ITEM 1. BUSINESS. DESCRIPTION OF THE TRUST
The Mesa Offshore Trust (the "Trust"), created under the laws of the State of Texas, maintains its offices at the office of the Trustee, Chase Bank of Texas National Association (the "Trustee"), 712 Main Street, Houston, Texas 77002. The telephone number of the Trust is (713) 216-6369.
The principal asset of the Trust consists of a 99.99% interest in the Mesa Offshore Royalty Partnership (the "Partnership"). The Trust was created on December 28, 1982, effective December 1, 1982, when Mesa Petroleum Co. conveyed to the Partnership certain overriding royalty interests (collectively, the "Royalty") carved out of Mesa Petroleum Co.'s existing working interests in ten producing and non-producing oil and gas leases offshore Louisiana and Texas (the "Royalty Properties"). The Partnership was formed for the purpose of receiving and holding the Royalty, receiving the proceeds from the Royalty, paying the liabilities and expenses of the Partnership and disbursing remaining revenues to the Trustee and Mesa Offshore Management Co., the managing general partner of the Partnership at that time, in accordance with their interests. Until August 7, 1997, MESA Inc. owned and operated its assets through Mesa Operating Co. ("Mesa"), the operator and the managing general partner of the Royalty Properties. On August 7, 1997, MESA Inc. merged with and into Pioneer, 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, Pioneer owns and operates its assets through PNR and is also the managing general partner of the Partnership. As hereinafter used in this report, the term PNR generally refers to the operator of the Royalty Properties, unless otherwise indicated. See "Termination of the Trust" on page 5 of this Form 10-K for additional information regarding PNR and the Trust.
Units of beneficial interest ("units") in the Trust were issued on December 28, 1982 to Mesa Petroleum Co. shareholders, who received one unit for each share of Mesa Petroleum Co. common stock held. The units are listed on the Pacific Exchange under the symbol "MOS".
The terms of the Mesa Offshore Trust Indenture (the "Trust Indenture") provide, among other things, that: (1) the Trust cannot acquire any asset other than its interest in the Partnership and cannot engage in any business or investment activity; (2) the Royalty can be sold in part or in total for cash upon approval of the unitholders or upon termination of the Trust; (3) the Trustee can establish cash reserves and borrow funds to pay liabilities of the Trust and can pledge the assets of the Trust to secure payment of the borrowing; (4) the Trustee will make quarterly distributions of cash available for distribution to the unitholders in January, April, July and October of each year; and (5) the Trust will terminate upon the first to occur of the following events: (i) the total amount of cash received per year 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 or (ii) a vote by holders of a majority of the outstanding units in favor of termination. Amounts paid to the Trustee as compensation were $128,000, $173,000 and $123,000, for the years 1998, 1997 and 1996, respectively. 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 terms of the First Amended and Restated Articles of General Partnership of the Partnership (the "Partnership Agreement") provide that the Partnership shall dissolve upon the occurrence of any of the following: (1) December 31, 2030; (2) the election of the Trustee to dissolve the Partnership; (3) the termination of the Trust; (4) the bankruptcy of the Managing General Partner; or (5) the dissolution of the Managing General Partner or its election to dissolve the Partnership; provided that the Managing General Partner shall not elect to dissolve the Partnership so long as the Trustee remains the only other partner of the Partnership.
The discussions of terms of the Trust Indenture and the Partnership Agreement contained herein are qualified in their entirety by reference to the Trust Indenture and the Partnership Agreement themselves, which are exhibits to this Form 10-K and are available upon request from the Trustee.
Under the instrument conveying the Royalty to the Partnership, the Trust is entitled to its share (99.99%) of 90% of the Net Proceeds, as hereinafter defined, realized from the sale of the minerals as, if and when produced from the Royalty Properties. See "Description of Royalty Properties" on page 6 of this Form 10-K. The instrument of conveyance provides for a monthly computation of Net Proceeds. "Net Proceeds" means the excess of Gross Proceeds, as hereinafter defined, received by PNR during a particular period over operating and capital costs and an amount to be recovered for future abandonment costs during such period. "Gross Proceeds" means generally the amount received by PNR from the sale of its share of minerals covered by the Royalty, subject to certain adjustments. Operating costs means, generally, costs incurred by PNR in operating the Royalty Properties, including capital costs. If operating and capital costs exceed the Gross Proceeds for any month, the excess plus interest thereon at the prime rate of the Bank of America plus one-half percent is recovered out of future Gross Proceeds prior to the making of further payment to the Trust. The Trust is not liable for any operating costs or other costs or liabilities attributable to the Royalty Properties or minerals produced therefrom. PNR, as owner of the working interest in the Royalty Properties, is required to maintain books and records sufficient to determine the amounts payable under the Royalty. Additionally, in the event of a controversy between PNR and any purchaser as to the correct sale price for any production, amounts received by PNR and promptly deposited by it with an escrow agent are not considered as having been received by PNR and therefore are not subject to being payable with respect to the Royalty until the controversy is resolved; but all amounts thereafter paid to PNR by the escrow agent will be considered amounts received from the sale of production. Similarly, operating costs include any amounts PNR is required to pay whether as a refund, interest or penalty to any purchaser because the amount initially received by PNR as the sales price was in excess of that permitted by the terms of any applicable contract, statute, regulation, order, decree or other obligation. Within 30 days following the close of each calendar quarter, PNR is required to deliver to the Trustee a statement of the computation of Net Proceeds attributable to such quarter.
The Royalty Properties are required to be operated by PNR in accordance with reasonable and prudent business judgment and good oil and gas field practices. PNR has the right to abandon any well or lease if, in its opinion, such well or lease ceases to produce or is not capable of producing oil, gas or other minerals in commercial quantities. PNR markets the production on terms deemed by it to be the best reasonably obtainable in the circumstances. See "Contracts" on page 13 of this Form 10-K. The Trustee has no power or authority to exercise any control over the operation of the Royalty Properties or the marketing of production therefrom.
The Trust has no employees. Administrative functions of the Trust are performed by the Trustee.
DESCRIPTION OF THE UNITS
Each unit is evidenced by a transferable certificate issued by the Trustee, which ranks equally as to distributions and has one vote on any matter submitted to unitholders. Each unit evidences an undivided interest in the Trust, which in turn owns a 99.99% interest in the Partnership.
DISTRIBUTIONS
The Trustee determines for each month the amount of cash available for distribution for such month. Such amount (the "Monthly Distribution Amount") is equal to the excess, if any, of the cash distributed by the Partnership to the Trust during such month, plus any other cash receipts of the Trust during such month (other than interest earned on the Monthly Distribution Amount for any other month), over the liabilities of the Trust paid during such month, and adjusted for changes made by the Trustee during such month in any cash reserves established for the payment of contingent or future obligations of the Trust. The Monthly Distribution Amount for each month is payable to unitholders of record on the monthly record date (the "Monthly Record Date"), which is the close of business on the last business day of such month, or such later date as the Trustee determines is required to comply with legal or stock exchange requirements. However, to reduce the administrative expenses of the Trust, the
Trust Indenture provides that the Trustee does not distribute cash monthly, but rather, during January, April, July and October of each year, distributes to each person who was a unitholder of record on a Monthly Record Date during one or more of the immediately preceding three months, the Monthly Distribution Amount for the month or months that he was a unitholder of record, together with interest earned on such Monthly Distribution Amount from the Monthly Record Date to the payment date.
LIABILITY OF UNITHOLDERS
As regards the unitholders, the Trustee is fully liable if the Trustee incurs any liability without ensuring that such liability will be satisfiable only out of the Trust assets (regardless of whether the assets are adequate to satisfy the liability) and in no event out of amounts distributed to, or other assets owned by unitholders. However, under Texas law, it is unclear whether a unitholder would be jointly and severally liable for any liability of the Trust in the event that all of the following conditions were to occur: (1) the satisfaction of such liability was not by contract limited to the assets of the Trust; (2) the assets of the Trust were insufficient to discharge such liability; and (3) the assets of the Trustee were insufficient to discharge such liability. Although each unitholder should weigh this potential exposure in deciding whether to retain or transfer his units, the Trustee is of the opinion that because of the passive nature of the Trust assets, the restrictions on the power of the Trustee to incur liabilities and the required financial net worth of any trustee, the imposition of any liability on a unitholder is extremely unlikely.
FEDERAL INCOME TAX MATTERS
OWNERSHIP OF UNITS
The federal income tax consequences to the unitholders of owning units depend on whether the Trust is classifiable as a grantor trust, a non-grantor trust, or a corporation. The Trustee reports on the basis that the Trust is a grantor trust. Based on its recent audit policy, the Internal Revenue Service (the "IRS") is expected to concur with such action. No IRS ruling has been received with respect to the Trust, however, and no court case has been decided involving identical facts and circumstances. It is possible, therefore, that the IRS will assert on audit that the Trust is taxable as a corporation and that a court might agree with such assertion.
INCOME AND DEPLETION
Royalty income, net of depletion and severance taxes, is treated as portfolio income, and, subject to certain exceptions and transitional rules, Royalty income cannot be offset by losses from passive businesses. Additionally, interest income is portfolio income. Administrative expense is an investment expense.
Generally, prior to the Revenue Reconciliation Act of 1990, the transferee of an oil and gas property could not claim percentage depletion with respect to production from such property if it was "proved" at the time of the transfer. This rule is not applicable in the case of transfers of properties after October 11, 1990. Thus, eligible unitholders that acquired units after that date are entitled to claim an allowance for percentage depletion with respect to Royalty income attributable to such units to the extent that such allowance exceeds cost depletion as computed for the relevant period.
BACKUP WITHHOLDING
Distributions from the Trust are generally subject to backup withholding at a rate of 31% of such distributions. Backup withholding will not normally apply to distributions to a unitholder, however, unless such unitholder fails to properly provide to the Trust his taxpayer identification number ("TIN") or the IRS notifies the Trust that the TIN provided by such unitholder is incorrect.
SALE OF UNITS
Generally, except for recapture items, the sale, exchange or other disposition of a unit will result in capital gain or loss measured by the difference between the basis in the unit and the amount realized. Such gain or loss would be capital gain or loss if such unit was held by the unitholder as a capital asset. For units sold on or prior to May 6, 1997, such capital gain will be long-term if such unitholder's holding period exceeded one year as of the date of sale or exchange. The Taxpayer Relief Act of 1997 reduced the maximum long-term capital gains rate to 20% for capital assets sold after May 6, 1997, but
the holding period necessary to qualify for the reduced rate increased to 18 months effective for sales after July 28, 1997. A special "mid-term" rate (generally 28%) applies to capital assets sold after July 28, 1997 with a holding period of over one year but not over 18 months. Effective for property placed in service after December 31, 1986, the amount of gain, if any, realized upon the disposition of oil and gas property is treated as ordinary income to the extent of the intangible drilling and development costs incurred with respect to the property and depletion claimed with respect to such property to the extent it reduced the taxpayer's basis in the property. Depletion attributable to a positive Section 743(b) basis adjustment of a unit acquired after 1986 will be subject to recapture as ordinary income upon disposition of the unit or upon disposition of the oil and gas property to which the depletion is attributable. The balance of any gain or any loss will be capital gain or loss, if such unit was held by the unitholder as a capital asset.
FOREIGN UNITHOLDERS
In general, a unitholder who is a nonresident alien individual or which is a foreign corporation (each, a "Foreign Taxpayer") will be subject to tax on the gross income produced by the Royalty at a rate equal to 30% (or lower treaty rate, if applicable). This tax will be withheld by the Trustee and remitted directly to the United States Treasury. A Foreign Taxpayer may elect to treat the income from the Royalty as effectively connected with the conduct of a United States trade or business under Section 871 or Section 882 of the Internal Revenue Code of 1986, as amended (the "Code"), (or pursuant to any similar provisions of applicable treaties). Upon making this election such unitholder is entitled to claim all deductions with respect to such income, but he must file a United States federal income tax return to claim such deductions. This election once made is irrevocable (unless an applicable treaty allows the election to be made annually). However, for tax years beginning after December 31, 1987, such effectively connected income will be subjected to withholding equal to the highest applicable percentage (tax rate)-39.6% for individual foreign unitholders and 35% for corporate foreign unitholders.
Section 897 of the Code and the Treasury Regulations thereunder treat the publicly traded Trust as if it were a United States real property holding corporation. Accordingly, Foreign Taxpayers owning greater than 5% of the outstanding units are subject to United States federal income tax on the gain on the disposition of their units. Foreign unitholders owning 5% or less of the outstanding units are not subject to United States federal income tax on the gain on the disposition of their units.
Federal income taxation of a Foreign Taxpayer is a highly complex matter which may be affected by many other considerations. Therefore, each Foreign Taxpayer should consult with his own tax adviser as to the advisability of his ownership of units.
TAX-EXEMPT ORGANIZATIONS
Investments in publicly traded partnerships are treated the same as investments in other partnerships for purposes of the rules governing unrelated business taxable income. The Royalty and interest income should not be unrelated business taxable income so long as, generally, a unitholder did not incur debt to acquire a unit or otherwise incur or maintain a debt that would not have been incurred or maintained if such unit had not been acquired. Legislative proposals have been made from time to time which, if adopted, would result in the treatment of Royalty income as unrelated business income. Tax-exempt unitholders should consult their own tax advisors with respect to the treatment of royalty income.
PENDING SALE AGREEMENT
In December 1998, PNR signed a purchase and sale agreement (the "Agreement") with Costilla Energy, Inc. ("Costilla") to sell certain PNR oil and gas properties. Included with the properties to be sold are PNR's interest in all of the Trust properties. The consummation of this Agreement is primarily dependent upon the Costilla's ability to finance the purchase as well as certain other contingencies defined in the Agreement. The sale is expected to close by March 31, 1999. Subsequent to the closing, PNR expects to continue to operate the Trust properties for a limited period of time; however, Costilla will become the Managing General Partner of the Partnership. There can be no assurance that the sale of any or all of these properties will be completed. In addition, if such a sale is consummated, the Trust has been advised that there should be no significant impact on the Trust, although the precise nature of any effects cannot be predicted or quantified at this time.
TERMINATION OF THE TRUST
As discussed above under "Description of the Trust", the terms of the Mesa Offshore Trust Indenture provide that the Trust will terminate upon 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 the unitholders 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 pages 12 and 13 of this Form 10-K and Note 6 in the Notes to Financial Statements included elsewhere in this Form 10-K. 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, which is an exhibit to this Form 10-K and is available upon request from the Trustee.
In addition, in the event of a dissolution of the Partnership (which could occur under the circumstances described above under "Description of the Trust") and a subsequent winding up and termination thereof, the assets of the Partnership (i.e., the Royalty interest) could either (1) be distributed in kind ratably to the Managing General Partner and the Trustee or (2) 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.
The December 31, 1998 reserve report prepared for the Partnership indicates that Royalty income expected to be received by the Trust in 1999 and 2000 could be at or near the Termination Threshold. The reserve report estimates that future Royalty income to the Trust is approximately $5.2 million while the Termination Threshold for 1998 was approximately $1.4 million. It is therefore possible (depending on the timing of future production, market conditions, recoupment of unrecovered capital costs, the receipt of amounts withheld from the Trust related to MMS royalty claims, and other matters) that in either 1999 or 2000 Royalty income received by the Trust may be below the Termination Threshold. If Royalty income falls below the Termination Threshold for three successive years, the Trust would terminate pursuant to the terms discussed above. 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, there can be no assurance that Royalty income received by the Trust in 1999 or 2000 will be above the Termination Threshold.
DESCRIPTION OF ROYALTY PROPERTIES
PRODUCING ACREAGE AND WELLS AS OF DECEMBER 31, 1998
- ------------ (1) Dual completions are counted as one well. For information regarding wells producing at December 31, 1998, see "Net Proceeds, Production and Average Prices" on page 21 of this Form 10-K.
(2) Net Producing Acres are calculated by multiplying gross producing acres by the net Royalty interest (as defined by the Trust Indenture) attributable to the Trust for each property.
RESERVES
A study of the proved oil and gas reserves attributable to the Partnership as of December 31, 1998, has been made by PNR. The following letter (the "Reserve Report") summarizes such reserve study. The Reserve Report reflects estimated reserve quantities and future net revenue based upon estimates of the future timing of actual production without regard to when received in cash by the Trust, which differs from the manner in which the Trust recognizes and accounts for its royalty income. For further information regarding the Net Overriding Royalty Interest, the Basis of Accounting for the Trust and Reserves, see Notes 2, 3 and 6, respectively, in the Notes to Financial Statements contained in Item 8 of this Form 10-K.
[LOGO] PIONEER NATURAL RESOURCES
SUMMARY REPORT DATED MARCH 1999
ON
RESERVES AND REVENUE AS OF DECEMBER 31, 1998
FROM CERTAIN PROPERTIES OWNED BY
MESA OFFSHORE TRUST
[LOGO]
March 17, 1999
MESA Offshore Trust Chase Bank of Texas, N.A. (as Trustee) Chase Tower, Suite 1150 600 Travis Street Houston TX 77002
Ladies and Gentlemen:
Pursuant to your request, we have prepared estimates, as of December 31, 1998, of the extent and value of the proved crude oil, condensate, natural gas liquids, and natural gas reserves of certain properties subject to a net profits interest owned by the Mesa Offshore Royalty Partnership, hereinafter referred to as the "Partnership," a partnership owned 99.99 percent by the Mesa Offshore Trust. The interest appraised is referred to herein as the "Partnership Interest" and consists of a 90 percent net profits interest in ten Pioneer Natural Resources USA, Inc. (hereinafter referred to as "Pioneer") leases located in the Gulf of Mexico offshore from Louisiana and Texas. The ten offshore leases subject to the net profits interest are hereinafter referred to as the "Subject Properties." Three of these leases have been abandoned; reserves of the remaining seven leases are reported herein.
The reserve estimates are based on a detailed study of the Subject Properties. The method or combination of methods used in the study of each reservoir was tempered by experience in the area, consideration of the stage of development of the reservoir, and the quality and completeness of basic data.
Estimates of oil, condensate, natural gas liquids and gas reserves and future net revenue should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserve and revenue estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgment factors in interpreting such information.
In the preparation of this report, Pioneer has used internal information with respect to property interests owned by the Partnership, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information.
The development status shown herein represents the status applicable as of December 31, 1998. Data available from wells drilled on the appraised properties through December 31, 1998 were used in estimating gross ultimate recovery. Gross production estimated to December 31, 1998, was deducted from gross ultimate recovery to arrive at the estimates of gross reserves. In some fields, this required that the production rates be estimated for a portion of 1998 since production data for these properties were not available throughout 1998.
The reserve volumes and revenue values shown in this report for Partnership Interest were estimated from projections of reserves and revenue attributable to the combined interests consisting of the Partnership Interest and the retained Pioneer Interest in the Subject Properties (Combined Interest). Net reserves attributable to the Partnership Interest were estimated by allocating to the Partnership a portion of the estimated combined net reserves of the Subject Properties based on future revenue. Because the net reserve volumes attributable to the
MESA Offshore Trust March 17, 1999
Partnership Interest are estimated using an allocation of reserves based on estimates of future revenue, a change in prices or costs will result in changes in the estimated net reserves. Therefore, the estimated net reserves attributable to the Partnership Interest will vary if different future price and cost assumptions are used.
Petroleum reserves included in this report are classified as proved and are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analysis, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs as of the date the estimate is made, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:
o Proved - Reserves that have been proved to a high degree of certainty by analysis of the producing history of a reservoir and/or by volumetric analysis of adequate geological and engineering data. Commercial productivity has been established by actual production, successful testing, or in certain cases by favorable core analyses and electrical-log interpretation when the producing characteristics of the formation are known from nearby fields. Volumetrically, the structure, areal extent, volume, and characteristics of the reservoir are well defined by a reasonable interpretation of adequate subsurface well control and by known continuity of hydrocarbon-saturated material above known fluid contacts, if any, or above the lowest known structural occurrence of hydrocarbons.
o Developed - Reserves that are recoverable from existing wells with current operating methods and expenses. Developed reserves include both producing and nonproducing reserves. Estimates of producing reserves assume recovery by existing wells producing from present completion intervals with normal operating methods and expenses. Developed nonproducing reserves are in reservoirs behind the casing or at minor depths below the producing zone and are considered proved by production from other wells in the field, by successful drill-stem tests, or by core analysis from the particular zones. Nonproducing reserves require only moderate expense to be brought into production.
o Undeveloped - Reserves that are recoverable from additional wells yet to be drilled. Undeveloped reserves are those considered proved for production by reasonable geological interpretation of adequate subsurface control in reservoirs that are producing or proved by other wells but are not recoverable from existing wells. This classification of reserves requires drilling of additional wells, major deepening of existing wells, or installation of enhanced recovery or other facilities.
Estimates of the net proved reserves attributable to the Partnership Interest, as of December 31, 1998, are as follows:
TOTAL PROVED RESERVES: Natural Gas (Mcf)............................ 2,280,001 Oil and Condensate (bbl)..................... 404,272 Natural Gas Liquids (bbl).................... 0
PROVED DEVELOPED RESERVES Natural Gas (Mcf)............................ 933,684 Oil and Condensate (bbl)..................... 5,628 Natural Gas Liquids (bbl).................... 0
MESA Offshore Trust March 17, 1999
Revenue values attributable to the net proved reserves of the Partnership Interest are expressed in terms of estimated future net revenue and present worth of future net revenue. Future net revenue attributable to the Partnership Interest was estimated monthly from a projection of the combined Pioneer and Partnership future net revenue. Combined future net revenue values were calculated by deducting operating expenses and capital costs from the future gross revenue of the Combined Interest. The monthly values for the aggregate of the Combined Interest in the Subject Properties were reduced by an overhead charge, by a monthly amount necessary for Pioneer to accrue the abandonment costs over the life of the properties, by the deficit balance as described below from the previous month, and by the interest on that deficit balance when such deficits occur. If the adjusted revenue resulting from this calculation was negative, it was carried forward to the next month as a deficit balance. If the adjusted revenue was greater than zero, it was multiplied by a factor of 90 percent to arrive at the future net revenue of the Partnership Interest. The above calculations were made monthly in the aggregate for the Subject Properties. Interest was charged monthly on the net profits deficit balance (cost not recovered currently) at the rate of 9.0 percent per year. The deficit balance as of December 31, 1998 was $1,029,737.
Future oil and gas producing rates estimated for this report are based on production rates considering the most recent figures available or, in certain cases, are based on estimates tempered by Pioneer's experience in the area. The rates used for future production are rates that Pioneer has determined are within the capacity of the well or reservoir to produce.
Gas volumes shown herein are expressed at standard conditions of 60 degrees Fahrenheit and a 15.025 pounds per square inch absolute. Condensate reserves estimated herein are those to be obtained from normal separator recovery.
Revenue values in this report were estimated using current prices and costs. Future prices were estimated using guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board.
The assumptions used for estimating future prices and costs are as follows:
o Oil and Condensate Prices - Oil and condensate prices were held constant for the life of the properties.
o Natural Gas Prices - Gas prices were held constant for the life of the properties.
o Natural Gas Liquids Prices - Natural gas liquids prices were held constant for the life of the properties.
o Operating and Capital Costs - Current estimates of operating costs were used for the life of the properties with no increases in the future based on inflation. Future capital expenditures were estimated using 1998 values and were not adjusted for inflation.
A summary of estimated revenue and costs attributable to the Combined Interest in proved reserves and the future net revenue and present worth attributable to the Partnership Interest, as of December 31, 1998 is as follows:
MESA Offshore Trust March 17, 1999
COMBINED INTEREST: Future Gross Revenue ($).................... 8,740,898 Production and Ad Valorem Taxes ($)......... 0 Operating Costs ($)......................... (1,804,756) Capital Costs ($)(1)........................ (10,497,250) Future Net Revenue ($)...................... (3,561,108)
Accrued Revenue for Abandonment Costs ($)... 10,010,271 Future Accrued Revenue for Abandonment Costs ($)................................. 470,733 Cumulative Net Profits Deficit @ 12/31/98 .. (1,144,152) Revenue Subject to Net Profits Interest ($). 5,775,744
PARTNERSHIP INTEREST: Future Net Revenue ($)(2)................... 5,198,165 Present Worth at 10 Percent ($)............. 3,977,242
(1) Includes abandonment costs. (2) Future income tax expenses were not taken into account in the preparation of these estimates.
The information relating to estimated proved reserves, estimated future net revenue from proved reserves, and present worth of estimated future net revenue from proved reserves of oil, condensate, natural gas liquids, and gas contained in this report has been prepared in accordance with Paragraphs 10-13, 15 and 30(a)-(b) of Statement of Financial Accounting Standards No. 69 (November 1982) of the Financial Accounting Standards Board and Rules 4-10(a)(1)-(13) of Regulation S-X and Rule 302(b) of Regulation S-K of the Securities and Exchange Commission; provided, however, future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein.
To the extent the above enumerated rules, regulations, and statements require determinations of an accounting or legal nature or information beyond the scope of this report, we are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.
Submitted,
/s/ RICHARD MASSENGILL D. Richard Massengill
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The preceding reserve data in the Reserve Report represent estimates only and should not be construed as being exact. Reserve assessment is a subjective process of estimating the recovery from underground accumulations of gas and oil that cannot be measured in an exact way, and estimates of other persons might differ materially from those of PNR. Accordingly, reserve estimates are often different from the quantities of hydrocarbons that are ultimately recovered.
Also, while estimates of reserves attributable to the Royalty Properties are shown in order to comply with requirements of the Securities and Exchange Commission (the "SEC"), there is no precise method of allocating estimates of physical quantities of reserves between PNR and the Partnership, since the Royalty is not a working interest and the Partnership does not own and is not entitled to receive any specific volume of reserves from the Royalty. Reserve quantities in the previously mentioned reserve study have been allocated based on the method referenced in the Reserve Report. The quantities of reserves attributable to the Partnership will be affected by future changes in various economic factors utilized in estimating future gross and net revenues from the Royalty Properties. Therefore, the estimates of reserves set forth in the Reserve Report are to a large extent hypothetical and differ in significant respects from estimates of reserves attributable to a working interest.
Moreover, the discounted present values in the Reserve Report should not be construed as the current market value of the estimated gas and oil reserves attributable to the Royalty Properties or the costs that would be incurred to obtain equivalent reserves, since a market value determination would include many additional factors. In accordance with applicable regulations of the SEC, estimated future net revenues were based, generally, on current prices and costs, whereas actual future prices and costs may be materially greater or less. The estimates in the Reserve Report use market prices as of December 31, 1998 pursuant to gas contracts in effect on January 1, 1999. These prices (having a weighted average of $1.83 per Mcf as of December 31, 1998) were held constant over the estimated life of the Royalty Properties. Such prices were influenced by seasonal demand for natural gas and may not be the most appropriate or representative prices to use for estimating future revenues or related reserve data. The average price of natural gas sold from the Royalty Properties during 1998 was $2.31 per Mcf, representing a combination of contract prices and spot market prices.
The following is a summary of the estimated remaining life for each of the Royalty Properties provided to the Trustee by PNR as of December 31, 1998. There are numerous uncertainties present in estimating the remaining productive lives for the Royalty Properties. The following summary represents an estimate only and should not be construed as being exact. The estimated remaining productive life of each property varies depending on the recoverable reserves and annual production assumed by PNR. In addition, future economic and operating conditions may cause significant changes in such estimates.
PROPERTY - ------------------------------------------------ South Marsh Island 155/156...................... -- West Delta 61/62................................ 15-20 years Brazos A-7...................................... 4-5 years Brazos A-39..................................... 1-2 years Matagorda Island 624............................ 3-4 years - ------------ (1) The Trust will terminate in the event the total amount of cash received per year by the Trust falls below certain levels. Accordingly, it would be possible for the Trust to terminate even though some of the Royalty Properties continued to have remaining productive lives. See "Termination of the Trust" on page 5 of this Form 10-K.
(2) Estimates of remaining lives may vary significantly from year to year.
The future net revenues contained in the Reserve Report have not been reduced for future general and administrative costs and expenses of the Trust, which are expected to approximate $500,000 annually. The general and administrative costs and expenses of the Trust may increase in future years, depending on the amount of royalty income, increases in accounting, engineering, legal and other professional fees and other factors.
PNR has advised the Trust that there have been no events subsequent to December 31, 1998 that have caused a significant change in the estimated proved reserves referred to in the Reserve Report.
PROCEEDS, PRODUCTION AND AVERAGE PRICES
Reference is made to "Net Proceeds, Production and Average Prices" under Item 7 of this Form 10-K.
ASSETS
Reference is made to Item 6 of this Form 10-K for information relating to the assets of the Trust.
CONTRACTS
GENERAL. PNR has advised the Trust that during 1998 its offshore gas production was marketed under short-term contracts at spot market prices primarily to H&N, Limited. PNR has further advised the Trust that it expects to continue to market its production under short-term contracts for the foreseeable future; however, it is not known whether Costilla will change the current marketing practices. Spot market prices for natural gas in 1998 were generally lower than spot market prices in 1997. Information regarding recent prices received for production from the Royalty Properties is provided below.
BRAZOS A-7 AND A-39. In March 1999, most of the gas from this property was being sold to H&N, Limited at an average price of $1.59 per MMBtu.
SOUTH MARSH ISLAND 155 AND 156. In March 1999, most of the gas from this property was being sold to H&N, Limited at an average price of $1.61 per MMBtu.
WEST DELTA 61 AND 62. In March 1999, most of the gas from this property was being sold to H&N, Limited at an average price of $1.57 per MMBtu.
MATAGORDA ISLAND 624. In March 1999, most of the gas from this property was being sold to H&N, Limited at an average price of $1.57 per MMBtu.
MARKET FOR NATURAL GAS
The amount of cash distributions by the Trust is dependent on, among other things, the sales prices for natural gas produced from the Royalty Properties and the quantities of gas sold. The natural gas industry in the United States during the past decade has been affected generally by a surplus in natural gas deliverability in comparison to demand. Demand for gas declined during this period due to a number of factors including the implementation of energy conservation programs, a shift in economic activity away from energy intensive industries and competition from alternative fuel sources such as residual fuel oil, coal and nuclear energy. The surplus of natural gas deliverability caused a general deterioration in gas prices. The annual average wellhead price for natural gas peaked in 1984 at $2.66 per Mcf and declined to $1.55 per Mcf in 1995. Annual wellhead prices generally increased from 1995 to $2.17 per MCF in 1996 and $2.32 per MCF in 1997 and decreased to an estimated $1.90 in 1998, according to the Natural Gas Monthly published by the Energy Information Administration of the Department of Energy. Spot prices for domestic natural gas were negatively affected by warmer than normal weather in the winters of 1997-98 and 1998-99.
The seasonal nature of demand for natural gas and its effects on sales prices and production volumes may cause the amounts of cash distributions by the Trust to vary substantially on a seasonal basis. Generally, production volumes and prices are higher during the first and fourth quarters of each
calendar year due primarily to peak demand in these periods. Because of the time lag between the date on which PNR receives payment for production from the Royalty Properties and the date on which distributions are made to unitholders, the seasonality that generally affects production volumes and prices is generally reflected in distributions to unitholders in later periods.
COMPETITION
The production and sale of gas from the areas in which the Royalty Properties are located is highly competitive and PNR has a number of competitors in these areas. PNR has advised the Trust that it believes that its competitive position in these areas is affected by price, contract terms and quality of service. PNR's business is affected not only by such competition, but also by general economic developments, governmental regulations and other factors.
MARKETING OF LIQUIDS
PNR generally reserves in its gas purchase contracts the right to extract condensate and other liquid and liquifiable hydrocarbons from all gas produced. PNR is currently selling the condensate and other liquids to various purchasers under contracts with terms of one year or less.
A PNR subsidiary owns a 100% interest in a pipeline which transports crude oil from South Marsh Island 155 and 156 to an underwater connection with Marathon Pipe Line Company's ("Marathon") pipeline on South Marsh Island 139. In 1998, PNR charged $3.60 per barrel for transportation of crude oil from these properties, which included Marathon's currently posted tariff of $1.55 per barrel and the PNR subsidiary's tariff of $2.05 per barrel. Tariffs are subject to approval by the Federal Energy Regulatory Commission (the "FERC").
Future pipeline construction and operation arrangements may be necessary for the marketing of crude oil and other liquid hydrocarbon production, if any, from the other Royalty Properties. PNR could be involved in such arrangements.
REGULATION AND PRICES
GENERAL
The production and sale of natural gas from the Royalty Properties are affected from time to time in varying degrees by political developments and federal, state and local laws and regulations. In particular, oil and gas production operations and economics are, or in the past have been, affected by price controls, taxes, conservation, safety, environmental and other laws relating to the petroleum industry, by changes in such laws and by constantly changing administrative regulations.
OPERATING HAZARDS AND UNINSURED RISKS
PNR's oil and gas activities are subject to all of the risks normally incident to exploration for and production of oil and gas, including blowouts, cratering and fires, each of which could result in damage to life and property. Offshore operations are subject to a variety of operating risks, such as hurricanes and other adverse weather conditions and lack of access to existing pipelines or other means of transporting production. Furthermore, offshore oil and gas operations are subject to extensive governmental regulations, including certain regulations that may, in certain circumstances, impose absolute liability for pollution damages, and to interruption or termination by governmental authorities based on environmental or other considerations. In accordance with customary industry practices, PNR carries insurance against some, but not all, of these risks. Losses and liabilities resulting from such events would reduce revenues and increase costs to the Trust to the extent not covered by insurance.
FERC REGULATION
In recent years, the FERC has required interstate pipeline companies to "unbundle" their services. To the extent a pipeline company or its sales affiliate makes gas sales as a merchant in the future, it does so pursuant to private contracts in direct competition with all other sellers, such as PNR. In recent years, the FERC also has pursued a number of other policy initiatives which could significantly affect the marketing of natural gas. Several of these initiatives are intended to enhance competition in natural gas markets, although some, such as "spin-downs," may have the adverse effect of increasing the cost of doing business on some in the industry. On July 29, 1998, the FERC issued two orders in which the FERC is considering revisions to its regulations of short-term and long-term transportation markets. As to all of these recent FERC initiatives, PNR has advised the Trust that the on-going, or, in some instances, preliminary evolving nature of these regulatory initiatives makes it impossible at this time to predict their ultimate impact on the prices, markets or terms of sale of natural gas related to the Trust.
STATE REGULATION
State regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, non-discriminatory take requirements. Recently some states have implemented more stringent legislation to regulate gathering rates charged by gas gathering companies but to date the effect to PNR is minimal.
ENVIRONMENTAL
PNR's operations are subject to numerous federal, state and local laws and regulations controlling the discharge of materials into the environment or otherwise relating to the protection of the environment, including the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA" or "Superfund"), the Solid Waste Disposal Act, the Clean Air Act, and the Federal Water Pollution Control Act. These laws and regulations, including their state counterparts, can impose liability upon the lessee under a lease for the cost of cleanup of discharged materials resulting from a lessee's operations or can subject the lessee to liability for damages to natural resources. Violations of environmental laws, regulations, or permits can result in civil and criminal penalties as well as potential injunctions curtailing operations in affected areas and restrictions on the injection of liquids into the subsurface that may contaminate groundwater. PNR maintains insurance for costs of cleanup operations, but it is not fully insured against all such risks. A serious release of regulated materials could result in the DOI requiring lessees under federal leases to suspend or cease operations in the
affected area. In addition, the recent trend toward stricter standards and regulations in environmental legislation is likely to continue. For example, legislation has been proposed in Congress that would reclassify certain oil and gas production wastes as "hazardous wastes" which would subject the handling, disposal and cleanup of these wastes to more stringent requirements and result in increased operating costs for the Royalty Properties, as well as the oil and gas industry in general. State initiatives to further regulate the disposal of oil and gas wastes are also pending in certain states, and these initiatives could have a similar impact on the Royalty Properties.
From time to time, federal and state environmental agencies propose regulations which could have a direct and material impact on PNR's operations. For example, under the Oil Pollution Act of 1990, as amended by the Coast Guard Authorization Act of 1996, (collectively, "OPA"), parties responsible for offshore facilities must establish and maintain evidence of oil-spill financial responsibility ("OSFR") for costs attributable to potential oil spills. OPA requires a minimum of $35 million in OSFR for offshore facilities located on the OCS. This amount is subject to upward regulatory adjustment up to $150 million. Responsible parties for more than one offshore facility are required to provide OSFR only for their offshore facility requiring the highest OSFR. In 1998, the Minerals Management Service adopted regulations for establishing the amount of OSFR required for particular facilities. The amount of OSFR increases as the volume of a facility's worst-case oil spill increases. Accordingly, for facilities with worst-case spills of less than 35,000 barrels, only $35 million in OSFR is required; for worst-case spills of over 35,000 barrels, $70 million is required; for worst-case spills of over 70,000 barrels, $105 million is required; and for worst-case spills of over 105,000 barrels, $150 million is required. In addition, all OSFR below $150 million remains subject to upward regulatory adjustment if warranted by the particular operational, environmental, human health or other risks involved with a facility. Under this regulation, PNR is required to maintain $ 35 million in OSFR for its offshore facilities. PNR is maintaining its OSFR in this amount by insurance. Although the working interest owners have advised the Trust that current environmental regulation has had no material adverse effect on the working interest owners' present method of operations, the impact of the recently adopted regulatory changes, and of future environmental regulatory developments such as stricter environmental regulation and enforcement policies, cannot presently be quantified. By letter dated November 9, 1995, PNR was advised by the MMS that it does not qualify for a waiver from supplemental bond requirements and that PNR may be required to post supplemental bonds covering its potential obligations with respect to offshore operations. PNR executed a guaranty of abandonment liability (area wide) with the MMS on April 26, 1996, in satisfaction of these obligations.
PNR has advised the Trust that it is not involved in any administrative or judicial proceedings relating to the Royalty Properties arising under federal, state, or local environmental protection laws and regulations which would have a material adverse effect on the Trust's financial position or results of operations.
PLATFORM ABANDONMENT AND REMOVAL
PNR is responsible for the abandonment and removal of its offshore drilling and production structures within one year after the cessation of production, although extensions can be requested.
ITEM 2.
ITEM 2. PROPERTIES.
Reference is made to Item 1 of this Form 10-K.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
There are no pending legal proceedings to which the Trust is a party.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
There were no matters submitted to a vote of unitholders during the fourth quarter of 1998.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED UNITHOLDER MATTERS.
The units of beneficial interest of Mesa Offshore Trust are traded on the Pacific Exchange -- ticker symbol MOS. The high and low sales prices and distributions per unit for each quarter in the two years ended December 31, 1998 were as follows:
At March 26, 1999, the 71,980,216 units outstanding were held by 14,525 unitholders of record.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
FINANCIAL REVIEW
YEARS 1998 AND 1997
Royalty income decreased to $1,683,664 in 1998 as compared to $5,737,644 in 1997, primarily as a result of lower natural gas production and prices and the recovery of capital costs associated with completion costs on the Brazos A-7 No. 5 well in the fourth quarter of 1998.
Production volumes for natural gas decreased to 1,277,464 Mcf in 1998 compared with 4,030,273 Mcf in 1997. The decrease was due primarily to natural production decline. The average sale price received for natural gas in 1998 was $2.31 per Mcf compared with $2.66 per Mcf in 1997.
Crude oil, condensate and natural gas liquids production volumes decreased to 51,066 barrels in 1998 compared with 170,158 barrels in 1997. The decrease was due primarily to natural production decline at South Marsh Island 155 and 156. The average sale price in 1998 for crude oil, condensate and natural gas liquids was $13.03 per barrel compared with $16.97 per barrel in 1997.
YEARS 1997 AND 1996
Royalty income was $5,737,644 in 1997 as compared to $36,014 in 1996. The increase in Royalty income was primarily due to the recovery of 1996 drilling costs on South Marsh Island blocks 155 and 156 by PNR in the first quarter of 1997. Distributable income increased to $4,900,814 ($.0681 per unit) in 1997 as compared to no distributable income in 1996.
Production volumes for natural gas decreased to 4,030,273 Mcf in 1997 compared with 4,499,242 Mcf in 1996. The decrease was due primarily to natural production decline. The average sale price received for natural gas in 1997 was $2.66 per Mcf compared with $2.25 per Mcf in 1996.
Crude oil, condensate and natural gas liquids production volumes increased to 170,158 barrels in 1997 compared with 162,405 barrels in 1996. The increase was due primarily to increased production
on South Marsh Island. The average sale price in 1997 for crude oil, condensate and natural gas liquids was $16.97 per barrel compared with $15.83 per barrel in 1996.
GENERAL
From inception of the Trust on December 1, 1982 through December 31, 1987, PNR, as working interest owner, spent $110 million ($99 million net to the Trust) to explore and develop the Royalty Properties. No significant expenditures regarding exploration and development were made during 1988, 1989 or 1990. Beginning in late 1991 and continuing in 1992, PNR spent $9.6 million ($8.7 million net to the Trust) on exploration and development. No significant exploration and development expenditures were made in 1993 or 1994. As discussed below, PNR spent $3.4 million ($1.2 million net to the Trust) on exploration and development during 1995, $21.9 million ($13.8 million net to the Trust) in 1996, $2.9 million ($1.8 million net to the Trust) in 1997, and $7.5 million ($746,000 net to the Trust) in 1998. PNR anticipates spending up to approximately $72,000 ($45,000 net to the Trust) primarily on a possible workover on South Marsh Island 155 and 156 in 1999, and recompletions on Brazos 155 and 156 in 1999.
LIQUIDITY AND CAPITAL RESOURCES
In accordance with the provisions of the Trust conveyance, generally all revenues received by the Trust, net of Trust administrative expenses and any cash reserves established for the payment of contingent or future obligations of the Trust, are distributed currently to the unitholders.
The Trust's source of cash is the Royalty income received from its share of the net proceeds from the Royalty Properties. Reference is made to Note 6 in the Notes to Financial Statements under Item 8
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
MESA OFFSHORE TRUST
STATEMENTS OF DISTRIBUTABLE INCOME
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
STATEMENTS OF CHANGES IN TRUST CORPUS
The accompanying notes are an integral part of these financial statements.
MESA OFFSHORE TRUST NOTES TO FINANCIAL STATEMENTS
(1) TRUST ORGANIZATION AND PROVISIONS
THE TRUST
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 predecessor to MESA Inc., transferred to the Trust a 99.99% interest in the Mesa Offshore Royalty Partnership (the "Partnership"). The Trust is an independent trust administered by Chase Bank of Texas National Association, as trustee (the "Trustee").
The terms of the Mesa Offshore Trust Indenture (the "Trust Indenture") provide, among other things, that:
(a) the Trust cannot engage in any business or investment activity or purchase any assets;
(b) the interest in the Partnership can be sold in part or in total for cash upon approval of the unitholders;
(c) the Trustee can establish cash reserves and borrow funds to pay liabilities of the Trust and can pledge the assets of the Trust to secure payment of the borrowings;
(d) the Trustee will make cash distributions to the unitholders in January, April, July and October of each year as discussed more fully in Note 4; and
(e) the Trust will terminate upon the first to occur of the following events: (i) 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 (ii) a vote by the unitholders in favor of termination. Amounts earned by the Trustee as compensation were $128,000, $173,000 and $123,000 for the years 1998, 1997 and 1996, respectively. 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 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.
The Partnership is owned 99.99% by the Trust and 0.01% by PNR. PNR serves as the managing general partner of the Partnership. PNR receives no compensation for serving as managing general partner other than the income it receives attributable to its interest in the Partnership.
STATUS OF THE TRUST
The December 31, 1998 reserve report prepared for the Partnership (See Note 6) indicates that Royalty income expected to be received by the Trust in 1999 and 2000 could be at or near the Termination Threshold. The reserve report estimates that the future Royalty income to the Trust is approximately $5.2 million while the Termination Threshold for 1998 was approximately $1.4 million. It is therefore possible (depending on the timing of production, market
MESA OFFSHORE TRUST NOTES TO FINANCIAL STATEMENTS--CONTINUED
conditions, recoupment of unrecovered capital costs, the receipt of amounts withheld from the Trust related to MMS royalty claims, and other matters) that in either 1999 or 2000 Royalty income received by the Trust may be below the Termination Threshold. If Royalty income falls below the Termination Threshold for three successive years, the Trust would terminate pursuant to the terms discussed above. 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, there can be no assurance that Royalty income received by the Trust in 1999 or 2000 will be above the Termination Threshold.
(2) NET OVERRIDING ROYALTY INTEREST
The instruments conveying the Royalty to the Partnership provide that PNR will calculate and pay to the Partnership each month an amount equal to 90% of aggregate net proceeds for the preceding month. Generally, net proceeds means the excess of the amounts received by PNR from sales of its share of oil and gas from the Royalty Properties (gross proceeds) over the operating and capital costs incurred. Costs exceeding gross proceeds for any month are recovered by PNR, with interest thereon at the prime rate of the Bank of America plus one-half percent, out of future gross proceeds prior to making further royalty payments to the Partnership.
The initial carrying value of the Royalty represented the net book value assigned by PNR to the Royalty Properties at the date of transfer to the Trust. Amortization of the Royalty, 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 amounts do not affect distributable income.
(3) BASIS OF ACCOUNTING
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; and
(c) Trust general and administrative expenses are recorded in the month they accrue.
This basis for reporting distributable 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 generally accepted accounting principles 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.
(4) DISTRIBUTIONS TO UNITHOLDERS
Under the terms of the Trust Indenture, the Trustee must distribute to the unitholders all cash receipts, after paying liabilities and providing for cash reserves as determined necessary by the Trustee. The amounts distributed are determined on a monthly basis and are payable to unitholders of record as of the last business day of each month. However, cash distributions are made quarterly in January,
MESA OFFSHORE TRUST NOTES TO FINANCIAL STATEMENTS--CONTINUED
April, July and October, and include interest earned from the monthly record dates to the dates of distribution.
(5) FEDERAL INCOME TAXES
The Trustee reports on the basis that the Trust is a grantor trust. Based on its previous audit policy, the Internal Revenue Service (the "IRS") is expected to concur with such action. No IRS ruling has been received or requested with respect to the Trust, however, and no court case has been decided involving identical facts and circumstances. It is possible, therefore, that the IRS would assert upon audit that the Trust is taxable as a corporation and that a court might agree with such assertion.
As a grantor trust, the Trust will incur no federal income tax liability. In addition, it will incur little or no federal income tax liability if it is held to be a non-grantor trust. If the Trust were held to be taxable as a corporation, it would have to pay tax on its net taxable income at the corporate rate.
(6) SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)
Estimates of the proved oil and gas reserves attributable to the Royalty as of December 31, 1998, 1997 and 1996 are based on a report prepared by PNR. The estimates were prepared in accordance with guidelines established by the Securities and Exchange Commission (the "SEC"). Accordingly, the estimates were based on existing economic and operating conditions. The reserve volumes and revenue values contained in the reserve report for the Partnership interest were estimated by allocating to the Partnership a portion of the estimated combined net reserve volumes of the Royalty Properties based on future net revenue. Production volumes are allocated based on royalty income. Because the net reserve volumes attributable to the Partnership interest are estimated using an allocation of reserve volumes based on estimates of future net revenue, a change in prices or costs will result in changes in the estimated net reserve volumes. Therefore, the estimated net reserve volumes attributable to the Partnership interest will vary if different future price and cost assumptions are used. Only costs necessary to develop and produce existing proved reserve volumes were assumed in the allocation of reserve volumes to the Royalty.
Future prices for natural gas were based on prices in effect as of each year end and existing contract terms. Prices being received as of each year end were used for sales of oil, condensate and natural gas liquids. Operating costs, production and ad valorem taxes and future development and abandonment costs were based on current costs as of each year end, with no escalation.
There are numerous uncertainties inherent in estimating the quantities and value of proved reserves and in projecting the future rates of production and timing of expenditures. The reserve data below represent estimates only and should not be construed as being exact. Moreover, the discounted values should not be construed as representative of the current market value of the Royalty. A market value determination would include many additional factors including: (i) anticipated future oil and gas prices; (ii) the effect of federal income taxes, if any, on the future royalties; (iii) an allowance for return on investment; (iv) the effect of governmental legislation; (v) the value of additional reserves, not considered proved at present, which may be recovered as a result of further exploration and development activities; and (vi) other business risks.
Estimates of reserve volumes attributable to the Royalty are shown in order to comply with requirements of the SEC. There is no precise method of allocating estimates of physical quantities of reserve volumes between PNR and the Partnership, since the Royalty is not a working interest and the Partnership does not own and is not entitled to receive any specific volume of reserves from the Royalty. The quantities of reserves attributable to the Partnership have been and will be affected by changes in various economic factors utilized in estimating net revenues from the Royalty Properties, as well as any exploration activities which may be conducted by PNR. Therefore, the estimates of reserve
MESA OFFSHORE TRUST NOTES TO FINANCIAL STATEMENTS--CONTINUED
volumes set forth below are to a large extent hypothetical and differ in significant respects from estimates of reserves attributable to a working interest.
The future net revenues contained in the previously mentioned reserve report have not been reduced for future general and administrative costs and expenses of the Trust, which are expected to approximate $500,000 annually. The general and administrative costs and expenses of the Trust may increase in future years, depending on the amount of royalty income, increases in accounting, engineering, legal, and other professional fees and other factors.
The following schedules set forth (i) the estimated net quantities of proved and proved developed oil, condensate and natural gas liquids and natural gas reserves attributable to the Royalty, and (ii) the standardized measure of the discounted future royalty income attributable to the Royalty and the nature of changes in such standardized measure between years. These schedules are prepared on the accrual basis, which is the basis on which PNR maintains its production records and is different from the basis on which the Royalty is computed. Certain reclassifications have been made to prior year amounts to conform to the current year presentation.
ESTIMATED QUANTITIES OF PROVED AND PROVED DEVELOPED RESERVES (UNAUDITED)
- ------------
(See Notes on following page.)
MESA OFFSHORE TRUST NOTES TO FINANCIAL STATEMENTS--CONTINUED
STANDARDIZED MEASURE OF FUTURE ROYALTY INCOME FROM PROVED OIL AND GAS RESERVES, DISCOUNTED AT 10% PER ANNUM (UNAUDITED)
CHANGES IN THE STANDARDIZED MEASURE OF FUTURE ROYALTY INCOME FROM PROVED OIL AND GAS RESERVES, DISCOUNTED AT 10% PER ANNUM (UNAUDITED)
- ------------ o The estimated quantities of proved reserves for oil, condensate and natural gas liquids include oil and condensate reserves at December 31, of the respective years as follows: 1998, 404,272 Bbls; 1997, 54,769 Bbls; 1996, 192,574 Bbls.
o The estimated quantities of proved reserves, standardized measure of future royalty income and changes in the standardized measure represent 100% of amounts for the Partnership in which the Trust has a 99.99% interest.
o The "Future capital costs, net of amounts previously accrued" at December 31, 1998 includes, in thousands, $9,433 of future abandonment costs net of $9,009 previously accrued by PNR.
MESA OFFSHORE TRUST NOTES TO FINANCIAL STATEMENTS--CONTINUED
(7) SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
TO CHASE BANK OF TEXAS, NATIONAL ASSOCIATION (TRUSTEE) AND THE UNITHOLDERS OF THE MESA OFFSHORE TRUST:
We have audited the accompanying statements of assets, liabilities and trust corpus of the Mesa Offshore Trust as of December 31, 1998 and 1997, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 1998. These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
These financial statements were prepared on the basis of accounting described in Note 3, which is a comprehensive basis of accounting other than generally accepted accounting principles.
In our opinion, the financial statements referred to above present fairly, in all material respects, the assets, liabilities and trust corpus of the Mesa Offshore Trust as of December 31, 1998 and 1997, and its distributable income and changes in trust corpus for each of the three years in the period ended December 31, 1998, on the basis of accounting described in Note 3.
ARTHUR ANDERSEN LLP
Houston, Texas March 26, 1999
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
There are no directors or executive officers of the Registrant. The Trustee is a corporate trustee which may be removed by the affirmative vote of a majority of the units then outstanding at a meeting of the holders of units of beneficial interest of the Trust at which a quorum is present.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
Not applicable.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
(a) SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS. Not applicable.
(b) SECURITY OWNERSHIP OF MANAGEMENT. Not applicable.
(c) CHANGES IN CONTROL. Registrant knows of no arrangement, including the pledge of securities of the Registrant, the operation of which may at a subsequent date result in a change in control of the Registrant.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Not Applicable.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(a)(1) FINANCIAL STATEMENTS
The following financial statements are set forth under Part II, Item 8 of this Annual Report on Form 10-K on the pages indicated.
(a)(2) SCHEDULES
Schedules have been omitted because they are not required, not applicable or the information required has been included elsewhere herein.
(a)(3) EXHIBITS
- ------------ * Previously filed with the Securities and Exchange Commission and incorporated herein by reference.
(B) REPORTS ON FORM 8-K
None.
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(d) 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 CHASE BANK OF TEXAS, NATIONAL ASSOCIATION, TRUSTEE
By /s/ PETE FOSTER Pete Foster Senior Vice President & Trust Officer
March 26, 1999
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.
EXHIBIT INDEX
- ------------ * Previously filed with the Securities and Exchange Commission and incorporated herein by reference.