MESA ROYALTY TRUST/TX - Quarter Report: 2003 September (Form 10-Q)

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

Commission file number 1-7884

MESA ROYALTY TRUST

(Exact Name of Registrant as Specified in its Charter)

800-852-1422
(Registrant's Telephone Number, Including Area Code)

        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 /x/    No / /

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

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

        As of November 13, 2003—1,863,590 Units of Beneficial Interest in Mesa Royalty Trust.

PART I—FINANCIAL INFORMATION

Item 1.    Financial Statements.

MESA ROYALTY TRUST

STATEMENTS OF DISTRIBUTABLE INCOME
(Unaudited)

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

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

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MESA ROYALTY TRUST

STATEMENTS OF CHANGES IN TRUST CORPUS

(Unaudited)

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

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MESA ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

Note 1—Trust Organization

        The Mesa Royalty Trust (the "Trust") was created on November 1, 1979 when Mesa Petroleum Co. conveyed to the Trust a 90% net profits overriding royalty interest (the "Royalty") in certain producing oil and gas properties located in the Hugoton field of Kansas, the San Juan Basin field of New Mexico and Colorado and the Yellow Creek field of Wyoming (collectively, the "Royalty Properties"). Mesa Petroleum Co. was the predecessor to Mesa Limited Partnership ("MLP"), the predecessor to MESA Inc. On April 30, 1991, MLP sold its interests in the Royalty Properties located in the San Juan Basin field to ConocoPhillips, successor by merger to Conoco Inc. ("ConocoPhillips"). ConocoPhillips sold the portion of its interests in the San Juan Basin Royalty Properties located in Colorado to MarkWest Energy Partners, Ltd. (effective January 1, 1993) and Red Willow Production Company (effective April 1, 1992). On October 26, 1994, MarkWest Energy Partners, Ltd. sold substantially all of its interest in the Colorado San Juan Basin Royalty Properties to Amoco Production Company ("Amoco"), a subsidiary of BP Amoco. Until August 7, 1997, MESA Inc. operated the Hugoton Royalty Properties through Mesa Operating Co., a wholly owned subsidiary of MESA Inc. On August 7, 1997, MESA Inc. merged with and into Pioneer Natural Resources Company ("Pioneer"), formerly a wholly owned subsidiary of MESA Inc., and Parker & Parsley Petroleum Company merged with and into Pioneer Natural Resources USA, Inc. (successor to Mesa Operating Co.), a wholly owned subsidiary of Pioneer ("PNR") (collectively, the mergers are referred to herein as the "Merger"). Subsequent to the Merger, the Hugoton Royalty Properties have been operated by PNR. The San Juan Basin Royalty Properties located in New Mexico are operated by ConocoPhillips. The San Juan Basin Royalty Properties located in Colorado are operated by Amoco. As used in this report, PNR refers to the operator of the Hugoton Royalty Properties, ConocoPhillips refers to the operator of the San Juan Basin Royalty Properties, other than the portion of such properties located in Colorado, and Amoco refers to the operator of the Colorado San Juan Basin Royalty Properties unless otherwise indicated. The terms "working interest owner" and "working interest owners" generally refer to the operators of the Royalty Properties as described above, unless the context in which such terms are used indicates otherwise.

Note 2—Basis of Presentation

        The accompanying unaudited financial information has been prepared by JPMorgan Chase Bank (the "Trustee"), in accordance with the instructions to Form 10-Q. JPMorgan Chase Bank 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. The Trustee believes such information includes all the disclosures necessary to make the information presented not misleading. The information furnished reflects all adjustments which are, in the opinion of the Trustee, necessary for a fair presentation of the results for the interim periods presented. The financial information should be read in conjunction with the financial statements and notes thereto included in the Trust's 2002 Annual Report on Form 10-K.

        The Mesa Royalty Trust Indenture was amended in 1985, the effect of which was an overall reduction of approximately 88.56% in the size of the Trust; therefore, the Trust is now entitled each month to receive 90% of 11.44% of the net proceeds for the preceding month. Generally, net proceeds means the excess of

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the amounts received by the working interest owners from sales of oil and gas from the Royalty Properties over operating and capital costs incurred.

        The financial statements of the Trust are prepared on the following basis:

        (a)   Royalty income recorded for a month is the amount computed and paid by the working interest owners to the Trustee for such month rather than either the value of a portion of the oil and gas produced by the working interest owners for such month or the amount subsequently determined to be the Trust's proportionate share of the net proceeds for such month;

        (b)   Interest income, interest receivable, and distributions payable to unitholders include interest to be earned on short-term investments from the financial statement date through the next date of distribution;

        (c)   Trust general and administrative expenses, net of reimbursements, are recorded in the month they accrue;

        (d)   Amortization of the net overriding royalty interests, which is calculated on a unit-of-production basis, is charged directly to trust corpus since such amount does not affect distributable income; and

        (e)   Distributions payable are determined on a monthly basis and are payable to unitholders of record as of the last business day of each month or such other day as the Trustee determines is required to comply with legal or stock exchange requirements. However, cash distributions are made quarterly in January, April, July and October, and include interest earned from the monthly record dates to the date of distribution.

        This basis for reporting Royalty income is thought to be the most meaningful because distributions to the unitholders for a month are based on net cash receipts for such month. However, it will differ from the basis used for financial statements prepared in accordance with accounting principles generally accepted in the United States. Under these accounting principles, Royalty income for a month would be based on net proceeds from production for such month without regard to when calculated or received and interest income for a month would be calculated only through the end of such month.

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Item 2.    Management's Discussion and Analysis of Financial Condition and Results of Operations

        The following review of the Trust's financial condition and results of operations should be read in conjunction with the financial statements and notes thereto. The discussion of net production attributable to the Hugoton and San Juan properties represents production volumes that are to a large extent hypothetical as the Trust does not own and is not entitled to any specific production volumes. See Note 7 to the financial statements in the Trust's Form 10-K. Any discussion of "actual" production volumes represents the hydrocarbons that were produced from the properties in which the Trust has an overriding royalty interest.

Note Regarding Forward-Looking Statements

        This Form 10-Q 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-Q, including without limitation the statements under "Management's Discussion and Analysis of Financial Condition and Results of Operations" are forward-looking statements. Although the Working Interest Owners have advised the Trust that they believe that the expectations reflected in the forward-looking statements contained herein 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-Q and in the Trust's Form 10-K, including under the section "Business—Principal Trust 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.

SUMMARY OF ROYALTY INCOME AND AVERAGE PRICES

        Royalty income is computed after deducting the Trust's proportionate share of capital costs, operating costs and interest on any cost carryforward from the Trust's proportionate share of "Gross Proceeds," as defined in the Royalty conveyance. The following unaudited summary illustrates the net effect of the components of the actual Royalty computation for the periods indicated:

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(1)

Gross Proceeds from natural gas liquids attributable to the Hugoton and San Juan Basin Properties are net of a volumetric in-kind processing fee retained by PNR and ConocoPhillips, respectively.

(2)

Capital costs recovered represents capital costs incurred during the current or prior periods to the extent that such costs have been recovered by the working interest owners from current period Gross Proceeds. Cost carryforward represents capital costs incurred during the current or prior periods which will be recovered from future period Gross Proceeds. The cost carryforward resulting from the Fruitland Coal drilling program was $318,676 and $318,839 at September 30, 2003 and September 30, 2002, respectively. The cost carryforward at September 30, 2003 and September 30, 2002 relate solely to the San Juan Basin Colorado properties.

Three Months Ended September 30, 2003 and 2002

        The distributable income of the Trust for each period includes the Royalty income received from the working interest owners during such period, plus interest income earned to the date of distribution. Trust administration expenses are deducted in the computation of distributable income. Distributable income for the quarter ended September 30, 2003 was $2,290,593, representing $1.2291 per unit, compared to $1,485,982, representing $.7974 per unit, for the quarter ended September 30, 2002. Based on 1,863,590 units outstanding for the quarters ended September 30, 2003 and 2002, respectively, the per unit distributions were as follows:

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Hugoton Field

        Natural gas and natural gas liquids from the Hugoton field and attributable to the Royalty accounted for approximately 54% of the Royalty income of the Trust during the third quarter of 2003. PNR has advised the Trust that since June 1, 1995 natural gas produced from the Hugoton field has generally been sold under short-term and multi-month contracts at market clearing prices to multiple purchasers including Tenaska, Greely Gas, Oneok Gas Marketing Inc., Amoco, and Anadarko Energy Services, Inc. PNR has advised the Trust that it expects to continue to market gas production from the Hugoton field under short-term and multi-month contracts. Overall market prices received for natural gas from the Hugoton Royalty Properties were higher in the third quarter of 2003 as compared to the third quarter of 2002.

        In June 1994, PNR entered into a Gas Transportation Agreement ("Gas Transportation Agreement") with Western Resources, Inc. ("WRI") for a primary term of five years commencing June 1, 1995. This contract has been continued in effect on a year-to-year basis since June 1, 2000. PNR has extended the contract to June 1, 2004. Pursuant to the Gas Transportation Agreement, WRI has agreed to compress and transport up to 160 MMcf per day of gas and redeliver such gas to PNR at the inlet of PNR's Satanta Plant. PNR agreed to pay WRI a fee of $0.06 per Mcf escalating 4% annually as of June 1, 1996. This Gas Transportation Agreement has been assigned to Kansas Gas Service (Oneok).

        Royalty income attributable to the Hugoton Royalty increased to $1,241,481 in the third quarter of 2003, as compared to $905,056 in the third quarter of 2002, primarily due to higher prices received for production of natural gas and natural gas liquids from the Hugoton Royalty Properties. The average price received in the third quarter of 2003 for natural gas and natural gas liquids sold from the Hugoton Royalty Properties was $5.12 per Mcf and $20.08 per barrel, respectively, compared to $3.20 per Mcf and $15.98 per barrel during the same period in 2002. Net production attributable to the Hugoton Royalty was 189,877 Mcf of natural gas and 13,412 barrels of natural gas liquids in the third quarter of 2003 as compared to 209,940 Mcf of natural gas and 14,596 barrels of natural gas liquids in the third quarter of 2002. Actual production volumes attributable to the Hugoton properties decreased to 257,460 Mcf of natural gas and 13,410 barrels of natural gas liquids in the third quarter of 2003 as compared to 292,955 Mcf of natural gas and 14,596 barrels of natural gas liquids for the same period in 2002 as a result of natural production decline.

        Allowable rates of production in the Hugoton field are set by the Kansas Corporation Commission (the "KCC") based on the level of market demand. The KCC set the Hugoton field allowable for the period October 1, 2003 through March 31, 2004, at 119.4 Bcf of gas, compared with 134.7 Bcf of gas during the same period last year.

San Juan Basin

        Royalty income from the San Juan Basin Royalty Properties is calculated and paid to the Trust on a state-by-state basis. Royalty income from the San Juan Basin Royalty Properties located in the state of New Mexico was $1,059,476 during the third quarter of 2003 as compared to $583,100 in the third quarter of 2002. The increase in Royalty income in the third quarter of 2003 as compared to the same period in 2002 is primarily due to higher prices received for production of natural gas and natural gas liquids from the San Juan Basin Royalty Properties. No Royalty income was received from Amoco with respect to the San Juan Basin Royalty Properties located in the state of Colorado for the third quarter of 2003 or 2002, as costs associated with the Fruitland Coal drilling program on such properties have not been fully recovered.

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Net production attributable to the San Juan Basin Royalty was 184,251 Mcf of natural gas and 10,799 barrels of natural gas liquids in the third quarter of 2003 as compared to 151,159 Mcf of natural gas and 11,662 barrels of natural gas liquids in the third quarter of 2002. The average price received in the third quarter of 2003 for natural gas sold from the San Juan Basin Royalty Properties was $4.49 per Mcf and $21.50 per barrel, compared to $2.60 per Mcf and $16.30 per barrel during the same period in 2002. Actual production volumes attributable to the San Juan Basin properties decreased to 279,416 Mcf of natural gas and 14,303 barrels of natural gas liquids in the third quarter of 2003 as compared to 338,000 Mcf of natural gas and 16,519 barrels of natural gas liquids for the same period in 2002 as a result of natural production decline.

        Substantially all of the natural gas that is currently being produced from the San Juan Basin Royalty Properties is currently being sold on the spot market.

        The Trust's interest in the San Juan Basin was conveyed from PNR's working interest in 31,328 net producing acres in northwestern New Mexico and southwestern Colorado. The San Juan Basin New Mexico reserves as of December 31, 2002 represent approximately 58% of the Trust's estimated reserves as of December 31, 2002. The San Juan Basin Royalty Properties located in Colorado account for less than 5% of the Trust's reserves.

        No distributions related to the Colorado portion of the San Juan Basin Royalty have been made since 1990, as the costs of the Fruitland Coal drilling in Colorado have not yet been recovered.

Nine Months Ended September 30, 2003 and 2002

        Distributable income increased to $7,101,792 for the nine months ended September 30, 2003 from $3,460,012 for the same period in 2002.

Hugoton Field

        Royalty income attributable to the Hugoton Royalty Properties increased to $4,107,305 for the nine months ended September 30, 2003 from $2,174,580 for the same period in 2002 primarily due to higher natural gas and average natural gas liquid prices received. The average price received in the first nine months of 2003 for natural gas and natural gas liquids sold from the Hugoton field was $5.07 per Mcf and $21.74 per barrel, compared to $2.57 per Mcf and $13.74 per barrel during the same period in 2002. Net Production attributable to the Hugoton Royalty was 637,233 Mcf of natural gas and 40,319 barrels of natural gas liquids in the nine months ended September 30, 2003 as compared to 595,268 Mcf of natural gas and 46,925 barrels of natural gas liquids in the nine months ended September 30, 2002. Actual production volumes attributable to the Hugoton properties decreased to 799,785 Mcf of natural gas and 40,318 barrels of natural gas liquids in the nine months ended September 30, 2003 as compared to 917,730 Mcf of natural gas and 46,921 barrels of natural gas liquids for the nine months ended September 30, 2002 as a result of natural production decline.

San Juan Basin

        Royalty income attributable to the New Mexico San Juan Basin Royalty Properties increased to $3,019,646 for the first nine months of 2003 compared to $1,307,765 in the first nine months of 2002. The average price received in the first nine months of 2003 for natural gas and natural gas liquids sold from the San Juan Basin was $4.43 per Mcf and $22.40 per barrel compared to $2.51 per Mcf and $15.30 per barrel

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during the same period in 2002. No Royalty income was received from San Juan Basin Royalty Properties located in Colorado for the nine months ended September 30, 2003 and 2002, as costs associated with Fruitland Coal drilling on such properties have not been fully recovered. Net Production attributable to the San Juan Basin Royalty was 520,411 Mcf of natural gas and 31,885 barrels of natural gas liquids in the nine months ended September 30, 2003 as compared to 310,336 Mcf of natural gas and 34,563 barrels of natural gas liquids in the nine months ended September 30, 2002. Actual production volumes attributable to the San Juan Basin properties decreased to 853,557 Mcf of natural gas and 42,478 barrels of natal gas liquids in the nine months ended September 30, 2003 as compared to 1,011,184 Mcf of natural gas and 48,984 barrels of natural gas liquids for the nine months ended September 30, 2002 as a result of natural production decline.

Item 3.    Quantitative and Qualitative Disclosure About Market Risk.

        The Trust does not utilize market sensitive instruments. However, see the discussion of marketing by the working interest owners above.

Item 4.    Controls and Procedures.

        Evaluation of Disclosure Controls and Procedures.    Trustee maintains disclosure controls and procedures designed to ensure that information required to be disclosed by the Trust in the reports that it files or submits under the Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and regulations. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by the Trust is accumulated and communicated by the working interest owners to the Trustee and its employees who participate in the preparation of the Trust's periodic reports as appropriate to allow timely decisions regarding required disclosure.

        As of the end of the period covered by this report, the Trustee carried out an evaluation of the Trustee's disclosure controls and procedures. Mike Ulrich, as Trust Officer of the Trustee, has concluded that the controls and procedures are effective, while noting certain limitations on disclosure controls and procedures as set forth below.

        Due to the contractual arrangements of (i) the Trust Indenture and (ii) the rights of the Trust under the Conveyance regarding information furnished by the working interest owners, there are certain potential weaknesses that may limit the effectiveness of disclosure controls and procedures established by the Corporate Trustee or its employees and their ability to verify the accuracy of certain financial information. The contractual limitations creating potential weaknesses in disclosure controls and procedures may be deemed to include:

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The working interest owners alone control (i) historical operating data, including production volumes, marketing of products, operating and capital expenditures, environmental and other liabilities, the effects of regulatory changes and the number of producing wells and acreage, (ii) plans for future operating and capital expenditures, (iii) geological data relating to reserves, as well as the reserve reports that contain projected production, operating expenses and capital expenses, and (iv) information relating to projected production. While the Trustee requests material information for use in periodic reports as part of its disclosure controls and procedures, the Trustee

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does not control this information and relies entirely on the working interest owners to provide accurate and timely information when requested for use in the Trust's periodic reports.

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Under the terms of the Trust Agreement, the Trustee is entitled to rely, and in fact relies, on certain experts in good faith, including the independent public accountants with respect to annual audits of financial data provided by the working interest owners. Other than contracting independent auditors and reviewing information supplied by the working interest owners, the Trustee makes no independent or direct verification of this financial information. While the Trustee has no reason to believe its reliance upon experts is unreasonable, this reliance on experts and limited access to information may be viewed as a weakness.

        The Trustee does not intend to expand its responsibilities beyond those permitted or required by the Trust Indenture and those required under applicable law.

        Changes in Internal Controls.    To the knowledge of the Trustee, there have been no significant changes in the Trust's internal controls or in other factors that could significantly affect the Trust's internal controls subsequent to the date the Trustee completed its evaluation. The Trustee notes for purposes of clarification that it has no authority over, and makes no statement concerning, the internal controls of the working interest owners.

        Changes in internal control over financial reporting.    The Trustee has not identified any changes in the Trust's internal control over financial reporting during the Trust's last fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Trust's internal control over financial reporting. The Trustee notes for purposes of clarification that it has no authority over, and makes no statement concerning, the internal control over financial reporting of the working interest owners.

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PART II—OTHER INFORMATION

Item 1.    Legal Proceedings.

        There are no pending legal proceedings to which the Trust is a named party. However, PNR has informed the Trust that PNR 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 PNR's gathering systems connected to PNR's Satanta gas plant). The case was relatively inactive for several years. In early 2000, the plaintiffs amended their pleadings to add claims. The lawsuit now has two material claims: (1) that the plaintiffs were improperly charged for a proportionate share of compression expenses incurred by PNR downstream of its wells and upstream of its Satanta gas plant; and (2) that the plaintiffs are entitled to 100% of the value of the helium extracted at PNR's Satanta gas plant. If the plaintiffs were to prevail on the above claims in their entirety, within what the court has ruled to be the applicable limitations period, PNR believes it is possible that PNR's liability could reach $32.5 million, plus prejudgment interest and attorneys' fees. The Trust's share of this amount would be approximately $1.6 million, plus prejudgment interest and attorneys' fees.

        PNR believes the compression expenses charged to the plaintiffs represent the plaintiffs' pro-rata share of post-production expenses incurred to add value to gas which was marketable at the well and, therefore, were expenses properly charged to plaintiffs under Kansas law. PNR has also vigorously defended against the plaintiffs' claims to 100% of the value of the helium extracted and believes that it has properly accounted to the plaintiffs for its helium production.

        The case was tried to the Court without a jury in December 2001. No judgment or findings have been entered. Arguments for judgment were presented in the second quarter of 2002. Judgment could be entered at any time. However, it is anticipated that the losing side, whichever that might be, would appeal. Entry of a final judgment adverse to PNR would reduce any amount available for distribution to the Trust for the period in which liability is recorded and during periods required for PNR to recoup any additional amounts.

Item 6.    Exhibits and Reports on Form 8-K

(a)

Exhibits

        (Asterisk indicates exhibit previously filed with the Securities and Exchange Commission and incorporated herein by reference. JPMorgan Chase Bank is successor by mergers to the original name of the Trustee Texas Commerce Bank National Association.)

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(b)

Reports on Form 8-K

        Current reports on Form 8-K were filed with the Securities and Exchange Commission on August 21, 2003, and September 22, 2003.

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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, thereunto duly authorized.

Date: November 13, 2003

        The Registrant, Mesa Royalty Trust, has no principal executive officer, principal financial officer, board of directors or persons performing similar functions. Accordingly, no additional signatures are available and none have been provided.

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