SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED MARCH 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: 1-7884
MESA ROYALTY TRUST
(Exact name of registrant as specified in its charter)
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Texas |
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74-6284806 |
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(State or other
jurisdiction of |
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(I.R.S. Employer Identification No.) |
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The Bank of New York Trust Company, |
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78701 |
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(Address of Principal Executive Offices) |
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(Zip Code) |
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1-800-852-1422 |
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(Registrant’s Telephone Number, Including Area Code) |
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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 o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act (Check one):
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Large accelerated filer o |
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Accelerated filer x |
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Non-accelerated filer o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No x
Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.
As of May 15, 2007—1,863,590 Units of Beneficial Interest were outstanding in Mesa Royalty Trust.
STATEMENTS OF DISTRIBUTABLE INCOME
|
|
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Three Months Ended |
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||||
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|
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2007 |
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2006 |
|
||
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Royalty income |
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$ |
2,563,081 |
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$ |
3,580,350 |
|
|
Interest income |
|
22,618 |
|
7,862 |
|
||
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General and administrative expense |
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(13,054 |
) |
(21,965 |
) |
||
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Distributable income |
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$ |
2,572,645 |
|
$ |
3,566,247 |
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Distributable income per unit |
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$ |
1.3805 |
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$ |
1.9136 |
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Units Outstanding |
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1,863,590 |
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1,863,590 |
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STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
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March 31, |
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December 31, |
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(Unaudited) |
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|
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ASSETS |
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Cash and short-term investments |
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$ |
2,550,027 |
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$ |
1,725,732 |
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Interest receivable |
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22,618 |
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6,551 |
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||
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Net overriding royalty interest in oil and gas properties |
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42,498,034 |
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42,498,034 |
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||
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Accumulated amortization |
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(34,489,269 |
) |
(34,395,319 |
) |
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Total assets |
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$ |
10,581,410 |
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$ |
9,834,998 |
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LIABILITIES AND TRUST CORPUS |
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|
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Distributions payable |
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$ |
2,572,645 |
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$ |
1,732,283 |
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Trust corpus (1,863,590 units of beneficial interest authorized, issued and outstanding) |
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8,008,765 |
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8,102,715 |
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||
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Total liabilities and trust corpus |
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$ |
10,581,410 |
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$ |
9,834,998 |
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(The accompanying notes are an integral part of these financial statements.)
2
STATEMENTS OF CHANGES IN TRUST CORPUS
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Three Months Ended |
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||||
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|
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2007 |
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2006 |
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||
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Trust corpus, beginning of period |
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$ |
8,102,715 |
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$ |
8,521,268 |
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Distributable income |
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2,572,645 |
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3,566,247 |
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||
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Distributions to unitholders |
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(2,572,645 |
) |
(3,566,247 |
) |
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Amortization of net overriding royalty interest |
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(93,950 |
) |
(105,728 |
) |
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Trust corpus, end of period |
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$ |
8,008,765 |
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$ |
8,415,540 |
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(The accompanying notes are an integral part of these financial statements.)
3
NOTES TO FINANCIAL
STATEMENTS
(Unaudited)
Note 1—Trust Organization and Provisions
The Mesa Royalty Trust (the “Trust”) was created on November 1, 1979. On that date, 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”), which was 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. ConocoPhillips sold most 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 BP Amoco Company (“BP”), a subsidiary of BP p.l.c. 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 and a few wells located in Southwest Colorado near the New Mexico border, are operated by ConocoPhillips. The San Juan Basin Royalty Properties located in Colorado are operated by BP. 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 BP 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.
Effective October 2, 2006, the Bank of New York Trust Company, N.A. (the “Trustee”) succeeded JPMorgan Chase Bank, N.A. as Trustee of the Trust. JPMorgan Chase Bank, N.A. was the successor by mergers to the original name of the Trustee, Texas Commerce Bank National Association.
The terms of the Mesa Royalty Trust Indenture (the “Indenture”) provide, among other things, that:
(a) the Trust cannot engage in any business or investment activity or purchase any assets;
(b) the Royalty can be sold in part or in total for cash upon approval by the unitholders;
(c) the Trustee can establish cash reserves and borrow funds to pay liabilities of the Trust and can pledge assets of the Trust to secure payment of the borrowings;
(d) the Trustee will make cash distributions to the unitholders in January, April, July and October each year as discussed more fully in Note 2;
4
(e) the Trust will terminate upon the first to occur of the following events: (i) at such time as the Trust’s royalty income for two successive years is less than $250,000 per year or (ii) a vote by the unitholders in favor of termination. Upon termination of the Trust, the Trustee will sell for cash all the assets held in the Trust estate and make a final distribution to unitholders of any funds remaining after all Trust liabilities have been satisfied; and
(f) PNR, ConocoPhillips and BP (collectively the “Working Interest Owners”) will reimburse the Trust for 59.34%, 27.45% and 1.77%, respectively, for general and administrative expenses of the Trust.
The accompanying unaudited financial information has been prepared by the Bank of New York Trust Company, N.A., (“Trustee”) in accordance with the instructions to Form 10-Q. The preparation of the financial statements requires estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities at the date of the financial statements and the reported amounts of income and expenses during the reporting period. Actual results could differ from those estimates. 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 2006 Annual Report on Form 10-K.
In accordance with the instruments conveying the Royalty, the Working Interest Owners will calculate and pay the Trust each month an amount equal to 90% of the net proceeds for the proceeding month. The 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 to receive 90% of 11.44% of the net proceeds for the preceding month. Generally, net proceeds means the excess of 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 is computed on a unit-of-production basis and is charged directly to trust corpus since such amount does not affect distributable income; and
5
(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 distributable 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, these statements differ from the basis used for financial statements prepared in accordance with accounting principles generally accepted in the United States because under such 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.
There are no pending legal proceedings to which the Trust is a named party. PNR has advised the Trustee that the previously reached 2006 settlement in the lawsuit John Steven Alford and Robert Larrabee, individually and on behalf of a Plaintiff Class v. Pioneer Natural Resources USA, Inc., filed in the 26th Judicial District Court, Stevens County, Kansas, was approved in the first quarter of 2007 by the Judge and the case was finalized in April 2007. The plaintiffs in the above noted lawsuit were royalty owners in oil and gas properties located in the Hugoton field, which are owned by Pioneer USA, a subsidiary of Pioneer Natural Resources Company (“Pioneer”). The plaintiffs sued a predecessor company to Pioneer USA asserting various claims relating to alleged improper deductions in the calculation of royalties.
Under the terms of the agreement, Pioneer USA agreed to make cash payments to settle the plaintiffs’ claims with respect to production occurring on and before December 31, 2005. Pioneer USA also agreed to adjust the manner in which royalty payments to the class members will be calculated for production occurring on and after January 1, 2006.
Pioneer’s portion of the cash payment is approximately $32,700,000. Pioneer agreed to pay the cash portion in two installments. Pioneer has advised the Trustee that the portion of the cash payments net to the Trust’s interest was approximately $1,000,000 paid on September 30, 2006 and an expected payment of approximately $900,000 payable on September 30, 2007. Pioneer USA will initially pay the costs attributable to the Trust’s interest but will recover these costs through payments out of future gross proceeds on the Trust’s properties. The $1,000,000 attributable to the Trust paid on September 30, 2006, was deducted from royalty income in the fourth quarter of 2006 and the $900,000 anticipated to be paid on September 30, 2007, will be deducted from the Trust’s future royalty income. Accordingly, Royalty income to the Trust will be significantly reduced until all of these payments, together with any applicable interest as provided under the overriding royalty conveyance of the Trust’s properties, are recouped by Pioneer USA.
6
Pioneer has advised the Trust that under the terms of the settlement agreement, the amounts required to be paid will be reduced if potential participating class members elect not to participate in the settlement by “opting out” under procedures established by the court. The settlement agreement contains a refund mechanism to address the circumstance where potential participating parties opt out after one of the funding installments is made. Pioneer cannot predict whether opt-outs will occur, or in what magnitude, but in the event that opt-outs occur triggering a refund, Pioneer will advise us of the refund amount attributable to the Trust.
Note 4—Federal Income Tax Matters
In a technical advice memorandum dated February 26, 1982, the IRS advised the Dallas District Director that the Trust is classifiable as a grantor trust and not as an association taxable as a corporation. As a grantor trust, the Trust will incur no federal income tax liability.
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 2006 Annual Report on 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.
The Trust is a passive entity whose purposes are limited to: (1) converting the Royalties to cash, either by retaining them and collecting the proceeds of production (until production has ceased or the Royalties are otherwise terminated) or by selling or otherwise disposing of the Royalties; and (2) distributing such cash, net of amounts for payments of liabilities to the Trust, to the unitholders. The Trust has no sources of liquidity or capital resources other than the revenues, if any, attributable to the Royalties and interest on cash held by the Trustee as a reserve for liabilities or for distribution.
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 be 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 section “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.
7
SUMMARY OF ROYALTY
INCOME, PRODUCTION AND AVERAGE PRICES
(Unaudited)
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 summary illustrates the net effect of the components of the actual Royalty computation for the periods indicated.
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Three Months Ended March 31, |
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2007 |
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2006 |
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Natural |
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Oil, |
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Natural |
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Oil, |
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The Trust’s proportionate share of Gross Proceeds(1) |
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$ |
2,611,969 |
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$ |
921,856 |
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$ |
4,453,111 |
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$ |
906,188 |
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|
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Less the Trust’s proportionate share of: |
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|
|
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|
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|
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||||
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Capital costs recovered(2) |
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(239,441 |
) |
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— |
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(306,899 |
) |
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— |
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|
||||
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Operating costs |
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(719,066 |
) |
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(12,237 |
) |
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(1,102,862 |
) |
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(76,828 |
) |
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||||
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Withheld Revenue(3) |
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— |
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— |
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(292,360 |
) |
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— |
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||||
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Royalty income |
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$ |
1,653,462 |
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|
$ |
909,619 |
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$ |
2,750,990 |
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$ |
829,360 |
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Average sales price |
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$ |
5.67 |
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$ |
35.18 |
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$ |
9.80 |
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$ |
42.23 |
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|
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Net production volumes attributable to the Royalty paid(4) |
|
291,616 |
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|
25,856 |
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|
280,713 |
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|
19,639 |
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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.
(3) The Colorado portion of the San Juan Basin Royalty properties recouped all costs related to the Fruitland Coal drilling program as of December 2004. However, subsequent cumulative earnings were not remitted to the Trust until December 2006. The cumulative earnings reported to the Trust by the working interest owner from January 2005 through October 2006 totaled approximately $1,280,000. In December, BP remitted approximately $978,000 for payment of undistributed earnings from January 2005 through October 2006 and November 2006 earnings. Since Royalty income for the Trust is recorded on a cash basis, Royalty income for the quarter ended March 31, 2006 of $292,360, was not recognized until the quarter ended December 31, 2006.
(4) Net production volumes attributable to the Royalty are determined by dividing Royalty income by the average sales price received.
8
Three Months Ended March 31, 2007 and 2006
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Three Months Ended |
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2007 |
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2006 |
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Royalty income |
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$ |
2,563,081 |
|
$ |
3,580,350 |
|
|
Interest income |
|
22,618 |
|
7,862 |
|
||
|
General and administrative expense |
|
(13,054 |
) |
(21,965 |
) |
||
|
Distributable income |
|
$ |
2,572,645 |
|
$ |
3,566,247 |
|
|
Distributable income per unit |
|
$ |
1.3805 |
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$ |
1.9136 |
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|
Units outstanding |
|
1,863,590 |
|
1,863,590 |
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||
The Trust’s Royalty income was $2,563,081 in the first quarter of 2007, a decrease of approximately 28% as compared to $3,580,350 in the first quarter of 2006, primarily as a result of lower natural gas and natural gas liquid prices in the first quarter of 2007 as compared to the first quarter of 2006, offset slightly by increased production.
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 March 31, 2007 was $2,572,645, representing $1.3805 per unit, compared to $3,566,247, representing $1.9136 per unit, for the quarter ended March 31, 2006. Based on 1,863,590 units outstanding for the quarters ended March 31, 2007 and 2006, respectively, the per unit distributions were as follows:
|
|
|
2007 |
|
2006 |
|
||
|
January |
|
$ |
.3616 |
|
$ |
.7297 |
|
|
February |
|
.5127 |
|
.5738 |
|
||
|
March |
|
.5062 |
|
.6101 |
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||
|
|
|
$ |
1.3805 |
|
$ |
1.9136 |
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Hugoton Field
Natural gas and natural gas liquids from the Hugoton field and attributable to the Royalty accounted for approximately 46% of the Royalty income of the Trust during the first quarter of 2007.
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 recently including Greely Gas and Oneok Gas Marketing, 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. As discussed below, overall market prices received for natural gas from the Hugoton Royalty Properties were significantly lower in the first quarter of 2007 compared to the first quarter of 2006.
9
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 being effective June 1, 2001. PNR has extended the contract to June 1, 2007. 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 was assigned to Kansas Gas Service (“Oneok”).
Royalty income attributable to the Hugoton Royalty decreased to $1,185,761 in the first quarter of 2007, from $2,025,057 in the first quarter of 2006 primarily due to decreases in natural gas prices from the Hugoton Royalty Properties. The average price received in the first quarter of 2007 for natural gas and natural gas liquids sold from the Hugoton Royalty Properties was $5.91 per Mcf and $37.64 per barrel, respectively, as compared to $10.74 per Mcf and $44.32 per barrel, respectively, in the first quarter of 2006. Net production of natural gas attributable to the Hugoton Royalty decreased to 134,714 Mcf in the first quarter of 2007 from 148,109 Mcf in the first quarter of 2006. Net production of natural gas liquids attributable to the Hugoton Royalty increased from 9,771 barrels in the first quarter of 2006 to 10,351 barrels in the first quarter of 2007. Actual production volumes from the Hugoton properties increased to 191,211 Mcf of natural gas and 10,350 barrels of natural gas liquids in the first quarter of 2007 as compared to 189,720 Mcf of natural gas and 9,773 barrels of natural gas liquids for the same period in 2006.
The Hugoton capital expenditures were $8,986 in the first quarter of 2007, a decrease of approximately 91% as compared to $96,285 in the first quarter of 2006. Changes in capital activity are attributed to varying needs of capital spending at individual wells. Jarvis and Panoma wells accounted for approximately $89,000 of the first quarter 2007 decrease, as capital spending needs decreased between the first quarter of 2006, and the first quarter of 2007. Operating costs were $325,710 in the first quarter of 2007, a decrease of approximately 7% as compared to $348,633 in the first quarter of 2006.
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 has set the Hugoton field allowable for the period April 1, 2007 through September 30, 2007, at 113.6 Bcf of gas, compared with 124.7 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. Substantially all of the royalty income from the San Juan Basin Royalty Properties are located in the state of New Mexico. The Royalty income was $1,155,948 during the first quarter of 2007 as compared with Royalty income of $1,555,293 in the first quarter of 2006. Net production attributable to the San Juan Basin Royalty located in New Mexico was 111,177 Mcf of natural gas and 15,505 barrels of natural gas liquids in the first quarter of 2007, as compared to 132,604 Mcf of natural gas and 9,868 barrels of natural gas liquids in the first quarter of 2006. The average price received in the first quarter of 2007 for natural gas and natural gas liquids sold from the San Juan Basin Royalty Properties was $5.72 per Mcf and $33.54 per barrel, respectively, compared to $8.74 per Mcf and $40.16 per barrel during the same period in 2006. Actual production volumes of natural gas attributable to the San Juan Basin properties decreased to 217,302 Mcf in the first quarter of 2007 as compared to 237,324 Mcf of natural gas for the same period in 2006. Actual production volumes of natural gas liquids attributable to the San Juan Basin properties
10
increased to 15,870 barrels in the first quarter of 2007 compared to 11,782 barrels for the same period in 2006.
Capital expenditures on these properties were $230,455 in the first quarter of 2007, an increase of approximately 9% as compared to $210,614 in the first quarter of 2006, primarily due to increased developmental drilling. Operating costs were $389,461 in the first quarter 2007, a decrease of approximately 50% as compared to $781,498 in the first quarter of 2006, attributed to a decrease in rod/tubing repairs, maintenance work, and normal lease operating expenses (labor, fuel, electricity, and chemicals) between periods.
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. Substantially all of the natural gas produced from the San Juan Basin is currently being sold on the spot market.
The costs related to the San Juan Basin, Colorado portion were recovered in December 2004. However, subsequent earnings were not remitted to the Trust until December 2006. The cumulative earnings, including interest on undistributed earnings, reported to the Trust by the working interest owner through November 2006, totaled $1,280,412. In December, BP remitted $978,349 for payment of undistributed earnings from January 2005 through October 2006 and November 2006 earnings. BP communicated to the Trust this distribution represents all of the previously unpaid revenues. The Trustee is currently investigating the $302,063 difference in the original estimate of unpaid proceeds of $1,280,412 and the payment of $978,349. Since Royalty income for the Trust is recorded on a cash basis, the first quarter 2006 earnings of $292,360 were not recognized as income until the quarter ended December 31, 2006.
Royalty income from the San Juan Basin — Colorado Royalty Properties was $221,372 during the first quarter of 2007, compared to none received during the first quarter of 2006. BP did not pay to the Trust amounts received during the first quarter of 2006. Net production attributable to the San Juan Basin Royalty Properties located in Colorado was 45,833 Mcf of natural gas during the first quarter of 2007 with no volumes attributable to the Trust during the first quarter of 2006. The average price received in the first quarter of 2007 for natural gas sold from the San Juan Basin Colorado Properties was $4.83. Actual production volumes attributable to the San Juan Basin Colorado Properties increased to 49,180 Mcf of natural gas in the first quarter of 2007 as compared to 47,926 Mcf of natural gas for the same period in 2006.
Operating costs on these properties were $16,132 in the first quarter of 2007, a decrease of approximately 67% as compared to $49,559 in the first quarter of 2006 attributed to a decrease in maintenance work, and normal lease operating expenses (labor, fuel, electricity, and chemicals).
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
The Trust does not utilize market risk 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. The Trustee maintains disclosure controls and procedures designed to ensure that information required to be disclosed by the Trust in the reports that it
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files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) 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 in the reports that it files or submits under the Exchange Act is accumulated and communicated by the working interest owners to The Bank of New York Trust Company, N.A., as Trustee of the Trust, 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.
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, the Trustee relies on information provided by the working interest owners, including (i) the status of litigation, (ii) historical operating data, plans for future operating and capital expenditures and reserve information, (iii) information relating to projected production, and (iv) conclusions regarding reserves by their internal reserve engineers or other experts in good faith. See Part I Item 1A. Risk Factors —“Trust unitholders and the Trustee have no control over the operation or development of the Royalty Properties and have little influence over operation or development” and “—The Trustee relies upon the Working Interest Owners for information regarding the Royalty Properties” in the Trust’s Form 10-K for the year ended December 31, 2006 for a description of certain risks relating to these arrangements and reliance.
Changes in Internal Control over Financial Reporting. In connection with the evaluation by the Trustee of changes in internal control over financial reporting of the Trust that occurred during the Trust’s last fiscal quarter, no change in the Trust’s internal control over financial reporting was identified 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, has not evaluated and makes no statement concerning the internal control over financial reporting of the working interest owners.
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There are no pending legal proceedings to which the Trust is a named party. PNR has advised the Trustee that the previously reached 2006 settlement in the lawsuit John Steven Alford and Robert Larrabee, individually and on behalf of a Plaintiff Class v. Pioneer Natural Resources USA, Inc., filed in the 26th Judicial District Court, Stevens County, Kansas, was approved in the first quarter of 2007 by the Judge and the case was finalized in April 2007. The plaintiffs in the above noted lawsuit were royalty owners in oil and gas properties located in the Hugoton field, which are owned by Pioneer USA, a subsidiary of Pioneer Natural Resources Company (“Pioneer”). The plaintiffs sued a predecessor company to Pioneer USA asserting various claims relating to alleged improper deductions in the calculation of royalties.
Under the terms of the agreement, Pioneer USA agreed to make cash payments to settle the plaintiffs’ claims with respect to production occurring on and before December 31, 2005. Pioneer USA also agreed to adjust the manner in which royalty payments to the class members will be calculated for production occurring on and after January 1, 2006.
As noted in prior disclosures, Pioneer’s portion of the cash payment is approximately $32,700,000. Pioneer agreed to pay the cash portion in two installments. Pioneer has advised the Trustee that the portion of the cash payments net to the Trust’s interest was approximately $1,000,000 paid on September 30, 2006 and an expected payment of approximately $900,000 payable on September 30, 2007. Pioneer USA will initially pay the costs attributable to the Trust’s interest but will recover these costs through payments out of future gross proceeds on the Trust’s properties. The $1,000,000 attributable to the Trust paid on September 30, 2006, was deducted from royalty income in 2006 and the $900,000 anticipated to be paid on September 30, 2007, will be deducted from the Trust’s future royalty income. Accordingly, royalty income to the Trust will be significantly reduced until all of these payments, together with any applicable interest as provided under the overriding royalty conveyance of the Trust’s properties, are recouped by Pioneer USA.
Pioneer has advised the Trust that under the terms of the settlement agreement, the amounts required to be paid will be reduced if potential participating class members elect not to participate in the settlement by “opting out” under procedures established by the court. The settlement agreement contains a refund mechanism to address the circumstance where potential participating parties opt out after one of the funding installments is made. Pioneer cannot predict whether opt-outs will occur, or in what magnitude, but in the event that opt-outs occur triggering a refund, Pioneer will advise us of the refund amount attributable to the Trust.
There have not been any material changes from risk factors previously disclosed in the Trust’s Form 10-K in response to Item 1A to Part 1 of its Form 10-K for the year ended December 31, 2006.
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(Asterisk indicates exhibit previously filed with the Securities and Exchange Commission and incorporated herein by reference. The Bank of New York Trust Company, N.A. is the successor trustee to JPMorgan Chase Bank, N.A. JPMorgan Chase Bank, N.A. was formerly known as The Chase Manhattan Bank and was successor by mergers to the original name of the Trustee, Texas Commerce Bank National Association).
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SEC File or |
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Exhibit |
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4(a)* |
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Mesa Royalty Trust Indenture between Mesa Petroleum Co. and Texas Commerce Bank National Association, as Trustee, dated November 1, 1979 |
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2-65217 |
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1(a |
) |
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4(b)* |
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Overriding Royalty Conveyance between Mesa Petroleum Co. and Texas Commerce Bank, as Trustee, dated November 1, 1979 |
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2-65217 |
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1(b |
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4(c)* |
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First Amendment to the Mesa Royalty Trust Indenture dated as of March 14, 1985 (Exhibit 4(c) to Form 10-K for year ended December 31, 1984 of Mesa Royalty Trust) |
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1-7884 |
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4(c |
) |
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4(d)* |
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Form of Assignment of Overriding Royalty Interest, effective April 1, 1985, from Texas Commerce Bank National Association, as Trustee, to MTR Holding Co. (Exhibit 4(d) to Form 10-K for year ended December 31, 1984 of Mesa Royalty Trust) |
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1-7884 |
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4(d |
) |
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4(e)* |
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Purchase and Sale Agreement, dated March 25, 1991, by and among Mesa Limited Partnership, Mesa Operating Limited Partnership and Conoco, as amended on April 30, 1991 (Exhibit 4(e) to Form 10-K for year ended December 31, 1991 of Mesa Royalty Trust) |
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1-7884 |
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4(e |
) |
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31 |
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Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
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32 |
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Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
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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.
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Mesa Royalty Trust |
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By: |
The Bank of New York
Trust Company, N.A., |
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By: |
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Mike Ulrich |
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Vice President |
Date: May 15, 2007
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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