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 SEPTEMBER 30, 2004
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 of Incorporation
or Organization) | 76-6004065
(I.R.S. Employer
Identification No.) |
JPMorgan Chase Bank, Trustee
Institutional Trust Services
700 Lavaca
Austin, Texas
(Address of Principal Executive Offices) | 78701
(Zip Code) |
1-800-852-1422 / 1-512-479-2562
(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 o
Indicate by a check mark whether the registrant is an accelerated filer (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 November 14, 2004— 71,980,216 Units of Beneficial Interest in Mesa Offshore Trust.
PART I—FINANCIAL INFORMATION
Item 1. Financial Statements.
MESA OFFSHORE TRUST
STATEMENTS OF DISTRIBUTABLE INCOME
(Unaudited)
| | Three Months Ended
September 30, | | Nine Months Ended
September 30, | |
| | 2004 | | 2003 | | 2004 | | 2003 | |
Royalty income | | $ | — | | $ | — | | $ | — | | $ | — | |
Interest income | | 1,039 | | 1,741 | | 3,663 | | 7,566 | |
General and administrative expense | | (1,039 | ) | (1,741 | ) | (3,663 | ) | (7,566 | ) |
Distributable income | | $ | — | | $ | — | | $ | — | | $ | — | |
Distributable income per unit | | $ | — | | $ | — | | $ | — | | $ | — | |
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
| | September 30,
2004 | | December 31,
2003 | |
| | (Unaudited) | | �� | |
ASSETS | | | | | |
Cash and short-term investments | | $ | 478,670 | | $ | 938,827 | |
Interest receivable | | 330 | | 1,603 | |
Net overriding royalty interest in oil and gas properties | | 380,905,000 | | 380,905,000 | |
Accumulated amortization | | (380,893,873 | ) | (380,893,873 | ) |
Total assets | | $ | 490,127 | | $ | 951,557 | |
LIABILITIES AND TRUST CORPUS | | | | | |
Reserve for Trust expenses | | $ | 479,000 | | $ | 940,430 | |
Distributions payable | | — | | — | |
Trust corpus (71,980,216 units of beneficial interest authorized and outstanding) | | 11,127 | | 11,127 | |
Total liabilities and trust corpus | | $ | 490,127 | | $ | 951,557 | |
(The accompanying notes are an integral part of these financial statements.)
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MESA OFFSHORE TRUST
STATEMENTS OF CHANGES IN TRUST CORPUS
(Unaudited)
| | Three Months Ended
September 30, | | Nine Months Ended
September 30, | |
| | 2004 | | 2003 | | 2004 | | 2003 | |
Trust corpus, beginning of period | | $ | 11,127 | | $ | 11,127 | | $ | 11,127 | | $ | 11,127 | |
Distributable income | | — | | — | | — | | — | |
Distributions to unitholders | | — | | — | | — | | — | |
Amortization of net overriding royalty interest | | — | | — | | — | | — | |
Trust corpus, end of period | | $ | 11,127 | | $ | 11,127 | | $ | 11,127 | | $ | 11,127 | |
(The accompanying notes are an integral part of these financial statements.)
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MESA OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS
(Unaudited)
Note 1—Trust Organization
The Mesa Offshore Trust (the “Trust”) was created effective December 1, 1982. On that date, Mesa Petroleum Co., predecessor to Mesa Limited Partnership, which was the predecessor to MESA Inc., transferred to the Trust a 99.99% interest in the Mesa Offshore Royalty Partnership (the “Partnership”). The Partnership was created to receive and hold a net overriding royalty interest (the “Royalty”) in ten producing and nonproducing oil and gas properties located in federal waters offshore Louisiana and Texas (the “Royalty Properties”). MESA Inc. created the Royalty out of its working interest in the Royalty Properties and transferred it to the Partnership. 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 (“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) a wholly owned subsidiary of Pioneer (“PNR”) (collectively, the mergers are referred to herein as the “Merger”). Subsequent to the Merger, Pioneer owns and operates its assets through PNR and is also the managing general partner of the Partnership. As used in this report, the term PNR generally refers to the operator of the Royalty Properties, unless otherwise indicated.
Status of the Trust
The Trust Indenture provides that the Trust will terminate if the total amount of cash per year received by the Trust falls below certain levels for each of three successive years (the “Termination Threshold”).
As a result of the Trust properties nearing the end of their estimated productive lives, Royalty income received by the Trust in 2002 and 2003 fell below the Termination Threshold prescribed by the Trust Indenture. In addition, there is an accumulated deficit due PNR as of September 30, 2004 of $331,267 that will be deducted from any future gross proceeds on the Royalty Properties, which deduction will reduce future Royalty income.
The December 31, 2003 reserve report prepared for the Partnership indicates that Royalty income expected to be received by the Trust in 2004 will be below the Termination Threshold. The Termination Threshold for 2003 was approximately $1.2 million. The reserve report estimates that future Royalty income to the Trust will be zero for 2004 as estimated net proceeds from the Trust properties during 2004 will not be sufficient to recoup the accumulated deficit existing at December 31, 2003. In addition, the reserve report estimates that future Royalty income to the Trust after 2004 will be approximately $2.2 million (net of the recoupment of the Trust deficit). Future Royalty income in the reserve report was calculated using oil and natural gas spot prices in effect at December 31, 2003 of $31.42 per barrel and $5.97 per Mcf, respectively. Based on the current estimates of future Royalty income and 2004 operational updates received from PNR, the Trustee continues to expect that Royalty income received by the Trust will fall below the Termination Threshold in 2004. Accordingly, the Trustee anticipates that effective after December 31, 2004, the Trust Indenture will require the Trustee to sell the Trust’s interest in the Partnership, or cause the Partnership to sell the assets of the Partnership, and thereby terminate the Trust.
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Assuming the Termination Threshold is not met as of December 31, 2004, the Trust Indenture provides the Trustee a two-year period during which it must sell all of the Trust properties. The Trust Indenture provides that such properties must be sold for cash and not for any other consideration. The Trustee may sell the properties at public auction to the highest cash bidder, but it may also conduct any other sale process that it deems in the best interest of the Unitholders. The Trustee currently intends to commence a sale process promptly in early 2005 assuming commodity and financial market conditions remain favorable for the timing of a sale. The Trustee has engaged an independent party to commence a joint venture audit and has made requests for other relevant information in anticipation of this sale process and the termination of the Trust.
PNR advised the Trust that it farmed out the Trust’s interest in Brazos A-7 and A-39 so that two exploratory prospects could be drilled during 2003 with the Trust retaining an overriding royalty interest. The first exploration prospect was drilled on Brazos A-7 during 2003 and was determined to be a dry hole. As such, the well was plugged and abandoned. The second exploration prospect was drilled on Brazos A-39 and has been announced as a discovery. PNR has approved a plan to set minimal facilities, complete the well and perform a production test prior to determining whether or not to develop the project as a subsea tie-back into an existing platform. Equipment has been ordered and the production test should take place in late 2004. If the discovery is deemed to be commercially viable, first sales will not take place until 2005, which may occur after the termination of the Trust. In addition, PNR advised the Trust that Stone Energy Corporation (“Stone”) recently completed an exploratory well on West Delta 61 that was placed on production early in the third quarter of 2004. Even with this well coming on-line in 2004, it is currently expected that any Royalty income generated from this prospect will not be received in time to eliminate the deficit balance and increase Royalty income above the Termination Threshold.
There are numerous uncertainties inherent in estimating and projecting the quantity and value of proved reserves for the Trust properties, as many of the Trust properties are nearing the end of their productive lives and are therefore subject to unforeseen changes in production rates. As such, the foregoing statements reflect only current reasonable expectations.
The terms of the First Amended and Restated Articles of General Partnership of the Partnership provide that the Partnership shall dissolve upon the occurrence of any of the following: (a) December 31, 2030; (b) the election of the Trustee to dissolve the Partnership; (c) the termination of the Trust; (d) the bankruptcy of the Managing General Partner; or (e) 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. In the event of a dissolution of the Partnership and a subsequent winding up and termination thereof, the assets of the Partnership (i.e., the Royalty interest) could either (i) be distributed in kind ratably to the Managing General Partner and the Trustee or (ii) be sold and the proceeds thereof distributed ratably to the Managing General Partner and the Trustee. In the event of a sale of the Royalty and a distribution of the cash proceeds to the Trustee, the Trustee would make a final distribution to unitholders of such cash proceeds plus any other cash held by the Trust after the payment of or provision for all liabilities of the Trust, and the Trust would be terminated.
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
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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 2003 Annual Report on Form 10-K.
The financial statements of the Trust are prepared on the following basis:
(a) Royalty income recorded for a month is the Trust’s interest in the amount computed and paid by the working interest owner to the Partnership for such month rather than either the value of a portion of the oil and gas produced by the working interest owner for such month or the amount subsequently determined to be 90% 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 interest, which is calculated on the basis of current royalty income in relation to estimated future royalty income, 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 considered 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 of America 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.
The instruments conveying the Royalty provide that the working interest owner will calculate and pay the Partnership each month an amount equal to 90% of the net proceeds for the preceding month.
Generally, net proceeds means the excess of the amounts received by the working interest owner from sales of oil and gas from the Royalty Properties plus other cash receipts over operating and capital costs incurred. For the three and nine months ending September 30, 2004, proceeds from oil and gas sales exceeded operating and capital costs incurred; however, no Royalty income was reported as the net proceeds were used to reduce the accumulated deficit. For the three months ended September 30, 2004, the deficit was reduced by $102,641. There remains an accumulated deficit balance due PNR as of September 30, 2004 of $331,267 that will be deducted from any future gross proceeds on the Royalty Properties, which deduction will reduce future Royalty income. In addition, no Royalty income will be distributed to unitholders until the Trustee recoups Trust expenses being paid from the reserve that the
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Trustee has established for anticipated future expenses. As of September 30, 2004, the Reserve for Trust expenses is $479,000. As of September 30, 2004 the Trustee would expect to withhold up to $1,521,000 from future Royalty income before Trust distributions will resume.
Since the inception of the Trust, PNR has withheld from royalty income amounts for the future abandonment of the Royalty properties. The unexpended amount withheld by PNR for future abandonment costs at September 30, 2004 was $2,679,372. Under the terms of the Royalty conveyance, the amounts withheld by PNR for future abandonment costs are not escrowed and do not accrue interest for the benefit of the Trust.
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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.
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” and Note 1 to the financial statements of the Trust regarding the future net revenues of the Trust, are forward-looking statements. Although Pioneer 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-Q, and in the Trust’s Form 10-K for the year ended December 31, 2003, 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.
Financial Review
The amount of cash distributed by the Trust is dependent on, among other things, the sales prices and quantities of gas, crude oil, condensate and natural gas liquids produced from the Royalty Properties and the quantities sold. Substantial uncertainties exist with regard to future gas and oil prices, which are subject to fluctuations due to the regional supply and demand for natural gas and oil, production levels and other activities of the Organization of the Petroleum Exporting Countries (“OPEC”) and other oil and gas producers, weather, storage levels, industrial growth, conservation measures, competition and other variables.
Below is a summary of Royalty income received on the Trust properties for the three and nine months ended September 30, 2004 and 2003:
| | Three Months Ended
September 30, | | Nine Months Ended
September 30, | |
| | 2004 | | 2003 | | 2004 | | 2003 | |
Gross proceeds @ 90% | | $ | 129,251 | | $ | 289,855 | | $ | 513,492 | | $ | 719,983 | |
Operating expenditures @ 90% | | (26,599 | ) | (289,855 | ) | (148,010 | ) | (719,983 | ) |
Capital expenditures @ 90% | | — | | — | ) | — | | — | |
Net proceeds (deficit) | | 102,652 | | — | | 365,482 | | — | |
Increase (decrease) in deficit due PNR | | (102,641 | ) | (— | ) | (365,445 | ) | (— | ) |
Net proceeds after deficit recovery | | — | | — | | — | | — | |
Royalty Income (99.99%) | | $ | — | | $ | — | | $ | — | | $ | — | |
Accumulated deficit due PNR (as of end of period) | | $ | (331,267 | ) | $ | (615,553 | ) | $ | (331,267 | ) | $ | (615,553 | ) |
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Below is a summary of distributable income for the three and nine months ended September 30, 2004 and 2003:
| | Three Months Ended
September 30, | | Nine Months Ended
September 30, | |
| | 2004 | | 2003 | | 2004 | | 2003 | |
Royalty income | | $ | — | | $ | — | | $ | — | | $ | — | |
Interest income | | 1,039 | | 1,741 | | 3,663 | | 7,566 | |
General and administrative expenses | | (1,039 | ) | (1,741 | ) | (3,663 | ) | (7,566 | ) |
Distributable income | | $ | — | | $ | — | | $ | — | | $ | — | |
Distributable income per unit | | $ | — | | $ | — | | $ | — | | $ | — | |
Recoupment of reserve for Trust expenses | | $ | 102,641 | | $ | — | | $ | 365,445 | | $ | — | |
The Trust had no distributable income for the three and nine months ended September 30, 2004 and 2003. Since December 2001, the Trust has been in a deficit position to PNR as a result of significant decline in production on properties in which the Trust has a Royalty interest. The Trust continues to be in a deficit position as a result of lower production on all properties due to these properties nearing the end of their productive lives. See “—Operational Review” below.
Operational Review
PNR has advised the Trust that during the third quarter of 2004 its offshore gas production was marketed under short-term contracts at spot market prices primarily to Total S.A. and that it expects to continue to market its production under short-term contracts for the foreseeable future. Spot market prices for natural gas in the third quarter of 2004 were generally higher than spot market prices in the third quarter of 2003.
The amount of cash distributed by the Trust is dependent on, among other things, the sales prices and quantities of gas, crude oil and condensate produced from the Royalty Properties and the quantities sold. Substantial uncertainties exist with regard to future gas and oil prices, which are subject to fluctuations due to the regional supply and demand for natural gas and oil, production levels and other activities of the Organization of the Petroleum Exporting Countries (“OPEC”) and other oil and gas producers, weather, storage levels, industrial growth, conservation measures, competition and other variables.
Below is an operational review of the remaining producing Trust properties:
Brazos A-7 and A-39
| | Three Months Ended
September 30, | | Nine Months Ended
September 30, | |
| | 2004 | | 2003 | | 2004 | | 2003 | |
Gross proceeds @ 90% | | $ | 32,713 | | $ | 75,128 | | $ | 132,165 | | $ | 281,730 | |
Operating expenditures @ 90% | | (23,970 | ) | (75,128 | ) | (146,014 | ) | (281,730 | ) |
Capital expenditures @ 90% | | — | | — | | | | — | |
Net proceeds (deficit) | | $ | 8,743 | | $ | — | | $ | (13,849 | ) | $ | — | |
Producing wells | | 1 | | 2 | | 1 | | 2 | |
The Brazos A-7 and A-39 blocks continued to experience a decrease in natural gas production due to natural production decline. As of September 30, 2004, these two blocks had one well producing, the Brazos A-7 No. B-1 well. The Brazos A-39 No. A-3 well ceased production during the fourth quarter of 2003. PNR
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farmed out the Trust’s interest in both of these blocks so that two exploration prospects could be drilled with the Trust retaining an overriding royalty interest. The first prospect on Brazos A-7 was drilled during 2003 and was determined to be a dry hole. As such, the well was plugged and abandoned. The second exploration prospect was drilled on Brazos A-39 and has been announced as a discovery. PNR has approved a plan to set minimal facilities, complete the well and perform a production test prior to determining whether or not to develop the project as a subsea tie-back into an existing platform. Equipment has been ordered and the production test should take place in late 2004. If the discovery is deemed to be commercially viable, first sales will not take place until 2005, which may occur after the termination of the Trust. The plugging and abandonment of the PNR operated wells in the Brazos A-7 and Brazos A-39 blocks, with the exception of the recently drilled exploration well on the Brazos A-39 prospect, will begin in the fourth quarter of 2004 and the PNR operated Brazos A-7 and Brazos A-39 platforms will be removed in 2005.
West Delta 61 and 62
| | Three Months Ended
September 30, | | Nine Months Ended
September 30, | |
| | 2004 | | 2003 | | 2004 | | 2003 | |
Gross proceeds @ 90% | | $ | 96,538 | | $ | 214,727 | | $ | 381,327 | | $ | 438,253 | |
Operating expenditures @ 90% | | (2,629 | ) | (214,727 | ) | (1,996 | ) | (438,253 | ) |
Capital expenditures @ 90% | | — | | — | | — | | — | |
Net proceeds (deficit) | | $ | 93,909 | | $ | — | | $ | 379,331 | | $ | | |
Producing wells | | 4 | | 3 | | 4 | | 3 | |
The West Delta 61 and 62 blocks experienced a decrease in oil and natural gas production in the third quarter of 2004 as compared to the same period in 2003 due to natural production decline. The producing wells are operated by Stone. The PNR-operated wells ceased production in 2002, and the wells were plugged and abandoned at the end of 2002 with the facilities being completely abandoned during 2003. The only remaining wells on this block are in West Delta 61. PNR farmed out a portion of West Delta 61 to Stone retaining a 12.5% (11.25% net to the Trust) overriding royalty interest. Stone recently completed drilling an exploratory well that was placed on production early in the third quarter of 2004. Even with this well coming on-line in 2004, it is currently expected that any Royalty income generated from this prospect will not be received in time to eliminate the deficit balance and increase Royalty income above the Termination Threshold.
Capital Expenditures
PNR does not anticipate making any significant capital expenditures on the Royalty Properties in the future. Due to the limited financial capacity of the Trust, PNR has advised that it intends to farm out the Trust’s interest in the blocks that PNR believes may be produced economically, retaining an overriding royalty interest for the Trust.
Abandonment Expenditures
The table below provides a rollforward of the abandonment and removal costs that PNR has withheld from the Trust. Under the terms of the Royalty conveyance, these amounts withheld are not escrowed and do not accrue interest for the benefit of the Trust.
Balance, December 31, 2003 | | $ | 2,800,643 | |
Abandonment cost incurred (WD 61 and 62) | | (121,271 | ) |
Balance, September 30, 2004 | | $ | 2,679,372 | |
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The following tables provide a summary of the calculations of the net proceeds attributable to the Partnership’s royalty interest (unaudited):
| | Brazos A-7
and A-39 | | West Delta
61 and 62 | | Total | |
Three Months Ended September 30, 2004: | | | | | | | |
Ninety percent of gross proceeds | | $ | 32,713 | | $ | 96,538 | | $ | 129,251 | |
Less ninety percent of— | | | | | | | |
Operating expenditures | | (23,970 | ) | (2,629 | ) | (26,599 | ) |
Capital costs recovered | | — | | — | | — | |
Net proceeds | | $ | 8,743 | | $ | 93,909 | | $ | 102,652 | |
Trust share of net proceeds (99.99%) | | | | | | $ | 102,641 | |
Recoupment of deficit | | | | | | (102,641 | ) |
Royalty income | | | | | | — | |
Trust Deficit | | | | | | $ | 331,267 | |
Production Volumes and Average Prices: | | | | | | | |
Crude oil, condensate and natural gas liquids (Bbls) | | 6 | | 1,565 | | 1,571 | |
Average sales price per Bbl | | $ | 37.33 | | $ | 35.83 | | $ | 35.84 | |
Natural gas (Mcf) | | 5,280 | | 7,552 | | 12,832 | |
Average sales price per Mcf | | $ | 6.16 | | $ | 5.35 | | $ | 5.68 | |
Producing wells | | 1 | | 4 | | 5 | |
Three Months Ended September 30, 2003: | | | | | | | |
Ninety percent of gross proceeds | | $ | 75,128 | | $ | 214,727 | | $ | 289,855 | |
Less ninety percent of— | | | | | | | |
Operating expenditures | | (75,128 | ) | (214,727 | ) | (289,855 | ) |
Capital costs recovered | | — | | — | | — | |
Net proceeds (deficit) | | $ | — | | $ | — | | $ | — | |
Trust share of net proceeds (99.99%) | | | | | | $ | | |
Increase in deficit | | | | | | — | |
Royalty income | | | | | | — | |
Trust Deficit | | | | | | (615,553 | ) |
Production Volumes and Average Prices: | | | | | | | |
Crude oil, condensate and natural gas liquids (Bbls) | | 183 | | 2,526 | | 2,709 | |
Average sales price per Bbl | | $ | 27.69 | | $ | 28.99 | | $ | 28.90 | |
Natural gas (Mcf) | | 13,773 | | 20,102 | | 33,875 | |
Average sales price per Mcf | | $ | 5.09 | | $ | 7.04 | | $ | 6.25 | |
Producing wells | | 2 | | 3 | | 5 | |
The amounts shown are for Mesa Offshore Royalty Partnership. Producing wells indicate the number of wells capable of production as of the end of the period. The amounts for the three months ended September 30, 2004 and 2003 represent actual production for the periods May 2004 through July 2004 and May 2003 through July 2003, respectively. Capital costs recovered represent capital costs incurred during the current or prior periods to the extent that such costs have been recovered by PNR from current period Gross Proceeds. The unexpended amount withheld by PNR for future abandonment costs at
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September 30, 2004 was $2,679,372. The Trust deficit balance due PNR of $331,267 as of September 30, 2004 will be deducted from any future gross proceeds on the Royalty properties, which deduction will reduce future Royalty income. As of September 30, 2004, the Trustee would expect to withhold up to $1,521,000 from Royalty income before Trust distributions will resume.
| | Brazos A-7
and A-39 | | West Delta
61 and 62 | | Total | |
Nine Months Ended September 30, 2004: | | | | | | | |
Ninety percent of gross proceeds | | $ | 132,165 | | $ | 381,327 | | $ | 513,492 | |
Less ninety percent of— | | | | | | | |
Operating expenditures | | (146,014 | ) | (1,996 | ) | (148,010 | ) |
Capital costs recovered | | — | | — | | — | |
Net proceeds (deficit) | | $ | (13,849 | ) | $ | 379,331 | | $ | 365,482 | |
Trust share of net proceeds (99.99%) | | | | | | $ | 365,445 | |
Recoupment of deficit | | | | | | (365,445 | ) |
Royalty income | | | | | | — | |
Trust Deficit | | | | | | $ | 331,267 | |
Production Volumes and Average Prices: | | | | | | | |
Crude oil, condensate and natural gas liquids (Bbls) | | 24 | | 7,514 | | 7,538 | |
Average sales price per Bbl | | $ | 35.30 | | $ | 31.05 | | $ | 31.07 | |
Natural gas (Mcf) | | 24,067 | | 29,163 | | 53,230 | |
Average sales price per Mcf | | $ | 5.46 | | $ | 5.07 | | $ | 5.25 | |
Producing wells | | 1 | | 4 | | 5 | |
Nine Months Ended September 30, 2003: | | | | | | | |
Ninety percent of gross proceeds | | $ | 281,730 | | $ | 438,253 | | $ | 719,983 | |
Less ninety percent of— | | | | | | | |
Operating expenditures | | (281,730 | ) | (438,253 | ) | (719,983 | ) |
Capital costs recovered | | — | | — | | — | |
Net proceeds (deficit) | | $ | — | | $ | — | | $ | — | |
Trust share of net proceeds (99.99%) | | | | | | $ | — | |
Increase in deficit | | | | | | — | |
Royalty income | | | | | | — | |
Trust Deficit | | | | | | $ | (615,553 | ) |
Production Volumes and Average Prices: | | | | | | | |
Crude oil, condensate and natural gas liquids (Bbls) | | 306 | | 5,186 | | 5,492 | |
Average sales price per Bbl | | $ | 27.37 | | $ | 26.87 | | $ | 26.90 | |
Natural gas (Mcf) | | 66,857 | | 48,823 | | 110,680 | |
Average sales price per Mcf | | $ | 4.09 | | $ | 6.82 | | $ | 5.17 | |
Producing wells | | 2 | | 3 | | 5 | |
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The amounts shown are for Mesa Offshore Royalty Partnership. Producing wells indicate the number of wells capable of production as of the end of the period. The amounts for the nine months ended September 30, 2004 and 2003 represent actual production for the periods November 2003 through July 2004 and November 2002 through July 2003, respectively. Capital costs recovered represent capital costs incurred during the current or prior periods to the extent that such costs have been recovered by PNR from current period Gross Proceeds. The unexpended amount withheld by PNR for future abandonment costs at September 30, 2004 was $2,679,372. The Trust deficit balance due PNR of $331,267 as of September 30, 2004 will be deducted from any future gross proceeds on the Royalty properties, which deduction will reduce future Royalty income. As of September 30, 2004, the Trustee would expect to withhold up to $1,521,000 from Royalty income before trust distributions will resume.
Production and Price Review
Production volumes for natural gas decreased to 12,832 Mcf in the third quarter of 2004 as compared with 33,875 Mcf in the third quarter of 2003. The average sales price received for natural gas in the third quarter of 2004 was $5.68 per Mcf as compared with $6.25 per Mcf in the third quarter of 2003. Crude oil, condensate and natural gas liquids production volumes decreased to 1,571 barrels in the third quarter of 2004 as compared to 2,709 barrels in the third quarter of 2003. The average sales price in the third quarter of 2004 for crude oil, condensate and natural gas liquids was $35.84 per barrel as compared with $28.90 per barrel in the third quarter of 2003.
Production volumes for natural gas decreased to 53,230 Mcf for the nine months ended September 30, 2004 as compared with 110,680 Mcf for the nine months ended September 30, 2003. The average sales price received for natural gas for the nine months ended September 30, 2004 was $5.25 per Mcf as compared with $5.17 per Mcf for the nine months ended September 30, 2003. Crude oil, condensate and natural gas liquids production volumes increased to 7,538 barrels for the nine months ended September 30, 2004 as compared to 5,492 barrels for the nine months ended September 30, 2003. The average sales price for the nine months ended September 30, 2004 for crude oil, condensate and natural gas liquids was $31.07 per barrel as compared with $26.90 per barrel for the nine months ended September 30, 2003.
Termination of the Trust
The terms of the Mesa Offshore Trust Indenture provide, among other things, that the Trustee must sell of the Trust’s interest in the Partnership, or cause the Partnership to sell all of its assets, and thereby to terminate the Trust, after the first to occur of the following events: (1) the total amount of cash received per year 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 (2) a vote by holders of a majority of the outstanding units in favor of termination. Because the Trust will terminate in the event the total amount of cash received per year by the Trust falls below certain levels, it would be possible for the Trust to terminate even though some of the Royalty Properties continued to have remaining productive lives. For information regarding the estimated remaining life of each of the Royalty Properties and the estimated future net revenues of the Trust based on information provided by PNR, see the Trust’s 2003 Annual Report on Form 10-K and the description below. 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. The discussion set forth above is qualified in its entirety by reference to the Trust Indenture itself,
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which is an exhibit to the Trust’s 2003 Annual Report on Form 10-K and is available upon request from the Trustee.
The December 31, 2003 reserve report prepared for the Partnership indicates that Royalty income expected to be received by the Trust in 2004 will be below the Termination Threshold. The Termination Threshold for 2003 was approximately $1.2 million. The reserve report estimates that future Royalty income to the Trust will be zero for 2004 as estimated net proceeds from the Trust properties during 2004 will not be sufficient to recoup the accumulated deficit existing at December 31, 2003. In addition, the reserve report estimates that future royalty income to the Trust after 2004 will be approximately $2.2 million (net of the recoupment of the Trust deficit). Future Royalty income in the reserve report was calculated using oil and natural gas spot prices in effect at December 31, 2003 of $31.42 per barrel and $5.97 per Mcf, respectively. Based on the current estimates of future Royalty income and 2004 operational updates received from PNR, the Trustee continues to expect that Royalty income received by the Trust will fall below the Termination Threshold in 2004. Accordingly, the Trustee anticipates that effective after December 31, 2004, the Trust Indenture will require the Trustee to sell the Trust’s interest in the Partnership, or cause the Partnership to sell the assets of the Partnership, and thereby terminate the Trust.
Assuming the Termination Threshold is not met as of December 31, 2004, the Trust Indenture provides the Trustee a two-year period during which it must sell all of the Trust properties. The Trust Indenture provides that such properties must be sold for cash and not for any other consideration. The Trustee may sell the properties at public auction to the highest cash bidder, but it may also conduct any other sale process that it deems in the best interest of the Unitholders. The Trustee currently intends to commence a sale process promptly in early 2005 assuming commodity and financial market conditions remain favorable for the timing of a sale. The Trustee has engaged an independent party to commence a joint venture audit and has made requests for other relevant information in anticipation of this sale process and the termination of the Trust.
PNR advised the Trust that it farmed out the Trust’s interest in Brazos A-7 and A-39 so that two exploratory prospects could be drilled during 2003 with the Trust retaining an overriding royalty interest. The first exploration prospect was drilled on Brazos A-7 during 2003 and was determined to be a dry hole. As such, the well was plugged and abandoned. The second exploration prospect was drilled on Brazos A-39 which has been announced as a discovery. PNR has approved a plan to set minimal facilities, complete the well and perform a production test prior to determining whether or not to develop the project as a subsea tie-back into an existing platform. Equipment has been ordered and the production test should take place in late 2004. If the discovery is deemed to be commercially viable, first sales will not take place until early 2005, which may occur after the termination of the Trust. In addition, PNR advised the Trust that Stone recently completed an exploratory well on West Delta 61 that was placed on production early in the third quarter of 2004. Even with this well coming on-line, it is currently expected that any Royalty income generated from this prospect will not be received in time to eliminate the deficit balance and increase Royalty income above the Termination Threshold Amount.
The terms of the First Amended and Restated Articles of General Partnership of the Partnership provide that the Partnership shall dissolve upon the occurrence of any of the following: (a) December 31, 2030; (b) the election of the Trustee to dissolve the Partnership; (c) the termination of the Trust; (d) the bankruptcy of the Managing General Partner; or (e) the dissolution of the Managing General Partner or its election to dissolve the Partnership; provided that the Managing General Partner shall not elect to
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dissolve the Partnership so long as the Trustee remains the only other partner of the Partnership. In the event of a dissolution of the Partnership and a subsequent winding up and termination thereof, the assets of the Partnership (i.e., the Royalty interest) could either (i) be distributed in kind ratably to the Managing General Partner and the Trustee or (ii) be sold and the proceeds thereof distributed ratably to the Managing General Partner and the Trustee. In the event of a sale of the Royalty and a distribution of the cash proceeds to the Trustee, the Trustee would make a final distribution to unitholders of such cash proceeds plus any other cash held by the Trust after the payment of or provision for all liabilities of the Trust, and the Trust would be terminated.
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 PNR 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 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 procedures designed to ensure that information required to be disclosed by the Trust is accumulated and communicated by Pioneer, as the managing general partner of the Partnership, and the working interest owners to JPMorgan Chase Bank, 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 these 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, (ii) the Partnership Agreement and (iii) the rights of the Partnership under the Conveyance regarding information furnished by the working interest owners, there are certain weaknesses that are not subject to change or modification by the Trustee. The contractual limitations creating potential weaknesses in disclosure controls and procedures may be deemed to include:
· 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 report that contains projected production, operating expenses and capital expenses, and (iv) information relating to projected production. The Trustee 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.
· The Trustee relies on information provided by the managing general partner of the Partnership that is collected by the managing general partner from the working interest owners. While the Trustee
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may request information through the managing general partner, the Conveyance together with the Partnership Agreement gives only the managing general partner of the Partnership, as the Royalty Owner, the actual authority and discretion to request and receive financial information regarding the Royalty Properties from the working interest owners. While the Trustee requests material information for use in periodic reports as part of its disclosure controls and procedures, the Trustee generally does not have any direct contact with working interest owners, other than employees of the managing general partner, and relies on the managing general partner of the Partnership to request and obtain information deemed material to the Trust by the Trustee.
· Under the terms of the Trust Agreement, the Trustee is entitled to rely on certain experts in good faith. While the Trustee has no reason to believe its reliance upon experts is unreasonable, its 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 Control Over Financial Reporting. There has been no change in the Trustee’s internal control over financial reporting during the three months ended September 30, 2004 that has materially affected, or is reasonably likely to materially affect, the Trustee’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 or the managing general partner of the Partnership.
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PART II—OTHER INFORMATION
Item 6. Exhibits
(Asterisk indicates exhibit previously filed with the Securities and Exchange Commission and incorporated herein by reference. 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.)
| | | | | SEC File or
Registration
Number | | Exhibit
Number | |
4 | (a) | * | Mesa Offshore Trust Indenture between Mesa Petroleum Co. and Texas Commerce Bank National Association, as Trustee, dated December 15, 1982 | | 2-79673 | | 10(gg) | |
4 | (b) | * | Overriding Royalty Conveyance between Mesa Petroleum Co. and Mesa Offshore Royalty Partnership, dated December 15, 1982 | | 2-79673 | | 10(hh) | |
4 | (c) | * | Partnership Agreement between Mesa Offshore Management Co. and Texas Commerce Bank National Association, as Trustee, dated December 15, 1982 | | 2-79673 | | 10(ii) | |
4 | (d) | * | Amendment to Partnership Agreement between Mesa Offshore Management Co., Texas Commerce Bank National Association, as Trustee, and Mesa Operating Limited Partnership, dated December 27, 1985 (Exhibit 4(d) to Form 10-K for year ended December 31, 1992 of Mesa Offshore Trust) | | 1-8432 | | 4(d) | |
4 | (e) | * | Amendment to Partnership Agreement between Texas Commerce Bank National Association, as Trustee and Mesa Operating dated as of January 5, 1994 (Exhibit 4(e) to Form 10-K for year ended December 31, 1993 of Mesa Offshore Trust) | | 1-8432 | | 4(e) | |
31 | | | Certification furnished pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | | | | | |
32 | | | Certification furnished pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | | | | | |
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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.
| MESA OFFSHORE TRUST |
| By: | /s/ JPMORGAN CHASE BANK, Trustee |
| By: | 
|
| | Mike Ulrich
Vice President & Trust Officer |
Date: November 14, 2004
The Registrant, Mesa Offshore 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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