to a third party, which amounts have been recognized in interest and other income in the Company’s Consolidated Statements of Operations for the respective three and nine month periods of 2007. The Company may sell additional earned PPT credits in the future. The Company cannot predict the price that a third-party would pay for the certificates, but anticipates that it will be at a discount to the face amount of the certificates. Recently, the Alaskan legislature replaced PPT with Alaska’s Clear and Equitable Share tax (“ACES”). The Company is currently evaluating the complete effects of ACES, but believes it will not have a material impact on the Company’s Alaskan operations.

     As the Company pursues its strategy, it may utilize various financing sources, including fixed and floating rate debt, convertible securities, preferred stock or common stock. The Company may also issue securities in exchange for oil and gas properties, stock or other interests in other oil and gas companies or related assets. Additional securities may be of a class preferred to common stock with respect to such matters as dividends and liquidation rights and may also have other rights and preferences as determined by the Board.

     Liquidity. The Company’s principal source of short-term liquidity is the Credit Agreement. There was $328.0 million of outstanding borrowings under its credit facility as of December 31, 2006. Including $150.2 million of undrawn and outstanding letters of credit under its credit facility, the Company had $1.0 billion of unused borrowing capacity as of December 31, 2006.

     Debt ratings. The Company receives debt credit ratings from Standard & Poor’s Ratings Group, Inc. (“S&P”) and Moody’s, which are subject to regular reviews. S&P’s rating for the Company is BB+ with a stable outlook. Moody’s rating for the Company is Ba1 with a negative outlook. S&P and Moody’s consider many factors in determining the Company’s ratings including: production growth opportunities, liquidity, debt levels and asset and reserve mix. A reduction in the Company’s debt ratings could negatively impact the Company’s ability to obtain additional financing or the interest rate, fees and other terms associated with such additional financing. As of September 30, 2007, the Company was in compliance with all of its debt covenants.

     Book capitalization and current ratio. The Company’s book capitalization at December 31, 2006 was $4.5 billion, consisting of debt of $1.5 billion and stockholders’ equity of $3.0 billion. Consequently, the Company’s debt to book capitalization decreased to 33 percent at December 31, 2006 from 48 percent at December 31, 2005. The Company’s ratio of current assets to current liabilities was .60 to 1.00 at December 31, 2006, essentially unchanged from December 31, 2005.

Critical Accounting Estimates

     The Company prepares its consolidated financial statements for inclusion in this Report in accordance with GAAP. See Note B of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for a comprehensive discussion of the Company’s significant accounting policies. GAAP represents a comprehensive set of accounting and disclosure rules and requirements, the application of which requires management judgments and estimates including, in certain circumstances, choices between acceptable GAAP alternatives. Following is a discussion of the Company’s most critical accounting estimates, judgments and uncertainties that are inherent in the Company’s application of GAAP.

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     Asset retirement obligations. The Company has significant obligations to remove tangible equipment and facilities and to restore land or seabed at the end of oil and gas production operations. The Company’s removal and restoration obligations are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and gas platforms. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

     Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations, a corresponding adjustment is made to the oil and gas property balance. See Notes B and L of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for additional information regarding the Company’s asset retirement obligations.

     Successful efforts method of accounting. The Company utilizes the successful efforts method of accounting for oil and gas producing activities as opposed to the alternate acceptable full cost method. In general, the Company believes that, during periods of active exploration, net assets and net income are more conservatively measured under the successful efforts method of accounting for oil and gas producing activities than under the full cost method. The critical difference between the successful efforts method of accounting and the full cost method is as follows: under the successful efforts method, exploratory dry holes and geological and geophysical exploration costs are charged against earnings during the periods in which they occur; whereas, under the full cost method of accounting, such costs and expenses are capitalized as assets, pooled with the costs of successful wells and charged against the earnings of future periods as a component of depletion expense. During 2006, 2005 and 2004, the Company recognized exploration, abandonment, geological and geophysical expense from (i) continuing operations of $250.2 million, $153.8 million and $94.3 million, respectively, and (ii) discontinued operations of $21.3 million, $73.4 million and $87.4 million, respectively, under the successful efforts method.

     Proved reserve estimates. Estimates of the Company’s proved reserves included in this Report are prepared in accordance with GAAP and SEC guidelines. The accuracy of a reserve estimate is a function of:

• the quality and quantity of available data,

• the interpretation of that data,

• the accuracy of various mandated economic assumptions and

• the judgment of the persons preparing the estimate.

     The Company’s proved reserve information included in this Report as of December 31, 2006, 2005 and 2004 was prepared by the Company’s engineers and audited by independent petroleum engineers with respect to the Company’s major properties. Estimates prepared by third parties may be higher or lower than those included herein.

     Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify, positively or negatively, material revisions to the estimate of proved reserves.

     It should not be assumed that the Standardized Measure included in this Report as of December 31, 2006 is the current market value of the Company’s estimated proved reserves. In accordance with SEC requirements, the Company based the Standardized Measure on prices and costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. See “Item 1A. Risk Factors” for additional information regarding estimates of proved reserves.

     The Company’s estimates of proved reserves materially impact depletion expense. If the estimates of proved reserves decline, the rate at which the Company records depletion expense will increase, reducing future net income.

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Such a decline may result from lower market prices, which may make it uneconomical to drill for and produce higher cost fields. In addition, a decline in proved reserve estimates may impact the outcome of the Company’s assessment of its proved properties and goodwill for impairment.

     Impairment of proved oil and gas properties. The Company reviews its proved properties to be held and used whenever management determines that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Management assesses whether or not an impairment provision is necessary based upon its outlook of future commodity prices and net cash flows that may be generated by the properties and if a significant downward revision has occurred to the estimated proved reserves. Proved oil and gas properties are reviewed for impairment at the level at which depletion of proved properties is calculated.

     Impairment of unproved oil and gas properties. At December 31, 2006, the Company carried unproved property costs of $210.3 million. Management periodically assesses unproved oil and gas properties for impairment, on a project-by-project basis. Management’s assessment of the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects impacts the amount and timing of impairment provisions, if any.

     Suspended wells. The Company suspends the costs of exploratory wells that discover hydrocarbons pending a final determination of the commercial potential of the oil and gas discovery. The ultimate disposition of these well costs is dependent on the results of future drilling activity and development decisions. If the Company decides not to pursue additional appraisal activities or development of these fields, the costs of these wells will be charged to exploration and abandonment expense.

     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 of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for additional information regarding the Company’s suspended exploratory well costs.

     Assessments of functional currencies. Management determines the functional currencies of the Company’s subsidiaries based on an assessment of the currency of the economic environment in which a subsidiary primarily realizes and expends its operating revenues, costs and expenses. The U.S. dollar is the functional currency of all of the Company’s international operations except Canada. The assessment of functional currencies can have a significant impact on periodic results of operations and financial position.

     Argentine economic and currency measures. In April 2006, the Company sold its assets in Argentina for proceeds of $669.6 million, resulting in a gain of $10.9 million. Prior to the divestiture, the accounting for and remeasurement of the Company’s Argentine balance sheets as of December 31, 2005 reflect management’s assumptions regarding some uncertainties unique to Argentina’s economic environment. The Argentine economic and political situation continues to evolve and the Argentine government may enact future regulations or policies that, when finalized and adopted, may materially impact, among other items, the timing of repatriations of the sales proceeds and contingent liabilities associated with the Company’s retained obligations and its indemnifications provided to the purchaser of the assets. See Note B of Notes to Consolidated Financial Statements included in the Financial Statements included herein for a description of the assumptions utilized in the preparation of these financial statements.

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     Deferred tax asset valuation allowances. The Company continually assesses both positive and negative evidence to determine whether it is more likely than not that its deferred tax assets will be realized prior to their expiration. Pioneer monitors Company-specific, oil and gas industry and worldwide economic factors and reassesses the likelihood that the Company’s net operating loss carryforwards and other deferred tax attributes in each jurisdiction will be utilized prior to their expiration. There can be no assurances that facts and circumstances will not materially change and require the Company to establish deferred tax asset valuation allowances in certain jurisdictions in a future period. As of December 31, 2006, the Company does not believe there is sufficient positive evidence to reverse its valuation allowances related to certain foreign tax jurisdictions.

     Goodwill impairment. The Company reviews its goodwill for impairment at least annually. This requires the Company to estimate the fair value of the assets and liabilities of the reporting units that have goodwill. There is considerable judgment involved in estimating fair values, particularly in the estimation of proved reserves as described above. See Note B of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for additional information.

     Litigation and environmental contingencies. The Company makes judgments and estimates in recording liabilities for ongoing litigation and environmental remediation. Actual costs can vary from such estimates for a variety of reasons. The costs to settle litigation can vary from estimates based on differing interpretations of laws and opinions and assessments on the amount of damages. Similarly, environmental remediation liabilities are subject to change because of changes in laws and regulations, developing information relating to the extent and nature of site contamination and improvements in technology. Under GAAP, a liability is recorded for these types of contingencies if the Company determines the loss to be both probable and reasonably estimable. See Note I of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for additional information regarding the Company’s commitments and contingencies.

     Valuations of defined benefit pension and postretirement plans. The Company is the sponsor of certain defined benefit pension and postretirement plans. In accordance with GAAP, the Company is required to estimate the present value of its unfunded pension and accumulated postretirement benefit obligations. Based on those values, the Company records the unfunded obligations of those plans and records ongoing service costs and associated interest expense. The valuation of the Company’s pension and accumulated postretirement benefit obligations requires management assumptions and judgments as to benefit cost inflation factors, mortality rates and discount factors. Changes in these factors may materially change future benefit costs and pension and accumulated postretirement benefit obligations. See “New Accounting Pronouncements” below and Note H of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for additional information regarding the Company’s pension and accumulated postretirement benefit obligations.

     Valuation of stock-based compensation. The Company adopted the “modified prospective” approach as prescribed under SFAS No. 123(R) on January 1, 2006. Under this approach, the Company is required to expense all options and other stock-based compensation that vested during the year of adoption based on the fair value of the award on the grant date. The calculation of the fair value of stock-based compensation requires the use of estimates to derive the various inputs necessary for using the Black-Scholes valuation method elected by the Company.

New Accounting Pronouncements

     The following discussions provide information about new accounting pronouncements that were issued by the Financial Accounting Standards Board (“FASB”) during 2006:

     FIN 48. In July 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN No. 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 No. 48 also provides guidance on measurement, classification, interim accounting and disclosure. FIN No. 48 is effective for fiscal years beginning after December 15, 2006. The Company adopted FIN 48 on January 1, 2007 and recorded no adjustment related to the adoption.

     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 of SFAS 157.

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     SFAS 158. In September 2006, the FASB issued SFAS No. 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 fiscal year-end statement of financial position 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 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. See Note H of Notes to Consolidated Financial Statements included in the Financial Statements and Supplementary Data included herein for additional information regarding the Company’s postretirement plans.

     SFAS 159. In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”). SFAS 159 permits entities to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. SFAS 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The implementation of SFAS 159 is not expected to have a material effect on the financial condition or results of operations of the Company.

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Definitions of Certain Terms and Conventions Used Herein

• “Bbl” means a standard barrel containing 42 United States gallons.

• “Bcf” means one billion cubic feet.

• “BOE” means a barrel of oil equivalent and is a standard convention used to express oil and gas volumes on a comparable oil equivalent basis. Gas equivalents are determined under the relative energy content method by using the ratio of 6.0 Mcf of gas to 1.0 Bbl of oil or natural gas liquid.

• “BOEPD” means BOE per day.

• “Btu” means British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.

• “CBM” means coal bed methane.

• “field fuel” means gas consumed to operate field equipment (primarily compressors) prior to the gas being delivered to a sales point.

• “GAAP” means accounting principles that are generally accepted in the United States of America.

• “LIBOR” means London Interbank Offered Rate, which is a market rate of interest.

• “MBbl” means one thousand Bbls.

• “MBOE” means one thousand BOEs.

• “Mcf” means one thousand cubic feet and is a measure of natural gas volume.

• “MMBbl” means one million Bbls.

• “MMBOE” means one million BOEs.

• “MMBtu” means one million Btus.

• “MMcf” means one million cubic feet.

• “NGL” means natural gas liquid.

• “NYMEX” means the New York Mercantile Exchange.

• “NYSE” means the New York Stock Exchange.

• “Pioneer” or the “Company” means Pioneer Natural Resources Company and its subsidiaries.

• “proved reserves” mean the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii) Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”; (B) crude oil, natural gas and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics or economic factors; (C) crude oil, natural gas and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

• “SEC” means the United States Securities and Exchange Commission.

• “Standardized Measure” means the after-tax present value of estimated future net revenues of proved reserves, determined in accordance with the rules and regulations of the SEC, using prices and costs in effect at the specified date and a 10 percent discount rate.

• “VPP” means volumetric production payment.

• “U.S.” means United States.

• With respect to information on the working interest in wells, drilling locations and acreage, “net” wells, drilling locations and acres are determined by multiplying “gross” wells, drilling locations and acres by the Company’s working interest in such wells, drilling locations or acres. Unless otherwise specified, wells, drilling locations and acreage statistics quoted herein represent gross wells, drilling locations or acres.

• Unless otherwise indicated, all currency amounts are expressed in U.S. dollars.

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EX-99.3

Exhibit 99.3

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Consolidated Financial Statements

	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

1

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

2

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.

3

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.

4

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.

5

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.

6

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.

7

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(in thousands)

	Year Ended December 31,
	2006			2005			2004
Net income	$	739,731		$	534,568		$	312,854
Other comprehensive loss:
Net deferred hedge gains (losses), net of tax:
Net deferred hedge gains (losses)		118,139			(539,384	)		(291,642	)
Net hedge losses included in continuing operations		96,530			180,941			75,737
Net hedge losses included in discontinued operations		124,747			93,157			78,685
Translation adjustment		(6,600	)		8,118			19,417
Other comprehensive income (loss)		332,816			(257,168	)		(117,803	)
Comprehensive income	$	1,072,547		$	277,400		$	195,051

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

8

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.

9

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.

10

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

11

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.

12

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.

13

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:

14

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

15

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.

16

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

17

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

18

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

19

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

20

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.

21

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

22

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.

23

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

24

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.

25

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.

26

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.

27

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

28

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.

29

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

30

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

31

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

32

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.

33

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.

34

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.

35

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.

36

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

37

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

38

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.

39

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.

40

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.

41

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.

42

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.

43

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

44

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

45

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.

46

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

47

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

48

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

49

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.

50

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

51

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”).

52

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.

53

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.

54

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.

55

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

56

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.

57