Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

(Mark One)
ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2007
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM                                TO

Commission file number 1-8432

Mesa Offshore Trust
(Exact Name of Registrant as Specified in Its Charter)

Texas (State or Other Jurisdiction of Incorporation or Organization)		76-6004065 (I.R.S. Employer Identification No.)
JP Morgan Chase Bank, N.A., Trustee Institutional Trust Services 919 Congress Avenue, Austin, Texas (Address of Principal Executive Offices)		78701 (Zip Code)

Registrant's telephone number, including area code: 1-800-852-1422

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act:
Units of beneficial interest
(Title of Class)

        Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No ý

        Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No ý

        Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

        Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

        Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer," and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o

Accelerated filer o

Non-accelerated filer ý (Do not check if a smaller reporting company)

Smaller reporting company o

        Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No ý

        The aggregate market value of 71,980,216 Units of Beneficial Interest in Mesa Offshore Trust held by non-affiliates of the registrant at the closing sales price on June 30, 2007, of $0.09 was approximately $6,478,219.

        Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.

        As of March 31, 2008, 71,980,216 Units of Beneficial Interest were outstanding in Mesa Offshore Trust.

DOCUMENTS INCORPORATED BY REFERENCE: None.

TABLE OF CONTENTS

				Page
PART I
Item 1.		Business		4
Item 1A.		Risk Factors		19
Item 1B.		Unresolved Staff Comments		24
Item 2.		Properties		24
Item 3.		Legal Proceedings		24
Item 4.		Submission of Matters to a Vote of Security Holders		24
PART II
Item 5.		Market for the Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities		25
Item 6.		Selected Financial Data		25
Item 7.		Management's Discussion and Analysis of Financial Condition and Results of Operations		25
Item 7A.		Quantitative and Qualitative Disclosures About Market Risk		32
Item 8.		Financial Statements and Supplementary Data		33
Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		46
Item 9A.		Controls and Procedures		46
PART III
Item 10.		Directors, Executive Officers and Corporate Governance		48
Item 11.		Executive Compensation		48
Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters		48
Item 13.		Certain Relationships and Related Transactions, and Director Independence		49
Item 14.		Principal Accounting Fees and Services		49
PART IV
Item 15.		Exhibits, Financial Statement Schedules		51
SIGNATURES				53

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Note Regarding Forward-Looking Statements

        This Form 10-K includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included in this Form 10-K, including without limitation the statements under "Business—Timing of Liquidation," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 1 to the financial statements of the Trust regarding the future net revenues of the Trust, are forward-looking statements. Although Pioneer Natural Resources USA, Inc. has advised the Trust that it believes that the expectations reflected in such forward-looking statements are reasonable, no assurance can be given that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from expectations ("Cautionary Statements") are disclosed in this Form 10-K, including, without limitation in conjunction with the forward-looking statements included in this Form 10-K. A consolidated summary description of principal risk factors that could cause actual results to differ is also set forth in this Form 10-K under "Item 1A. Risk Factors." All subsequent written and oral forward-looking statements attributable to the Trust or persons acting on its behalf are expressly qualified in their entirety by the Cautionary Statements.

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PART I

Item 1.    Business.

DESCRIPTION OF THE TRUST

        The Mesa Offshore Trust (the "Trust"), created under the laws of the State of Texas, maintains its offices at the office of the Trustee, JPMorgan Chase Bank, N.A. (the "Trustee" or "JPMorgan"), 919 Congress Avenue, Austin, Texas 78701. The telephone number of the Trust is 1-800-852-1422. JPMorgan was formerly known as The Chase Manhattan Bank and is the successor by mergers to the original name of the Trustee, Texas Commerce Bank National Association. JPMorgan Chase & Co. and The Bank of New York Company ("BNY") announced in April 2006 an agreement pursuant to which BNY would acquire a portion of JPMorgan Chase & Co.'s corporate trust business in exchange for BNY's consumer small business and middle market banking business. This transaction did not include any transfer by JPMorgan of its obligations as Trustee of this Trust.

        The Trustee does not maintain a website for filings by the Trust with the U.S. Securities and Exchange Commission ("SEC"). Electronic filings by the Trust with the SEC are available free of charge through the SEC's website at www.sec.gov.

        The principal asset of the Trust consists of a 99.99% interest in the Mesa Offshore Royalty Partnership (the "Partnership"). The Trust was created on December 28, 1982, effective December 1, 1982, when Mesa Petroleum Co. conveyed to the Partnership certain overriding royalty interests (collectively, the "Royalty") carved out of Mesa Petroleum Co.'s existing working interests in ten producing and non-producing oil and gas leases offshore Louisiana and Texas (the "Royalty Properties"). The Partnership was formed for the purpose of receiving and holding the Royalty, receiving the proceeds from the Royalty, paying the liabilities and expenses of the Partnership and disbursing remaining revenues to the Trustee and Mesa Offshore Management Co., the managing general partner of the Partnership at that time, in accordance with their interests. Until August 7, 1997, MESA Inc. owned and operated its assets through Mesa Operating Co. ("Mesa"), the operator and the managing general partner of the Royalty Properties. On August 7, 1997, MESA Inc. merged with and into Pioneer Natural Resources Company ("PNRC"), formerly a wholly owned subsidiary of MESA Inc., and Parker & Parsley Petroleum Company merged with and into Pioneer Natural Resources USA, Inc. ("PNR") (successor to Mesa Operating Co.), a wholly owned subsidiary of PNRC (collectively, the mergers are referred to herein as the "Merger"). Subsequent to the Merger, PNR owns and operates its assets through PNRC and is also the managing general partner of the Partnership. PNR and PNRC are referred to hereinafter collectively as "Pioneer." As hereinafter used in this report, the term PNR generally refers to the operator of the Royalty Properties, unless otherwise indicated. See "—Legal Proceedings and Status of the Trust" beginning on page 9 of this Form 10-K and "—Timing of Liquidation" beginning on page 12 of this Form 10-K for additional information regarding Pioneer and the Trust.

        Units of beneficial interest ("units") in the Trust were issued on December 28, 1982 to Mesa Petroleum Co. shareholders, who received one unit for each share of Mesa Petroleum Co. common stock held.

        The terms of the Mesa Offshore Trust Indenture (the "Trust Indenture") provide, among other things, that: (1) the Trust cannot acquire any asset other than its interest in the Partnership and cannot engage in any business or investment activity; (2) the Royalty can be sold in part or in total for cash upon approval of the unitholders or upon liquidation of the Trust; (3) the Trustee can establish cash reserves and borrow funds to pay liabilities of the Trust and can pledge the assets of the Trust to secure payment of the borrowing; (4) the Trustee will make quarterly distributions of cash available for distribution to the unitholders in January, April, July and October of each year; and (5) the Trust will terminate upon the first to occur of the following events: (i) the total amount of cash received per year

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by the Trust for each of three successive years commencing after December 31, 1987 is less than ten times one-third of the total amount payable to the Trustee as compensation for such three-year period (the "Termination Threshold") or (ii) a vote by holders of a majority of the outstanding units. Amounts paid to the Trustee as compensation were approximately $177,000, $360,000 and $204,000 for the years 2007, 2006 and 2005, respectively. As described further in "—Legal Proceedings and Status of the Trust" beginning on page 9 of this Form 10-K, the Termination Threshold was met in each of the three consecutive years ending December 31, 2004. However, due to pending litigation involving the Trust that directly challenges whether the Termination Threshold has in fact been met, the Trustee cannot predict the timing of the sale of all or a portion of the Partnership assets as part of the Trust liquidation and termination. As part of the liquidation and eventual termination of the Trust, the Trustee will sell for cash all the assets held by the Partnership and make a final distribution to unitholders of any funds remaining after all Trust liabilities have been satisfied.

        The terms of the First Amended and Restated Articles of General Partnership of the Partnership (the "Partnership Agreement") provide that the Partnership shall dissolve upon the occurrence of any of the following: (1) December 31, 2030; (2) the election of the Trustee to dissolve the Partnership; (3) the termination of the Trust; (4) the bankruptcy of the Managing General Partner; or (5) the dissolution of the Managing General Partner or its election to dissolve the Partnership; provided that the Managing General Partner shall not elect to dissolve the Partnership so long as the Trustee remains the only other partner of the Partnership.

        Under the instrument conveying the Royalty to the Partnership (the "Conveyance"), the Trust is entitled to its share (99.99%) of 90% of the Net Proceeds, as hereinafter defined, realized from the sale of the hydrocarbons as, if and when produced from the Royalty Properties. See "Description of Royalty Properties" on page 14 of this Form 10-K. The Conveyance provides for a monthly computation of Net Proceeds. "Net Proceeds" means the excess of Gross Proceeds, as hereinafter defined, received by PNR during a particular period over operating and capital costs and an amount to be recovered for future abandonment costs during such period. "Gross Proceeds" means generally the amount received by PNR from the sale of its share of minerals covered by the Royalty, subject to certain adjustments. Operating costs means, generally, costs incurred by PNR in operating the Royalty Properties, including capital costs. If operating and capital costs exceed the Gross Proceeds for any month, the excess plus interest thereon at the prime rate of the Bank of America plus one-half percent is recovered out of future Gross Proceeds prior to the making of further payment to the Trust. The Trust is not liable for any operating costs or other costs or liabilities attributable to the Royalty Properties or minerals produced therefrom. PNR, as owner of the working interest in the Royalty Properties, is required to maintain books and records sufficient to determine the amounts payable under the Royalty. Additionally, in the event of a controversy between PNR and any purchaser as to the correct sale price for any production, amounts received by PNR and promptly deposited by it with an escrow agent are not considered as having been received by PNR and therefore are not subject to being payable with respect to the Royalty until the controversy is resolved; but all amounts thereafter paid to PNR by the escrow agent will be considered amounts received from the sale of production. Similarly, operating costs include any amounts PNR is required to pay whether as a refund, interest or penalty to any purchaser because the amount initially received by PNR as the sales price was in excess of that permitted by the terms of any applicable contract, statute, regulation, order, decree or other obligation. Within 30 days following the close of each calendar quarter, PNR is required to deliver to the Trustee a statement of the computation of Net Proceeds attributable to such quarter.

        The Royalty Properties are required to be operated by PNR in accordance with reasonable and prudent business judgment and good oil and gas field practices. PNR has the right to abandon any well or lease if, in its opinion, such well or lease ceases to produce or is not capable of producing oil, gas or other minerals in commercial quantities. PNR markets the production on terms deemed by it to be the best reasonably obtainable under the circumstances. See "Contracts" on page 16 of this Form 10-K.

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The Trustee has no power or authority to exercise any control over the operation of the Royalty Properties or the marketing of production therefrom.

        The discussions of terms of the Trust Indenture, the Partnership Agreement and the Conveyance contained herein are qualified in their entirety by reference to the Trust Indenture, the Partnership Agreement and the Conveyance themselves, which are exhibits to this Form 10-K and are available upon request from the Trustee.

        The Trust has no employees. Administrative functions of the Trust are performed by the Trustee.

DESCRIPTION OF THE UNITS

        Each unit is evidenced by a transferable certificate issued by the Trustee. Each unit ranks equally as to distributions and has one vote on any matter submitted to unitholders. Each unit evidences an undivided interest in the Trust, which in turn owns a 99.99% interest in the Partnership.

Distributions

        The Trustee determines for each month the amount of cash available for distribution for such month. Such amount (the "Monthly Distribution Amount") is equal to the excess, if any, of the cash distributed by the Partnership to the Trust during such month, plus any other cash receipts of the Trust during such month (other than interest earned on the Monthly Distribution Amount for any other month), over the liabilities of the Trust paid during such month, and adjusted for changes made by the Trustee during such month in any cash reserves established for the payment of contingent or future obligations of the Trust. The Monthly Distribution Amount for each month is payable to unitholders of record on the monthly record date (the "Monthly Record Date"), which is the close of business on the last business day of such month, or such later date as the Trustee determines is required to comply with legal or stock exchange requirements. However, to reduce the administrative expenses of the Trust, the Trust Indenture provides that the Trustee does not distribute cash monthly, but rather, during January, April, July and October of each year, distributes to each person who was a unitholder of record on a Monthly Record Date during one or more of the immediately preceding three months, the Monthly Distribution Amount for the month or months that he was a unitholder of record, together with interest earned on such Monthly Distribution Amount from the Monthly Record Date to the payment date.

Liability of Unitholders

        As regards to the unitholders, the Trustee is fully liable if the Trustee incurs any liability without ensuring that such liability will be satisfiable only out of the Trust assets (regardless of whether the assets are adequate to satisfy the liability) and in no event out of amounts distributed to, or other assets owned by unitholders. However, under Texas law, it is unclear whether a unitholder would be jointly and severally liable for any liability of the Trust in the event that all of the following conditions were to occur: (1) the satisfaction of such liability was not by contract limited to the assets of the Trust; (2) the assets of the Trust were insufficient to discharge such liability; and (3) the assets of the Trustee were insufficient to discharge such liability. Although each unitholder should weigh this potential exposure in deciding whether to retain or transfer his units, the Trustee is of the opinion that because of the passive nature of the Trust assets, the restrictions on the power of the Trustee to incur liabilities and the required financial net worth of any trustee, the imposition of any liability on a unitholder is extremely unlikely.

Federal Income Tax Matters

        This section is a summary of certain federal income tax matters of general application as of the date of this report. Except where indicated, the discussion below describes general federal income tax

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considerations applicable to individuals who are citizens or residents of the United States. Accordingly, the following discussion has limited application to domestic corporations and persons subject to specialized federal income tax treatment, such as regulated investment companies and insurance companies. It is impractical to comment on all aspects of federal, state, local and foreign laws that may affect the tax consequences of the transactions contemplated hereby and of an investment in the units as they relate to the particular circumstances of every unitholder. Federal income taxation is a highly complex matter that may be affected by many considerations. Each unitholder is encouraged to consult its own tax advisor with respect to its particular circumstances and the advisability of its ownership of units.

        This summary is based on current provisions of the Internal Revenue Code of 1986, as amended (the Code), existing and proposed Treasury Regulations thereunder and current administrative rulings and court decisions, all of which are subject to changes that may or may not be retroactively applied. Some of the applicable provisions of the Code have not been interpreted by the courts or the Internal Revenue Service (the "IRS"). No assurance can be provided that the statements set forth herein (which do not bind the IRS or the courts) will not be challenged by the IRS or will be sustained by a court if so challenged.

Ownership of Units

        The federal income tax consequences to the unitholders of owning units depend on whether the Trust is classifiable as a grantor trust, a non-grantor trust, or a corporation. The Trustee reports on the basis that the Trust is a grantor trust. Based on its recent audit policy, the IRS is expected to concur with such action. No IRS ruling has been received with respect to the Trust, however, and no court case has been decided involving identical facts and circumstances. It is possible, therefore, that the IRS will assert on audit that the Trust is taxable as a corporation and that a court might agree with that assertion.

Income and Depletion

        Royalty income, net of depletion and severance taxes, is portfolio income. Subject to certain exceptions and transitional rules, Royalty income cannot be offset by passive losses. Additionally, interest income is portfolio income. Administrative expense is an investment expense.

        Generally, prior to the Revenue Reconciliation Act of 1990, the transferee of an oil and gas property could not claim percentage depletion with respect to production from the property if it was "proved" at the time of the transfer. This rule is not applicable in the case of transfers of properties after October 11, 1990. Thus, eligible unitholders who acquired units after that date are entitled to claim an allowance for percentage depletion with respect to Royalty income attributable to these units to the extent that this allowance exceeds cost depletion as computed for the relevant period.

Backup Withholding

        Distributions from the Trust are generally subject to backup withholding at a rate of 28% of these distributions. Backup withholding will not normally apply to distributions to a unitholder, however, unless the unitholder fails to properly provide to the Trust his taxpayer identification number or the IRS notifies the Trust that the taxpayer identification number provided by the unitholder is incorrect.

Sale of Units

        Generally, except for recapture items, the sale, exchange or other disposition of a unit will result in capital gain or loss measured by the difference between the tax basis in the unit and the amount realized. Effective for property placed in service after December 31, 1986, the amount of gain, if any, realized upon the disposition of oil and gas property is treated as ordinary income up to the amount of

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intangible drilling and development costs incurred and depletion claimed to the extent it reduced the taxpayer's basis in the property. Under this provision, depletion attributable to a unit acquired after 1986 will be subject to recapture as ordinary income upon disposition of the unit or upon disposition of the oil and gas property to which the depletion is attributable. The balance of any gain or any loss will be capital gain or loss if the unit was held by the unitholder as a capital asset, either long-term or short-term depending on the holding period of the unit. This capital gain or loss will be long-term if a unitholder's holding period exceeds one year at the time of sale or exchange. A long-term capital gains rate of 15% applies to most capital assets sold or exchanged with a holding period of more than one year. Capital gain or loss will be short-term if the unit has not been held for more than one year at the time of sale or exchange.

Non-U.S. Unitholders

        In general, a unitholder who is a nonresident alien individual or which is a foreign corporation, each a "non-U.S. unitholder" for purposes of this discussion, will be subject to tax on the gross income produced by the Royalty at a rate equal to 30% or, if applicable, at a lower treaty rate. This tax will be withheld by the Trustee and remitted directly to the United States Treasury. A non-U.S. unitholder may elect to treat the income from the Royalty as effectively connected with the conduct of a United States trade or business under provisions of the Code or pursuant to any similar provisions of applicable treaties. Upon making this election a unitholder is entitled to claim all deductions with respect to that income, but he must file a United States federal income tax return to claim these deductions. This election once made is irrevocable unless an applicable treaty allows the election to be made annually.

        The Code and the Treasury Regulations thereunder treat the publicly traded Trust as if it were a United States real property holding corporation. Accordingly, non-U.S. unitholders may be subject to United States federal income tax on the gain on the disposition of their units.

        Federal income taxation of a non-U.S. unitholder is a highly complex matter which may be affected by many other considerations. Therefore, each non-U.S. unitholder is encouraged to consult with its own tax adviser with respect to its ownership of units.

Tax-Exempt Organizations

        The Royalty and interest income should not be unrelated business taxable income so long as, generally, a unitholder did not incur debt to acquire a unit or otherwise incur or maintain a debt that would not have been incurred or maintained if the unit had not been acquired. Legislative proposals have been made from time to time which, if adopted, would result in the treatment of Royalty income as unrelated business taxable income. Each tax-exempt unitholder should consult its own tax advisor with respect to the treatment of royalty income.

Widely Held Fixed Investment Trust Reporting Information

        The Trustee assumes that some Trust Units are held by a middleman, as such term is broadly defined in U.S. Treasury Regulations (and includes custodians, nominees, certain joint owners, and brokers holding an interest for a custodian in street name). Therefore, the Trustee considers the Trust to be a non-mortgage widely held fixed investment trust ("WHFIT") for U.S. federal income tax purposes. JPMorgan Chase Bank, N.A. ("Trustee" or "JPMorgan"), 919 Congress Avenue, Austin, Texas 78701, telephone number 1-800-852-1422, is the representative of the Trust that will provide tax information beginning with the 2008 tax year in accordance with applicable U.S. Treasury Regulations governing the information reporting requirements of the Trust as a WHFIT.

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LEGAL PROCEEDINGS AND STATUS OF THE TRUST

Hurricane Operations Update

        Hurricane Katrina struck the Gulf of Mexico in August 2005. The operator of the West Delta properties has informed PNR that the West Delta properties have been shut in since August 27, 2005 due to damage to the platform, the pipeline and the sales terminal. The operator has notified PNR that production at West Delta resumed at three of the four wells in October 2007 at a combined production rate of 4.8 MMCFD.

Status of the Trust

        The Trust Indenture provides that the Trust will liquidate if the total amount of cash per year received by the Trust falls below certain levels for each of three successive years. As a result of insufficient production on Royalty Properties nearing the end of their estimated productive lives, Royalty income received by the Trust in 2002, 2003 and 2004 fell below the Termination Threshold prescribed by the Trust Indenture. The Trustee has previously taken steps to begin the process of liquidating the Trust; however, the legal proceedings described herein directly challenge whether the Termination Threshold has in fact been met and thus have affected the liquidation process. See "—Timing of Liquidation" below. The Trustee, which has no authority or discretionary control over the timing of expenditures, production or income on the Royalty Properties, has no control over the occurrence of the Termination Threshold or its consequences.

        The Trust Indenture provides the Trustee a two-year period during which it must sell all of the assets of the Partnership. The Trust Indenture provides that such properties must be sold for cash and not for any other consideration. The Trustee expects that the sale process will be open to any persons desiring to participate, but, as is customary, access to information and participation may be limited to persons who execute confidentiality agreements regarding information provided by the working interest owners. The Trustee may also require bidders to identify themselves clearly and to represent or evidence sufficient financing in order to participate, as the Trustee expects payment will be required promptly after the close of bidding without any financing conditions. Accordingly, the auction may not be a "public" auction in the sense that it may not be open to anyone who does not satisfy these requirements.

Legal Proceedings

        On April 11, 2005, MOSH Holding, L.P. ("MHLP") filed an Original Petition in the District Court of Travis County, Texas, 250th Judicial District, against PNRC; PNR; Woodside Energy (USA), Inc. ("Woodside"); and JPMorgan, as Trustee of the Mesa Offshore Trust (Case No. GN501113) (the "Lawsuit"). The Lawsuit is currently before the 334th Judicial District of Harris Country, Texas (the "Court"). MHLP's Original Petition alleges Pioneer and Woodside are liable for various actions, including (1) a wrongful farmout by Pioneer to Woodside of the Brazos A-39 Lease, (2) a wrongful delay by Pioneer in producing the Brazos A-39 Lease and the Midway #5 well drilled thereon, (3) fraudulent accounting practices by Pioneer, (4) breach of fiduciary duty by Pioneer, (5) aiding and abetting breach of fiduciary duty by Woodside, (6) misapplication of Trust property by Pioneer, (7) conspiracy to misapply fiduciary property by Woodside and Pioneer, (8) common law fraud by Pioneer, (9) gross negligence by Pioneer, and (10) breach of the conveyance agreement by Pioneer. As described below, MHLP later added claims against the Trustee for (1) an accounting, and (2) breach of fiduciary duty. The remedies MHLP seeks include (a) reconstruing the Trust Indenture to determine that the Trust is not terminated because there has or should have been production that would have generated revenues to extend the life of the Trust, (b) requiring the Trustee to pursue certain claims, or to allow MHLP to pursue such claims, (c) setting aside any farmouts by Pioneer in which there have been conveyances to an alleged affiliate of Pioneer, (d) the removal of JPMorgan as Trustee, (e) the

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return or forfeiture of compensation to JPMorgan, (f) monetary damages against Pioneer, Woodside and JPMorgan, and (g) unspecified exemplary damages against all defendants.

        MHLP's Original Petition did not contain any claims against the Trustee, except to enjoin the Trustee from terminating the Trust during the pendency of the Lawsuit. In April 2005, the Trustee entered into an agreement with MHLP whereby the Trustee would not terminate the Trust without first giving MHLP at least sixty days written notice. This agreement allowed MHLP time to obtain documents and discovery from Pioneer and Woodside, and allowed the Trustee time to investigate the claims asserted by MHLP against Pioneer and Woodside to determine if they had any merit and, most importantly, whether they would benefit the Trust. During the six month period between April and October 2005, the Trustee conducted an independent investigation including: numerous meetings and discussions with the parties; reviewing the relevant documents with the Trustee's counsel; employing independent reservoir engineers to evaluate the reserves in which the Trust has an interest; engaging independent joint venture auditors to examine the accounting records of the operator, Pioneer, relating to revenues and expenses allocated to the Partnership's interests; and obtaining from both MHLP and Pioneer their respective legal analyses of the challenged farmout.

        Throughout 2005, the parties also anticipated that the Midway #5 well on the Brazos A-39 Lease that is the primary subject of the Lawsuit would go into production. Given the vast discrepancy between the reserves claimed by MHLP and those projected by Pioneer for the Midway #5 well, actual production results would significantly impact the Trustee's assessment of whether the Trust was better off with the cost-free override created by the Pioneer/Woodside farmout, or the prior cost-burdened net profits interest that MHLP seeks to restore through the Lawsuit. Unfortunately, Hurricane Katrina struck the Gulf of Mexico in August 2005 and delayed the commencement of production until 2006.

        Faced with this post-Katrina situation, the Trustee urged all the parties to consent to a bifurcated trial of the farmout issue on an expedited basis. The Trustee proposed to MHLP that if the Court determined that the farmout was not valid and that restoring the net profit interest would benefit the Trust, then the Trust would reimburse MHLP's reasonable attorneys' fees, up to $100,000, and the Trustee would allow MHLP's counsel to represent the Trust in prosecuting the damages portion of the case. Conversely, if MHLP were to lose on the expedited determination of the farmout issue, and in the absence of more evidence to support any ancillary claims, then MHLP would dismiss the other claims and would not be reimbursed, and the Trustee would move forward to terminate the Trust.

        While the Trustee, Pioneer, and Woodside all agreed to an expedited trial of the farmout issues, MHLP balked. Contrary to the assertions of MHLP and the Intervenor Plaintiffs identified below, the Trustee never agreed that the claims asserted by MHLP against Pioneer and Woodside "had merit"—the Trustee simply stated that the farmout issue might merit adjudication at that time to determine (1) if MHLP was legally correct, and (2) if setting aside the farmout would benefit the Trust.

        When MHLP refused to agree to an expedited and bifurcated trial as proposed by the Trustee, the Trustee informed MHLP that the Trustee's investigation of MHLP's allegations beyond the farmout issues failed to convince the Trustee that pursuing those claims and incurring the related legal fees and expenses would benefit the Trust. Moreover, the Trustee informed MHLP that the Trustee's independent joint venture auditors and reservoir engineers had not found any evidence to date to support any of MHLP's damage allegations.

        It was at this point, in November 2005, in the midst of the Trustee's negotiations with MHLP to obtain an agreed adjudication of MHLP's claims, that MHLP alleged for the first time that the Trustee had a conflict of interest because of JPMorgan's long-standing lending relationship with Pioneer. Although it is clear under the Trust Indenture, the Texas Trust Act, and relevant case law that JPMorgan is not precluded, by holding the position of Trustee, from pursuing commercial banking activities not involving Trust funds, MHLP amended its petition and asserted claims against the Trustee on November 28, 2005.

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        Although MHLP's claims against the Trustee were meritless, to avoid any further assertion that the Trustee could not impartially evaluate MHLP's claims, on November 30, 2005, JPMorgan announced its intention to resign as Trustee, effective January 31, 2006. On December 13, 2005, the lawsuit was transferred to the 334th Judicial District Court of Harris County, Texas. At a hearing on January 27, 2006 in the Harris County Court, the Court denied MHLP's motion for a temporary injunction to remove JPMorgan as Trustee and appoint a principal of MHLP, Timothy Roberson, as a temporary Trustee. At the Court's suggestion, JPMorgan agreed to continue as Trustee, until such time as a substitute trustee was found that fulfilled the qualifications of Trustee stated in the Trust Indenture. Since that hearing, neither MHLP nor Pioneer has identified a willing qualified successor Trustee that is not also a lender under one of Pioneer's credit facilities (which status MHLP contends is an alleged conflict of interest).

        On December 8, 2006, Dagger-Spine Hedgehog Corporation ("Dagger-Spine") filed a petition to intervene in the Lawsuit as a Plaintiff, alleging claims virtually identical to MHLP. Another group of unitholders, led by Keith A. Wiegand, (together with Dagger-Spine, the "Intervenors") also filed on March 9, 2007 a petition to intervene as plaintiffs in the Lawsuit, incorporating and adopting the same claims asserted by MHLP. MHLP and the Intervenors are referred to hereinafter as the "Plaintiffs."

        In 2006, after the Court denied MHLP's attempt to remove JPMorgan as Trustee, the parties pursued formal discovery in the Lawsuit. During this period, the Trustee continued to evaluate the merits of the alleged claims against Pioneer and Woodside. A central allegation by MHLP and the Intervenors is that Pioneer and Woodside delayed the commencement of production from the well drilled pursuant to the Pioneer-Woodside Farmout—the Midway #5 well on the Brazos A-39 Lease. Woodside and Pioneer witnesses have given sworn testimony in depositions about the commercial and technical reasons for the delays in bringing the well on line. The well commenced production in April 2006. After this time, the Trustee instructed its independent petroleum reserve engineers to evaluate how the production results and projected production from the well might affect the value of the Trust's interests. The Trustee's independent engineers determined that the initial data regarding projected production from the well did not warrant a material change in prior assessments of the value of the Trust's assets.

        Pioneer subsequently reported to the Trustee that production from the well was suspended in July 2006 due to mercury contamination identified at downstream facilities where the production from the well is commingled with production from other wells. An updated evaluation from the Trustee's independent petroleum reserve engineers estimated that revenues from future production from the well likely would not exceed the costs of drilling and completing the well. Accordingly, if the Partnership's interest in the underlying lease had remained, or was, a cost-burdened net profits interest, instead of the cost-free overriding royalty interest the Partnership held as a result of the Pioneer-Woodside Farmout, the Partnership would not have received, or would not receive, any payments from this production, and the Trust accordingly would not have received any associated distributions. Further, the production data did not support reserves of the size asserted by the Plaintiffs. The well resumed production in February 2007. The well was shut in again on April 18, 2007 due to an increase in hydrogen sulfide content coincidental with an increase in water production. Pioneer developed a hydrogen sulfide contingency plan, which was required and approved by the MMS, and has installed the necessary alarm and safety systems. The well returned to production on November 22, 2007 and is currently producing at 1-2 MMCFPD.

        On January 26, 2007, the Trustee reached a conditional settlement with Pioneer and Woodside of the claims asserted by the Plaintiffs against Pioneer and Woodside. The conditional settlement was set forth in the Mutual Release and Settlement Agreement dated as of January 26, 2007 (the "Pioneer/Woodside Settlement Agreement"). The Trustee filed a motion for approval of the Pioneer/Woodside Settlement Agreement with the Court on January 30, 2007. The Trustee believed that the Pioneer/Woodside Settlement Agreement was in the best interest of the unitholders, but the Plaintiffs opposed it. On

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June 19, 2007, the Court issued an Order denying the Trustee's motion to approve the Pioneer/Woodside Settlement Agreement. The Court also issued an Order setting the trial date to December 3, 2007.

        In June and July 2007, Pioneer and Woodside filed motions with the Court that argued that the claims against them did not have merit as a matter of law. Pioneer's motion included an argument that the Plaintiffs do not have the legal right to sue Pioneer because the claims belonged to the Trust, not the beneficiaries of the Trust. The motions are still pending before the Court. On October 19, 2007, the Trustee offered to assign to the Plaintiffs the Trust's claims against Pioneer and Woodside. Through their counsel, the Plaintiffs and the Trustee also began negotiating a resolution of the claims pending between them, and on October 26, 2007, the Trustee and the Plaintiffs informed the Court of an agreement in principle to settle.

        On December 3, 2007, JPMorgan, for itself and in its capacity as Trustee of the Trust, entered into a Settlement Agreement and Release with the Plaintiffs and additional Trust unitholders (the "Plaintiffs' Settlement Agreement"). Also on December 3, 2007, the Trustee and the Plaintiffs filed a Joint Motion for Approval of Settlement Agreement (the "Joint Motion"). In response to the Joint Motion, on December 21, 2007, Pioneer filed cross-claims against the Trustee seeking declaratory and injunctive relief to prevent certain aspects of the proposed settlement between the Trustee and the Plaintiffs, and alleging that all or part of such proposed settlement constituted a breach of contract and fiduciary duty. On January 14, 2008, the Trustee filed an answer to Pioneer's cross-claims, in which the Trustee denied the cross-claims in their entirety, stated that they were baseless, and set forth numerous affirmative defenses. On January 22, 2008, the Court issued an Order denying the Joint Motion. As a result, the conditions precedent to the Plaintiffs' Settlement Agreement cannot be satisfied, and the Plaintiffs' Settlement Agreement is null and void. In addition to denying the Joint Motion, the Court also considered and denied in the same Order (i) application by the Plaintiffs for the appointment of a temporary trustee and (ii) Pioneer's application for a temporary restraining order. As a result of the Court's denial of the Joint Motion, and the Court's denial of the Plaintiffs' application for the appointment of a temporary trustee, JPMorgan has elected not to resign and continues to serve as Trustee. The Trustee continues to desire the appointment of a successor Trustee.

        As of the date of this Form 10-K, there is no trial date set for the Lawsuit, but it is expected that the trial will be scheduled for late 2008. The Court has not yet entered a new Docket Control Order to govern the schedule of the Lawsuit as it proceeds to trial.

        The Trustee will make the full detail of the underlying data of the December 31, 2007 reserve report available for use in connection with the sale of the Partnership's Royalty Properties as part of the Trust termination. For more information regarding the estimated remaining life of each of the Royalty Properties, the estimated future net revenues of the Royalty Properties and information relating to farm-outs of interests on the Royalty Properties based on information provided by PNR to DeGolyer & MacNaughton ("D&M"), see "—Description of Royalty Properties" in this Form 10-K and Note 8 in the Notes to Financial Statements included elsewhere in this Form 10-K. The final distribution to unitholders will be an amount net of funds required to satisfy all Trust liabilities.

TIMING OF LIQUIDATION

        The Trust Indenture provides that the Trust will liquidate if the total amount of cash per year received by the Trust falls below certain levels for each of three successive years. As a result of continued declines in production on Royalty Properties nearing the end of their estimated productive lives, Royalty income received by the Trust in 2002, 2003 and 2004 fell below the Termination Threshold prescribed by the Trust Indenture.

        Due to the pending Lawsuit, the Trustee cannot predict the timing of the sale of all or a portion of the assets of the Partnership as part of the Trust termination.

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Trust Assets and Liabilities

        As a result of the triggering of the Termination Threshold effective January 1, 2005, the Trust is in the process of liquidation. However, due to the pending Lawsuit that directly challenges whether the Termination Threshold has in fact been met, the Trustee cannot predict the timing of the sale of all or a portion of the Royalty making up the Partnership assets as part of the Trust liquidation and termination. The below table presents the assets of the Trust at their estimated fair value:

The net overriding royalty interest in oil and gas properties at December 31, 2007 reflect the Trustee's estimate of value (in the absence of third-party appraisals or evaluations), based on the Trust's share of future net revenues from the net overriding royalty interest in the properties as of December 31, 2007. This estimate is based on the Trustee's current assessment of the impact of selling existing assets based on current market conditions, and includes the following assumptions:

•

The Trust's estimated share of proved oil and gas reserve volumes at December 31, 2007, was derived from the reserve report prepared by D&M.



•

Forward strip commodity prices on December 31, 2007 and then escalated 2% thereafter.



•

Includes approximately $1.5 million of excess production and future abandonment costs to be recouped by PNR.



•

Discount rate of 10%.



•

Future income taxes were not taken into account.

        The actual net proceeds from the sales of oil and gas properties may vary substantially from these estimates in value due to changes in current and estimated future oil and gas prices, subsequent production, estimates of actual abandonment costs and other factors which may be applied by the buyers.

        For all other assets presented in the above table, the Trustee believes that historical cost approximates fair market value due to the short-term nature of such assets. The Trustee will continue to reserve funds to recoup its previously established reserves to pay Trust expenses, which will primarily consist of expenses incurred by the Trustee to liquidate the Trust's assets. Any funds remaining after all expenses have been paid will be distributed to the unitholders.

        For more information regarding the estimated remaining life of each of the Royalty Properties, the estimated future net revenues of the Royalty Properties and information relating to farm-outs of interests on the Royalty Properties based on information provided by PNR to D&M, see "—Description of Royalty Property" in this Form 10-K and Note 8 in the Notes to Financial

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Statements included elsewhere in this Form 10-K. The sale of the assets of the Trust estate may include the related rights to abandonment accruals made by PNR. As explained in "Regulation and Prices—Platform Abandonment and Removal" on page 19 of this Form 10-K, PNR can withhold from the Trust a reserve to cover its share of those future abandonment and removal costs; however, no funds have been withheld as of December 31, 2007.

DESCRIPTION OF ROYALTY PROPERTIES

Producing Acreage and Wells as of December 31, 2007

(1)

Dual completions are counted as one well. For information regarding wells producing at December 31, 2007, see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Status of the Trust—Properties producing as of December 31, 2007" in Item 7 on page 27 of this Form 10-K. As of January 31, 2008, only the wells on Brazos A-39 and West Delta 61 were capable of producing.



(2)

Net Producing Acres are calculated by multiplying gross producing acres by the net royalty interest (as defined by the Conveyance) attributable to the Trust for each property. The current net interests attributable to the Trust after giving effect to Farmout agreements are described in Item 7 of this Form 10-K.



(3)

All wells on South Marsh Island 155 and 156 leases were plugged and abandoned in 2002. PNR abandoned the platform for these two properties in 2003. All wells were plugged and abandoned and the platform was abandoned on West Delta 62 during 2003 and the lease was relinquished.



(4)

All wells were plugged and abandoned and the platform was abandoned on Matagorda Island 624 during 2003 and the lease was relinquished.

Reserves

        A study of the proved oil and gas reserves attributable to the Partnership as of December 31, 2007, has been made by D&M in a letter (the "Reserve Report") attached as Exhibit 99(a) and incorporated herein by reference. The Reserve Report reflects estimated reserve quantities and future net revenue based upon estimates of the future timing of actual production without regard to when received in cash by the Trust, which differs from the manner in which the Trust recognizes and accounts for its Royalty income. The following tables are based on the information contained in the Reserve Report and summarize (1) estimates of the Trust's gross and net proved reserves as of December 31, 2007, and (2) the estimated future revenue and costs attributable to the Trust's royalty interest in the proved reserves, as of December 31, 2007, of the properties evaluated.

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*

Future income tax expenses were not taken into account in the preparation of these estimates.

        For further information regarding the Net Overriding Royalty Interest, the Basis of Accounting for the Trust and Supplemental Reserve Information, see Notes 3, 4 and 8, respectively, in the Notes to Financial Statements contained in Item 8 of this Form 10-K.

        There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The preceding reserve data based on the Reserve Report represent estimates only and should not be construed as being exact. Reserve assessment is a subjective process of estimating the recovery from underground accumulations of gas and oil that cannot be measured in an exact way and estimates of other persons might differ materially from those of D&M. Accordingly, reserve estimates are often different from the quantities of hydrocarbons that are ultimately recovered.

        Also, while estimates of reserves attributable to the Royalty Properties are shown in order to comply with requirements of the SEC, there is no precise method of allocating estimates of physical quantities of reserves between PNR and the Partnership, since the Royalty is not a working interest and the Partnership does not own and is not entitled to receive any specific volume of reserves from the Royalty. Reserve quantities in the previously mentioned reserve study have been allocated based on the method referenced in the Reserve Report. The quantities of reserves attributable to the Partnership will be affected by future changes in various economic factors utilized in estimating future gross and net revenues from the Royalty Properties. Therefore, the estimates of reserves set forth in the Reserve Report are to a large extent hypothetical and differ in significant respects from estimates of reserves attributable to a working interest.

        Moreover, the discounted present values in the Reserve Report should not be construed as the current market value of the estimated gas and oil reserves attributable to the Royalty Properties or the costs that would be incurred to obtain equivalent reserves, since a market value determination would include many additional factors. In accordance with applicable regulations of the SEC, estimated future net revenues were based, generally, on current prices and costs, whereas actual future prices and costs may be materially greater or less. The estimates in the Reserve Report use market prices as of December 31, 2007. These prices (having weighted average year end prices of $92.52 to $95.95 per barrel of oil and condensate and $6.94 to $7.33 per Mcf of natural gas as of December 31, 2007) were held constant over the estimated life of the Royalty Properties. These prices were influenced by seasonal demand for natural gas and may not be the most appropriate or representative prices to use for estimating future revenues or related reserve data. The average price of natural gas sold from the Royalty Properties during 2007 was $6.79 per Mcf, representing a combination of contract prices and spot market prices, while the average price of crude oil, condensate and natural gas liquids was $53.84 per barrel. See Management's Discussion and Analysis of Financial Condition and Results of Operations "—Financial and Operational Overview—Production and Price Review" of this Form 10-K.

        The following is a summary of the estimated remaining life for each of the Royalty Properties provided to the Trustee by D&M as of December 31, 2007. There are numerous uncertainties present in estimating the remaining productive lives for the Royalty Properties. The following summary

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represents an estimate only and should not be construed as being exact. The estimated remaining productive life of each property varies depending on the recoverable reserves and annual production assumed by D&M. In addition, future economic and operating conditions may cause significant changes in these estimates.

(1)

Under the Trust Indenture, the Trust is to liquidate and then terminate in the event the total amount of cash received per year by the Trust falls below certain levels. Accordingly, it would be possible for the Trust to terminate even though some of the Royalty Properties continued to have remaining productive lives. See "Business—Legal Proceedings and Status of the Trust" on page 9 of this Form 10-K and see "Business—Timing of Liquidation" on page 12 of this Form 10-K.



(2)

Estimates of remaining lives may vary significantly from year to year.

        The future net revenues contained in the Reserve Report have not been reduced for future general and administrative costs and expenses of the Trust, which are expected to approximate $1,200,000 annually.

        The general and administrative costs and expenses of the Trust may increase in future years, depending on the amount of royalty income, increases in accounting, engineering, legal and other professional fees and other factors.

CONTRACTS

General

        PNR has advised the Trust that during 2007 its offshore gas production was marketed under short-term contracts at spot market prices primarily to TOTAL S.A. PNR has further advised the Trust that it expects to continue to market its production under short-term contracts for the foreseeable future. Spot market prices for natural gas in 2007 were generally lower than spot market prices in 2006.

Market for Natural Gas

        The amount of cash distributions by the Trust is dependent on, among other things, the sales prices for natural gas produced from the Royalty Properties and the quantities of gas sold. The natural gas industry in the United States during the 1990's was affected generally by a surplus in natural gas deliverability in comparison to demand. Demand for gas declined during this period due to a number of factors including the implementation of energy conservation programs, a shift in economic activity away from energy intensive industries and competition from alternative fuel sources such as residual fuel oil, coal and nuclear energy. In late 2001 and early 2002, demand for natural gas increased as a result of the increase in clean burning natural gas fired power generation, the increase in the usage of electrical power fueled by the expanding U.S. economy and a return to seasonally cold winters. Annual wellhead prices generally increased from $2.95 per Mcf in 2002, increased to $5.09 per Mcf in 2003, to $5.49 per Mcf in 2004, to $5.65 in 2005, to $6.42 in 2006 but decreased to $6.39 in 2007 according to the Natural Gas Monthly published by the Energy Information Administration of the Department of Energy.

        The seasonal nature of demand for natural gas and its effects on sales prices and production volumes may cause the amounts of cash distributions by the Trust to vary substantially on a seasonal basis. Generally, production volumes and prices are higher during the first and fourth quarters of each calendar year due primarily to peak demand in these periods. Because of the time lag between the date on which PNR receives payment for production from the Royalty Properties and the date on which

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distributions are made to unitholders, the seasonality that generally affects production volumes and prices is generally reflected in distributions to unitholders in later periods.

Competition

        The production and sale of gas from the areas in which the Royalty Properties are located is highly competitive and PNR has a number of competitors in these areas. PNR has advised the Trust that it believes that its competitive position in these areas is affected by price, contract terms and quality of service. PNR's business is affected not only by such competition, but also by general economic developments, governmental regulations and other factors.

Marketing of Liquids

        PNR generally reserves in its gas purchase contracts the right to extract condensate and other liquid and liquefiable hydrocarbons from all gas produced. PNR is currently selling the condensate and other liquids to purchasers under contracts with terms of one year or less.

REGULATION AND PRICES

General

        The production and sale of natural gas from the Royalty Properties are affected from time to time in varying degrees by political developments and federal, state and local laws and regulations. In particular, oil and gas production operations and economics are, or in the past have been, affected by price controls, taxes, conservation, safety, environmental and other laws relating to the petroleum industry, by changes in such laws and by constantly changing administrative regulations.

Operating Hazards and Uninsured Risks

        PNR's oil and gas activities are subject to all of the risks normally incident to exploration for and production of oil and gas, including blowouts, cratering and fires, each of which could result in damage to life and property. Offshore operations are subject to a variety of operating risks, such as hurricanes and other adverse weather conditions and lack of access to existing pipelines or other means of transporting production. Furthermore, offshore oil and gas operations are subject to extensive governmental regulations, including certain regulations that may, in certain circumstances, impose absolute liability for pollution damages, and to interruption or termination by governmental authorities based on environmental or other considerations. In accordance with customary industry practices, PNR carries insurance against some, but not all, of these risks. Losses and liabilities resulting from such events would reduce revenues and increase costs to the Trust to the extent not covered by insurance.

FERC Regulation

        In general, the FERC regulates the transportation of natural gas in interstate commerce by interstate pipelines. Over the course of approximately the previous decade, the FERC adopted regulations resulting in a restructuring of the natural gas industry. The principal elements of this restructuring were the requirement that interstate pipelines separate, or "unbundle," the various services offered on their systems into individual components, with all transportation services to be provided on a non-discriminatory basis, and the prohibition against an interstate pipeline providing gas sales services except through separately-organized affiliates. In various rulemaking proceedings following its initial unbundling requirement, the FERC has refined its regulatory program applicable to interstate pipelines in various respects, and it has announced that it will continue to monitor these regulations to determine whether further changes are needed. As to these various developments, the working interest owners have advised the Trust that the on-going and evolving nature of these regulatory initiatives makes it impossible to predict their ultimate impact on the prices, markets or terms of sale of natural gas related to the Trust.

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State and Other Regulation

        State regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, non-discriminatory take requirements. Some states have implemented more stringent legislation in recent years to regulate gathering rates charged by gas gathering companies, but to date the effect to PNR in connection with the Royalty Properties has been minimal.

        Natural gas pipeline facilities used for the transportation of natural gas in interstate commerce are subject to Federal minimum safety requirements. These requirements, however, are not applicable to, inter alia,: (1) onshore gathering facilities outside: (i) the limits of any incorporated or unincorporated city, town, or village; and (ii) any designated residential or commercial area; or (2) pipeline facilities on the Outer Continental Shelf ("OCS") upstream of the point at which operating responsibility transfers from a producing operator to a transporting operator. See 49 C.F.R. § 192.1(b). We are informed that the Royalty Properties are located in Federal waters on the OCS. The standards governing pipeline safety have undergone recent changes and it is possible that future changes in the regulations and statutes may occur which may increase the stringency of the standards or expand the applicability of the standards to facilities not currently covered.

Environmental

        PNR's operations are subject to numerous federal, state and local laws and regulations controlling the discharge of materials into the environment or otherwise relating to the protection of the environment, including the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA" or "Superfund"), the Solid Waste Disposal Act, the Clean Air Act, and the Federal Water Pollution Control Act. These laws and regulations, including their state counterparts, can impose liability upon the lessee under a lease for the cost of cleanup of discharged materials resulting from a lessee's operations or can subject the lessee to liability for damages to natural resources. Violations of environmental laws, regulations, or permits can result in civil and criminal penalties as well as potential injunctions curtailing operations in affected areas and restrictions on the injection of liquids into the subsurface that may contaminate groundwater. PNR maintains insurance for costs of cleanup operations, but it is not fully insured against all such risks. A serious release of regulated materials could result in the U.S. Department of the Interior requiring lessees under federal leases to suspend or cease operations in the affected area. In addition, the recent trend toward stricter standards and regulations in environmental legislation is likely to continue. For example, legislation has been proposed in Congress that would reclassify certain oil and gas production wastes as "hazardous wastes" which would subject the handling, disposal and cleanup of these wastes to more stringent requirements and result in increased operating costs for the Royalty Properties, as well as the oil and gas industry in general. State initiatives to further regulate the disposal of oil and gas wastes are also pending in certain states, and these initiatives could have a similar impact on the Royalty Properties.

        From time to time, federal and state environmental agencies propose regulations which could have a direct and material impact on PNR's operations. For example, under the Oil Pollution Act of 1990, as amended by the Coast Guard Authorization Act of 1996 (collectively, "OPA"), parties responsible for offshore facilities must establish and maintain evidence of oil-spill financial responsibility ("OSFR") for costs attributable to potential oil spills. OPA requires a minimum of $35 million in OSFR for offshore facilities located on the OCS. This amount is subject to upward regulatory adjustment up to $150 million. Responsible parties for more than one offshore facility are required to provide OSFR only for their offshore facility requiring the highest OSFR. In 1998, the Minerals Management Service ("MMS") adopted regulations for establishing the amount of OSFR required for particular facilities. The amount of OSFR increases as the volume of a facility's worst-case oil spill increases. Accordingly, for facilities with worst-case spills of less than 35,000 barrels, only $35 million in OSFR is required; for worst-case spills of over 35,000 barrels, $70 million is required; for worst-case spills of over 70,000 barrels, $105 million is required; and for worst-case spills of over 105,000 barrels, $150 million is required. In addition, all OSFR below $150 million remains subject to upward regulatory adjustment if

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