ITEM 1. BUSINESS.
BACKGROUND
Freeport-McMoRan Oil and Gas Royalty Trust (the Trust) was created effective September 30, 1983. On that date, Freeport-McMoRan Inc. (FTX) transferred to a Partnership (the Partnership) a net overriding royalty interest in certain offshore oil and gas properties equal to 90 percent of the Net Proceeds (as defined in the Conveyance referred to below) from FTX's working interests in such properties and conveyed a 99.9 percent general partnership interest in the Partnership to the Trust. Such net overriding royalty interest is referred to herein as the "Royalty." The Overriding royalty Conveyance which created the Royalty is referred to herein as the "Conveyance." The Trust is passive, with The Chase Manhattan Bank as Trustee. The Trustee has only such powers as are necessary for the collection and distribution of revenues attributable to the Royalty, the payment of Trust liabilities and the protection of Trust assets.
The Trust's cash receipts were less than $3 million in 1996, 1997, and 1998. The Trust Indenture stated that the Trust must terminate if the amount of cash per year received by the Trust for each of three successive years commencing after December 31, 1990 is less than $3 million. However, at a special meeting of the Unit holders held on March 12, 1999, the Unit holders approved a shareholder proposal to amend the Trust Indenture to extend the life of the Trust for at least two years. This extension expired on December 31, 2000. Therefore, the Trust Indenture requires the Trustee to sell the Trust's interest in the Partnership, or to cause the Partnership to sell the Royalty.
Early in December 2000, the Trustee was approached by representatives of Roberson Oil Company and IMC Global, Inc. (IMC), the Working Interest Owner, proposing a transaction whereby a to-be-formed corporation (NewCo) would purchase the Trust assets and the working interest from IMC. Thereafter, NewCo would conduct an exchange offer whereby Unit holders would be offered the opportunity to exchange, on terms and conditions established by NewCo, their Units in the Trust for shares in NewCo. The Trustee has received a shareholder proposal that would amend the Trust Indenture to allow the transaction to proceed if the proposal receives the requisite vote of Unitholders. The Trustee is currently preparing proxy materials and a notice of a special meeting of the Unit holders expected to be held in May of this year to authorize the Trustee to conduct a sale of the Trust's Royalty for nominal consideration in accordance with the plan described above. If a majority of the Unit holders entitled to vote at that meeting in which a quorum is present vote to authorize the Trustee to sell the Trust's assets to NewCo the Trustee will do so. If the sale to NewCo is not approved, the Trustee will proceed to conduct an auction of the Trust properties in accordance with the existing terms of the Trust Indenture. Complete information concerning the vote will be provided to the Unit holders in forthcoming proxy materials.
Ryder Scott Company Petroleum Engineers conducted an independent review of the oil and gas interest burdened by the Royalty and prepared estimates, as of December 31, 2000, of the discounted present value of future net revenues from proved reserves attributable to the Royalty. The report of Ryder Scott is set forth elsewhere in this report. The estimates were prepared in accordance with SEC regulations, which among other things require that estimated net revenues be based on prices and costs as of December 31, 2000. Ryder Scott estimated that the net present value (discounted at 10%) of proved reserves attributable to the Royalty was $15.5 million and that the undiscounted estimated future net revenues from proved reserves were $18.4 million as of December 31, 2000, however, the estimates do not take into account many additional factors that impact the value of the Royalty, including the following:
- Pursuant to the Conveyance, the Working Interest Owner is entitled to recoup certain costs before any payments are made with respect to the Royalty. When these costs cannot be paid out of current revenue, they are accrued and carried forward. As of December 31, 2000, the accumulated cost carry-forward was approximately $19.8 million. The estimated discounted present value of $15.5 million and the undiscounted estimated net revenues of $18.4 million in the Ryder Scott report do not take into account the cost carry-forward.
- The Ryder Scott estimates took into account only those reserves that were classified as proved reserve as of December 31, 2000, and only the estimated costs of developing and producing those proved reserves. Thus, the estimates did not take into account costs that may be incurred to discover, develop or produce reserves not classified as proved as of December 31, 2000, nor did they take into account future revenues, if any, from such reserves.
- The weighted average prices used in the Ryder Scott report were $23.52 per Bbl of oil and $5.85 per Mcf of gas. Oil and natural gas prices have declined substantially since December 31, 2000.
- Proceeds from gas produced but sold by other parties pursuant to gas balancing arrangements are not included in estimated future proceeds. As of December 31, 2000, the quantity of gas sold by third parties under the gas balancing arrangements was approximately .2 Bcf. Proceeds related to the underproduction position could result in additional proceeds to the Trust or reduce the cost-carryforward in future periods, however, the amount and timing of such proceeds are uncertain. In addition, other factors, including the credit worthiness of the counterparties should be considered in determining the probability and amount of future proceeds. The Ryder Scott estimates did not include proceeds that may be received with respect to the gas balance arrangements.
- The Working Interest Owner has brought suit against a prior gas purchaser, seeking reimbursement of excess royalty of a portion of amounts paid to the Minerals Management Service. A successful outcome for the Working Interest Owner could result in additional proceeds to the Trust or reduce the cost-carryforward. However, the suit is in the early stages, and no trial date has been set. The amount of any recovery is presently indeterminable. The Ryder Scott estimates did not include proceeds, if any, from this lawsuit.
- The reserve for future abandonment costs for the Trust's properties totals $4.2 million. This amount is included in the cost carryforward of $19.8 million, as of December 31, 2000. Such costs are by their nature imprecise and can be expected to be revised over time due to changes in general and specific cost levels, government regulation, operations or technology. The Ryder Scott estimates did not take into account any changes in such costs.
- In December 1997, the Working Interest Owner entered into a crude oil agreement with an oil pipeline company which included an annual minimum delivery volume. Since the agreement's inception, the Trust has been assessed a deficiency payment ranging from $.5 million to $.7 million on an annual basis. There are no assurances that the annual minimum delivery volume will be met in the future. For further information on this matter see under Ryder Scott report.
Accordingly, the estimated discounted net present value of future net revenues should not be construed as the current market value of the estimated oil and gas reserves, since a market value determination would include these and other additional factors. The Ryder Scott report is included elsewhere in this report and includes additional information regarding the estimates.
DESCRIPTION OF THE TRUST
Units of beneficial interest (the Units) in the Trust are traded on the over the counter market under the trading symbol "FMOLS."
The Units are not an interest in or an obligation of the Working Interest Owner, IMC. The Units represent indirect interests in the Royalty Properties (as defined below). The following information and the information set forth under "DESCRIPTION OF THE UNITS" are subject to the detailed provisions of the Trust Indenture and the First Amended and Restated Articles of General Partnership of Freeport-McMoRan Oil and Gas Royalty Partnership (the Partnership) entered into between McMoRan Offshore Management Co., formerly an indirect wholly owned subsidiary of FTX, and the Trustee (the Partnership Agreement). The Trust Indenture and the Partnership Agreement are among the exhibits incorporated by reference to this report. The provisions governing the Trust and the Partnership are complex and extensive, and no attempt has been made below to describe all of such provisions. The following is a general description
of the basic framework of the Trust and the Partnership, and reference is made to the Trust Indenture and the Partnership Agreement for detailed provisions concerning the Trust and the Partnership.
CREATION AND TRANSFER OF THE ROYALTY
As described above, on September 30, 1983, pursuant to the terms of the Overriding Royalty Conveyance (the Conveyance), FTX transferred to the Partnership a net overriding royalty interest (the Royalty) in what then represented 18 productive (the Productive Properties) and 12 undeveloped (the Undeveloped Properties) oil and gas leases offshore Louisiana, Texas and California equal to 90 percent of the net proceeds from working interests in such properties. See "THE ROYALTY PROPERTIES AND THE ROYALTY -- Computation of the Royalty." The Productive Properties and the Undeveloped Properties are referred to herein jointly as the "Royalty Properties."
FTX assigned the Royalty to the Partnership in exchange for a 99.9 percent interest therein. Immediately thereafter, FTX assigned its 99.9 percent general partnership interest in the Partnership to the Trust in exchange for the Units. Units were then distributed to FTX's stockholders.
THE PARTNERSHIP
Title to the Royalty is held by the Partnership, a general partnership formed under the laws of the State of Texas and in which the Trustee, for the benefit of the Unit holders, has a 99.9 percent general partnership interest and the Managing General Partner (discussed below) has a 0.1 percent general partnership interest. The Partnership was formed and exists 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 the Managing General Partner in accordance with their interests.
The Managing General Partner of the Partnership is the American Royalty Partnership Management Company (ARPMC), a Colorado corporation which is owned by the Greater New Orleans Foundation, a Louisiana nonprofit corporation. IMC provides the staff and facilities to carry out the administrative duties for and on behalf of ARPMC, and IMC has indemnified the Partnership for the obligations of ARPMC in connection with its duties and responsibilities as Managing General Partner.
THE TRUST
Under the Trust Indenture, the Trustee holds an interest in the Partnership for the benefit of the Unit holders. The terms of the Trust Indenture provide, among other things, that (1) the Trustee cannot engage in any business or investment activity and cannot acquire any asset other than its interest in the Partnership and cash being held for payment of liabilities or distribution to Unit holders; (2) the Royalty can be sold in whole or in part upon approval of the Unit holders or upon termination of the Trust; and (3) any cash distributions to the Unit holders are made by the Trustee quarterly in January, April, July and October of each year. The Trust has not made any cash distributions since 1995.
The Trust Indenture provides that Unit holders take their Units subject to the provisions of the Trust Indenture, which gives the Trustee only such rights and powers as are necessary and proper for the conservation and protection of the Royalty. Accordingly, the Trustee has no responsibility or authority with respect to the operation of the Royalty Properties. The Trust is a passive trust, and the Trust Indenture requires the Trustee (a) to receive all income and proceeds of the Royalty net of other Partnership expenses and net of amounts attributable to the Managing General Partner's 0.1 percent interest in the Partnership, (b) to pay or provide for the payment of expenses, charges, liabilities and obligations of the Trust and (c) to distribute to Unit holders the remaining revenues attributable to the Royalty.
The Trust has no employees. Administrative functions of the Trust are performed by the Trustee, which is compensated for its services and reimbursed for specified charges for transfer agency and distribution functions out of Trust assets. The Trustee is also entitled to reimbursement for its out-of-pocket expenses. Because of the passive nature of the Trust assets and the restrictions on the power of the Trustee to incur obligations, the only liabilities which the Trustee ordinarily incurs are those for routine administrative
expenses, such as Trustee's fees and accounting, legal and other administrative fees. The costs and expenses of the Trust (including the Trustee's fees) are estimated to approximate $600,000 for 2001. The Trustee, in accordance with the Trust Indenture, established an expense reserve to cover Trust expenses as discussed in Note 6 -- Establishment of an Expense Reserve, of which $615,459 remained as of December 31, 2000. The costs and expenses of the Trust may vary in future years, depending on the volume of trading in the Units, the amount of revenues to the Trust and increases in accounting, legal and other administrative fees.
DUTIES AND LIMITED POWERS OF THE TRUSTEE
Under the Trust Indenture, the Trustee receives the Trust's share of any distributions from the Partnership and pays all expenses, charges, liabilities and obligations of the Trust. With respect to any liability which is contingent or uncertain in amount or which otherwise is not currently due and payable, the Trustee has the discretion to establish a cash reserve for the payment of such liability. If at any time the cash on hand and to be received by the Trustee is not, in its judgment, sufficient to pay liabilities of the Trust as they become due, the Trustee is authorized to borrow the funds required to pay such liabilities, in which event no further distributions will be made to Unit holders until such borrowing has been repaid. The Trustee is permitted to borrow such funds from any bank, including itself. To secure payment of any such indebtedness, the Trustee is authorized to mortgage, pledge, grant security interests in or otherwise encumber assets of the Trust, or any portion thereof, to cause the Partnership to mortgage, pledge, grant security interests in or otherwise encumber the Royalty, and to cause the Partnership to carve out and convey production payments. After payment of or provision for Trust expenses and obligations, the Trustee makes quarterly distributions to the Unit holders of all the proceeds received from the Partnership in respect of the Royalty and not theretofore distributed. The Trustee submits periodic financial reports to the Unit holders as described under "DESCRIPTION OF THE UNITS -- Periodic Reports."
The Trust Indenture authorizes the Trustee to take such action as in its judgment is necessary or advisable to achieve the purposes of the Trust. The Trust Indenture provides that cash being held by the Trustee as a reserve for liabilities or for distribution at the next distribution date will be placed in interest-bearing accounts or certificates (which may include accounts or certificates of the bank acting as Trustee), but the Trustee is otherwise prohibited from acquiring any asset other than the Trust's interest in the Partnership or engaging in any business or investment activity of any kind whatsoever. The Trustee may sell or dispose of its interest in the Partnership, or permit the Partnership to sell or dispose of all or any part of the Royalty, only as authorized by a vote of the Unit holders upon termination of the Trust and in certain other limited circumstances. However, the Trust Indenture states that the Trustee must effect such a sale (without any such vote) because the Trust has had no cash receipts from the Royalty for each of the past five years. Depending on the outcome of the Unit holders' meeting described above and under "Business -- Background," the Trust assets will be sold in some manner in the near future.
The Trustee is also authorized to agree to modifications of the terms of the Partnership Agreement or to cause the Partnership to agree to modifications of the terms of the Conveyance or to settle disputes with respect thereto, so long as such modifications or settlements do not (i) alter the nature of the Royalty as a right to receive a share of the proceeds of minerals produced from the Royalty Properties, free of any expense or other cost and without any operating rights, or (ii) alter the Partnership Agreement so as to change the purposes or scope of activities of the Partnership. Furthermore, the Trustee may not agree to any distribution from the Partnership of the Royalty, or any other asset of the Partnership, which would cause the interest of the holders of Units to be treated as other than an intangible personal property interest.
LIABILITIES OF THE TRUSTEE
The Trustee may act in its discretion and will be personally or individually liable only for fraud, gross negligence or bad faith. The Trustee will be indemnified from the Trust assets for any liability, expense, claim, damage or other loss incurred in performing its duties, unless resulting from fraud, gross negligence or bad faith, and will have a lien upon the assets of the Trust as security for such indemnification and for
reimbursements and compensation to which it is entitled. The Trustee will not be entitled to indemnification from Unit holders.
TERMINATION OF THE TRUST
The conditions precedent to termination of the Trust have occurred and absence further changes to the Trust Indenture approved by the Unit holders, in accordance with the terms of the Trust Indenture, and as may be approved by the Trustee in its discretion, the Trustee will sell the assets of the Trust and distribute any proceeds to the Unit holders.
DESCRIPTION OF THE UNITS
GENERAL
Each Unit is evidenced by a transferable certificate. Each Unit evidences an undivided interest in the Trust, which in turn owns a 99.9 percent interest in the Partnership. As of December 31, 2000, a total of 14,975,390 Units are outstanding.
DISTRIBUTIONS AND INCOME COMPUTATIONS
Each month the Trustee is required to determine the amount, if any, 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, subject to adjustments 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, if any, for each month is payable to Unit holders of record on 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 Trustee does not distribute cash monthly, but rather, during January, April, July and October of each year if amounts are available for distribution. The Trustee is required to distribute to each person who was a Unit holder of record on a Monthly Record Date during one or more of the immediately preceding three months, any Monthly Distribution Amount for the month or months that he was a Unit holder of record, together with interest earned on such Monthly Distribution Amount from the Monthly Record Date to the payment date.
Because the Trust is classified for tax purposes as a "grantor trust" and the Partnership is classified for tax purposes as a partnership (see "FEDERAL INCOME TAX CONSIDERATIONS") and is required to use the accrual method of accounting, any net taxable income from the Royalty (other than interest earned on Monthly Distribution Amounts) will be realized by the Unit holders for tax purposes in the month accrued by the Partnership, rather than in the month distributed by the Trust. Thus, a Unit holder may be required to report income attributable to his Units without receiving distributions directly corresponding to such income.
NATURE OF THE UNITS
The Units are not an interest in or obligation of the Company, the Working Interest Owner or any successor Working Interest Owner. However, the ultimate value of the Royalty is dependent to a large extent upon the ability of the Working Interest Owner to produce oil and gas from the Royalty Properties. There is no requirement that the Working Interest Owner expend any specific amounts with respect to the Royalty Properties, and the Working Interest Owner is entitled to go, and in the past has gone, "non-consent" with respect to operations, in which case its participation will be significantly reduced. See "Operating Agreements." The Working Interest Owner is free to transfer the working interests (burdened by the Royalty) to third parties such as NewCo. In certain cases the Working Interest Owner is permitted to farm out interests in the Royalty Properties and to reduce the Royalty proportionately. See "THE ROYALTY PROPERTIES AND THE ROYALTY -- General and -- Production and Drilling Activities." The Working Interest Owner
does not have an obligation to produce any specific amounts of oil and gas from any of the Royalty Properties. It has the right to abandon any well or lease, and upon termination of any lease the portion of the Royalty relating thereto will be extinguished. The amount of revenues attributable to the Royalty may be affected by operating agreements and unitization and pooling arrangements. The realization of the ultimate value of the Royalty is subject to all the risks associated with exploration on and development of oil and gas properties and to comprehensive regulation by governmental authorities.
TRANSFER OF THE UNITS
Units are transferable on the records of the Trustee or transfer agent upon the surrender of any certificate representing Units in proper form for transfer as required by the Trustee. No service charge is made to the transferor or transferee for any transfer of a Unit, but the Trustee may require payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in connection with such transfer.
PERIODIC REPORTS
As promptly as practicable following the end of each quarter, the Trustee is required to mail to each person who was a Unit holder of record on the Monthly Record Date for any month during such quarter a report which shows in reasonable detail the assets and liabilities and receipts and disbursements of the Trust for such quarter and for each month in such quarter. As promptly as practicable following the end of each fiscal year, the Trustee is required to mail to Unit holders of record as of a date to be selected by the Trustee an annual report containing audited financial statements of the Trust.
The Trustee is required to file such returns for federal income tax purposes as in its judgment are required to comply with applicable law and to permit each Unit holder to report correctly his share of the income and deductions of the Trust. The Trustee will treat all income and deductions recognized during each month as reportable by Unit holders of record on the Monthly Record Date of such month unless otherwise advised by counsel or the Internal Revenue Service.
The Conveyance provides that the Working Interest Owner maintain books and records sufficient to determine the amounts payable to the owner of the Royalty. On the eleventh day prior to the last business day of each month the Working Interest Owner is required to provide the Partnership with information regarding the amount of the Royalty payment to be made on the next Monthly Record Date. The Working Interest Owner is also required to provide material information regarding the Royalty Properties.
The Trustee has no duty to secure, file or disseminate information to which it is not expressly afforded access under the terms of the instruments creating the Trust or which it is unable to obtain without unreasonable effort and expense.
LIABILITY OF OWNERS OF UNITS
Regarding the Unit holders, the Trust Indenture provides that the Trustee will be fully liable if the Trustee incurs any liability, except with respect to the income tax and oil and gas pricing matters described in the next paragraph, without taking reasonable steps to ensure 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, Unit holders. However, under the laws of Texas (and perhaps California, if applicable), it is unclear whether a Unit holder would be jointly and severally liable for any liability of the Trust in the event that both of the following conditions were to occur: (a) the satisfaction of such liability was not by contract limited to the assets of the Trust, and (b) the assets of the Trust were insufficient to discharge such liability. Each Unit holder should weigh this potential exposure in deciding whether to retain or transfer his Units. In that connection, Unit holders should consider the passive nature of the Trust assets and the restrictions on the power of the Trustee to incur liabilities.
The Trust Indenture provides that the Trustee will not be liable to Unit holders for state or federal income taxes or for refunds, fines, penalties or interest relating to oil or gas pricing overcharges under state or federal price controls. With respect to gas pricing matters, the Federal Energy Regulatory Commission
(FERC) is not considered to be empowered under current judicial decisions to compel refunds of gas price overcharges from overriding royalty interest owners. It is possible, however, that laws on such matters may change in the future or that other parties, such as oil or gas purchasers, might be able to instigate legal action to compel such refunds from royalty owners and that Unit holders might be treated for such purpose as royalty owners.
STATE LAW CONSIDERATIONS
It is anticipated, based on the structure of the Trust and the Partnership, that the Units will be treated for certain state law purposes essentially the same as other securities, that is, as interests in intangible personal property rather than as interests in real property. However, in the absence of controlling legal precedent there is a possibility that under certain circumstances a Unit holder could be treated as owning an interest in real property. In that event, the tax, probate, devolution of title and administration laws of Texas, or Louisiana applicable to real property may apply to the Units, even if held by a person who is not a resident or domiciliary thereof. Application of such laws could make inheritance and related matters with respect to the Units substantially more onerous than had the Units been treated as interests in intangible personal property. In any event, however, the ownership of Units and realization of income from the Royalty by a Unit holder may subject such Unit holder to state or local income or other taxation in the state of the Unit holder's residence or domicile. Unit holders should consult their legal and tax advisors regarding the applicability of these considerations to their individual circumstances.
POSSIBLE REQUIREMENT THAT UNITS BE DIVESTED
Although the Trust Indenture imposes no restrictions based on nationality or other status of the persons or other entities who are eligible to hold Units, it does provide that if at any time the Trust or Trustee is named as a party in any judicial or other proceeding which seeks the cancellation or forfeiture of the Trust's interest in any of the Royalty Properties because of the nationality or other status of any one or more Unit holders, such Unit holders may be required to sell their Units according to procedures set forth in the Trust Indenture.
THE ROYALTY PROPERTIES AND THE ROYALTY
EXPLANATORY NOTE
The Trustee has no responsibility relating to the operations of the Royalty Properties. The information in this report, relating to the characteristics of and operations on the Royalty Properties and certain other matters, has been furnished to the Trustee by the Working Interest Owner.
The information in this report regarding the Royalty Properties should be read in light of the following: The Royalty was carved out of working interests owned by FTX at the time of creation of the Trust. References in this report to "net" wells and acres refer to the sum of the fractional working interests owned by the Working Interest Owner (from which the Royalty was carved) in the "gross" wells or acres. References to the percentage of the working interest owned by the Working Interest Owner are references to the working interest out of which the Royalty was carved. For example, a reference to a "50 percent working interest" in a well or lease which is included in a Royalty Property indicates that the Partnership's net overriding royalty interest (equal to 90 percent of the Net Proceeds, as defined, from all the Royalty Properties) burdens half of the total working interest in the well or lease. Such 50 percent working interest will also be subject to landowners' royalties and may be subject to other overriding royalty interests and other burdens which are considered prior to calculations of amounts payable to the owner of the Royalty. Since the amounts and nature of such burdens vary from lease to lease, the information presented herein and elsewhere regarding the Working Interest Owner's percentage of the working interest in any well or lease cannot be used to calculate precisely the interest attributable to the Trust in a well or lease. In addition, (i) because operating and capital costs are taken into consideration in calculating the amounts payable to the owner of the Royalty and because prices for oil and gas may vary from field to field, information regarding results of well tests of gross quantities of production from a given well cannot be used to compute the interest attributable to the Trust, and
(ii) because the Royalty Properties consist of multiple leases in multiple fields, the interest of the Working Interest Owner in any given well or lease may not be indicative of the interest attributable to the Trust in the Royalty Properties.
GENERAL
As of December 31, 2000, there were 14 gross productive oil wells and 14 gross productive gas wells on the 3 remaining Royalty Properties where the Working Interest Owner retains a working interest.
All Royalty Properties are operated under joint operating agreements by other oil and gas companies other than the Working Interest Owner. Neither the Working Interest Owner nor any operator has any contractual commitments to the Partnership or the Trust to conduct further exploratory or development drilling on the Royalty Properties or to maintain its ownership interest in any of the properties. See "Certain Factors Affecting Distributions; Conflicts of Interest." However, any operator of a Royalty Property has an obligation to operate and develop such property in accordance with the standards of a reasonable and prudent operator. The Working Interest Owner retains a revenue interest in the remaining Royalty Properties and it has informed the Trustee that it is reviewing all options relating to its ownership interest in the remaining properties, including discussions with several Unit holders. See "Production and Drilling Activities" below for a discussion of current development and exploratory activities on certain of the Royalty Properties.
RESERVES
A study of the proved oil and gas reserves attributable to the Royalty Properties as of December 31, 2000, has been made by Ryder Scott Company L.P., independent petroleum engineers (Ryder Scott). In accordance with regulations of the Securities and Exchange Commission (the SEC), such study is limited to reserves currently classified as "proved." The amount of reserves and the timing of production attributable to the Royalty Properties are, and in the future will continue to be, significantly affected by the level of capital expenditures to be incurred on the individual properties and the success of exploration and development activities. The assumptions used in preparing the reserve study are detailed within the following letter, which summarizes such reserve study. Such assumptions, as well as the cautionary paragraphs following the letter, should be studied carefully together with the estimates contained in the letter. Ryder Scott also prepared estimates of future net cash flows attributable to the Royalty from proved oil and gas reserves and the discounted present value of such future net cash flows. The estimates of Ryder Scott are used in the preparation of the Trust's financial statements and for other reporting purposes. However, as explained in the cautionary paragraphs immediately following the letter, Ryder Scott's estimates were prepared based on production and costs as of December 31, 2000, but the timing of inclusion of production and costs for purposes of calculating Royalty payments during a given period varies somewhat from the method used by Ryder Scott in preparing its estimates. For example, the estimates do not take into account amounts received in 2000 attributable to sales of oil and gas produced in the fourth quarter of 2000, volumes of natural gas sold by other parties pursuant to certain gas balancing arrangements and the effect of the excess cost carry-forward at December 31, 2000. Therefore, the amounts set forth in the letter are not indicative of actual amounts to be distributed to Unit holders, either annually or ultimately.
The estimates of future net cash flows and discounted present value of future net cash flows were prepared using prices and costs as of December 31, 2000. Proved reserves are estimated quantities of oil and gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (see Note 10 -- Supplementary Proved Oil and Gas Reserve Information).
[RYDER SCOTT COMPANY PETROLEUM CONSULTANTS LETTERHEAD]
March 27, 2001
Freeport-McMoRan Oil and Gas Royalty Trust c/o Chase Bank of Texas, National Association (Trustee) 600 Travis Street, Suite 1150 Houston, Texas 77002
Gentlemen:
At the request of IMC Global Inc. (IMC), successor to Freeport-McMoRan Inc. (FTX), we have prepared estimates of the proved reserves and future production and income attributable to a net overriding royalty interest in certain offshore leases as of December 31, 2000. The future income has been calculated using Securities and Exchange Commission (SEC) guidelines for price and cost parameters.
The net overriding royalty interest is equal to a 90 percent net profits interest in leases owned by a subsidiary of FTX on September 30, 1983. The leases are located in the Gulf of Mexico offshore of Louisiana and Texas. This net overriding royalty interest (Royalty) is the property that FTX originally transferred to Freeport-McMoRan Oil and Gas Royalty Partnership (Partnership), a partnership which is owned 99.9 percent by Freeport-McMoRan Oil and Gas Royalty Trust. The term "Working Interest Owner" includes IMC and the successors and assigns of its oil and gas working interests to the extent the context requires.
All offshore leases currently subject to the Royalty have been considered in this report, and the impact of these leases' reserves, revenues, expenses, and expense accruals on the income of the Partnership has been determined. These leases are hereinafter referred to as the "Subject Properties." All other leases originally subject to the Royalty have either expired, or the leasehold interest subject to the Royalty has been sold. The Working Interest Owner has assured us that no leases other than those included in our evaluation have a material effect on the overall revenues or liabilities of the Partnership.
The estimated reserve quantities and future income quantities presented in this report are related to hydrocarbon prices. December 2000 hydrocarbon prices were used in the preparation of this report as required by SEC guidelines; however, actual future prices may vary significantly from December 2000 prices. Therefore, volumes of reserves actually recovered and amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized as follows:
Freeport-McMoRan Oil and Gas Royalty Trust March 27, 2001 SEC PARAMETERS Estimated Net Reserve and Income Data Freeport-McMoRan Oil and Gas Royalty Partnership As of December 31, 2000
The amounts shown above are all attributable to proved developed reserves.
Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are sales gas expressed in millions of cubic feet (MMCF) at 60 degrees Fahrenheit and 14.73 pounds per square inch absolute.
The reserve volumes and income values shown above for the properties transferred to the Partnership were estimated from projections of reserves and income attributable to the combined interests consisting of the Royalty and the interest of the Working Interest Owner in the Subject Properties. Interests related to non-consent operations and interests acquired subsequent to the conveyance of the Royalty to the Partnership are excluded from the calculation of Partnership income.
The future net income attributable to the Royalty was estimated on a yearly basis from a projection of the combined Working Interest Owner and Partnership future net income. Combined future net income values were calculated by deducting operating expenses and capital costs from the future gross revenue of the combined interests. Only those expenses and capital costs necessary for the development and production of proved reserves were taken into consideration. A portion of the expenses at West Cameron Block 498 Field are associated with oil transportation tariffs. The tariffs included in the expenses amount to a total of $1,167,458 net to the combined interests of the Working Interest Owner and Partnership for the oil produced from the West Cameron Block 498 Field. In that regard, annual deductions were made to represent future deficiency payments for which the Working Interest Owner or the Partnership may be liable in accordance with Exhibit A of the Crude Oil Buy/Sell Agreement between Coastal States Trading, Inc. and the Working Interest Owner for oil produced from the West Cameron Block 498 field.
The annual income values for each property were further reduced by an overhead charge furnished by the Working Interest Owner. The adjusted annual income resulting from subtracting the overhead charge was multiplied by a factor of 90 percent to arrive at the annual future net income of the Partnership.
More than a sufficient amount has been accrued as of December 31, 2000 to pay for the unescalated estimated abandonment costs attributable to the Royalty; therefore, using SEC pricing and cost parameters, it is anticipated that no future accruals will be necessary. Furthermore, a reimbursement is included as Partnership income in the year after depletion and abandonment of the Subject Properties. This reimburse-
Freeport-McMoRan Oil and Gas Royalty Trust March 27, 2001 ment is equal to the amount by which current unspent accruals exceed anticipated unescalated future abandonment costs.
The future net income calculated for the Partnership is before the deduction of state and federal income taxes and does not include any adjustment for cash on hand or undistributed income. No attempt has been made to quantify or otherwise account for any accumulated gas imbalances that may exist. In accordance with Securities and Exchange Commission regulations, discounted future net income values shown above were calculated by discounting the future net income at the rate of 10 percent per year; however, such rate is not necessarily the most appropriate discount rate. At the request of the Working Interest Owner, annual compounding was used in the computation of discounted future net income. Discounted future net income should not be construed as Ryder Scott Company's estimate of fair market value since no consideration was given to the additional factors that influence the prices at which oil and gas properties are bought and sold, such as taxes on income, allowance for return on investments and business risks.
It should be noted that, although the Partnership will not be directly subject to the aforementioned deductions (operating costs, transportation tariffs, capital costs, and overhead charges), these deductions will affect the future net income of the Partnership as described above. Therefore, the estimated net income attributable to the Partnership will change if actual costs differ from those used in our estimates.
Estimates of reserves attributable to the Partnership are shown above as required by the Securities and Exchange Commission; however, there is no precise method of allocating estimates of physical quantities of reserves between the Working Interest Owner and the Partnership, since the Royalty is a net profits interest, and the Partnership does not own, and is not entitled to receive, any specific volume of reserves. Net reserves attributable to the Royalty were estimated by allocating to the Partnership a portion of the estimated combined net reserves of the Subject Properties using a formula based on future income. The quantities of reserves indicated by such formula will be affected by future changes in various economic factors utilized in estimating future gross revenues and net income from the Subject Properties. Therefore, the estimates of reserves set forth above are to a large extent hypothetical and are not comparable to estimates of reserves attributable to a working interest. At the request of the Working Interest Owner, the following formula was used on a yearly basis to estimate the required net reserves attributable to the Royalty of each property:
The price per unit of reserves was calculated by dividing combined future gross revenues by combined net reserves.
RESERVES INCLUDED IN THIS REPORT
The proved reserves presented in this report comply with SEC definitions and guidelines, as outlined below. SEC Regulation S-X Rule 4-10 paragraph (a) defines proved reserves as follows:
PROVED OIL AND GAS RESERVES. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes:
Freeport-McMoRan Oil and Gas Royalty Trust March 27, 2001 (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and
(B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.
(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the "proved" classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.
(iii) Estimates of proved reserves do not include the following:
(A) oil that may become available from known reservoirs but is classified separately as "indicated additional reserves";
(B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;
(C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and
(D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.
PROVED DEVELOPED OIL AND GAS RESERVES. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
PROVED UNDEVELOPED RESERVES. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
Certain Staff Accounting Bulletins published subsequent to the promulgation of Regulation S-X have dealt with matters relating to the application of financial accounting and disclosure rules for oil and gas producing activities. In particular, the following interpretations extracted from Staff Accounting Bulletins set forth the Commission staff's view on specific questions pertaining to proved oil and gas reserves.
Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years under existing economic and operating conditions. The relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a
Freeport-McMoRan Oil and Gas Royalty Trust March 27, 2001 combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. (extracted from SAB-35)
In determining whether "proved undeveloped reserves" encompass acreage on which fluid injection (or other improved recovery technique) is contemplated, is it appropriate to distinguish between (i) fluid injection used for pressure maintenance during the early life of a field and (ii) fluid injection used to effect secondary recovery when a field is in the late stages of depletion? ... The Office of Engineering believes that the distinction identified in the above question may be appropriate in a few limited circumstances, such as in the case of certain fields in the North Sea. The staff will review estimates of proved reserves attributable to fluid injection in the light of the strength of the evidence presented by the registrant in support of a contention that enhanced recovery will be achieved. (extracted from SAB-35)
Companies should report reserves of natural gas liquids which are net to their leasehold interest, i.e., that portion recovered in a processing plant and allocated to the leasehold interest. It may be appropriate in the case of natural gas liquids not clearly attributable to leasehold interests ownership to follow instruction (b) of Item 2(b)(3) of Regulation S-K and report such reserves separately and describe the nature of the ownership. (extracted from SAB-35)
The staff believes that since coalbed methane gas can be recovered from coal in its natural and original location, it should be included in proved reserves, provided that it complies in all other respects with the definition of proved oil and gas reserves as specified in Rule 4-10(a)(2) including the requirement that methane production be economical at current prices, costs, (net of the tax credit) and existing operating conditions. (extracted from SAB-85)
ESTIMATES OF RESERVES
In general, the reserves included herein were estimated by performance methods or the volumetric method; however, other methods were used in certain cases where characteristics of the data indicated such other methods were more appropriate in our opinion. The reserves estimated by the performance method utilized extrapolations of various historical data in those cases where such data were definitive in our opinion. Reserves were estimated by the volumetric method in those cases where there were inadequate historical performance data to establish a definitive trend or where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.
The reserves included in this report are estimates only and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, the revenues therefrom and the actual costs related thereto could be more or less than the estimated amounts. Moreover, estimates of reserves may increase or decrease as a result of future operations.
FUTURE PRODUCTION RATES
Initial production rates are based on the current producing rates for those wells now on production. Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations which are not currently producing. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by the Working Interest Owner.
Freeport-McMoRan Oil and Gas Royalty Trust March 27, 2001 The future production rates from wells now on production may be more or less than estimated because of changes in market demand or allowables set by regulatory bodies. Wells or locations which are not currently producing may start producing earlier or later than anticipated in our estimates of their future production rates.
HYDROCARBON PRICES
The Working Interest Owner furnished us with prices in effect at December 31, 2000 and these prices were held constant except for known and determinable escalations. In accordance with Securities and Exchange Commission guidelines, changes in liquid and gas prices subsequent to December 31, 2000 were not taken into account in this report.
OIL AND CONDENSATE
The Working Interest Owner furnished us with initial oil and condensate prices for the properties in this report. These initial liquid prices were based on actual prices received in December 2000, and were held constant throughout the depletion of the reserves. In accordance with Securities and Exchange Commission guidelines, changes in liquid prices subsequent to December 31, 20000 were not considered in this study.
GAS
The Working Interest Owner has furnished us with gas prices in effect at December 2000 and with its forecasts of future gas prices which take into account SEC guidelines and current market prices. In accordance with SEC guidelines, the future gas prices used in this report make no allowance for future gas price increases which may occur as a result of inflation nor do they allow any allowance for seasonal variations in gas prices.
COSTS
The current operating, development, abandonment, and overhead costs were held constant throughout the life of the properties. The estimated net cost of abandonment after salvage was used in our estimates of future revenue from the Subject Properties since these costs are relatively large in offshore areas. The estimates of the net abandonment costs for the Subject Properties were furnished by the Working Interest Owner and were accepted without independent verification.
All costs used in this study were furnished by the Working Interest Owner. The operating costs are based on the operating expense reports of the Working Interest Owner, or on operating expense estimates furnished by the Working Interest Owner for properties not yet on production. The development and abandonment costs are based on authorizations for expenditure for the proposed work, or on actual costs for similar projects.
When applicable, the operating costs attributable to the Working Interest Owner and the Partnership include a portion of general and administrative costs allocated directly to the leases and wells under operating agreements. No deduction was made for indirect costs such as loan repayments, deficiency payments related to transportation agreements, interest expenses, and exploration and development prepayments that are not charged directly to the leases or wells.
GENERAL
Tables 1 through 4 present summaries of estimated annual production and income beginning January 1, 2001 for the total Partnership. Tables 5 through 12 present our annual projection of production and income for each individual field.
Freeport-McMoRan Oil and Gas Royalty Trust March 27, 2001 The reserve estimates presented herein are based upon a detailed study of the Subject Properties; however, Ryder Scott has not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities which may exist nor were any costs included for potential liability to restore and clean up damages, if any, caused by past operating practices. The Working Interest Owner has represented that it has given Ryder Scott access to its accounts, records, geological and engineering data and reports and other data as were required for this investigation. The ownership interests, prices, and other factual data furnished to Ryder Scott by the Working Interest Owner in connection with this investigation were accepted without verification. The estimates presented in this report are based on such furnished data available through December 2000.
The future prices received for the sale of production may be higher or lower than the prices used in this report as described above, and the operating costs and other costs related to such production may also increase or decrease from existing levels; however, such possible changes in prices and costs were, in accordance with rules adopted by the Securities and Exchange Commission, omitted from consideration in preparing our report.
Neither Ryder Scott Company nor any of its employees has any interest in the Subject Properties and neither the employment to make this study nor the compensation is contingent on our estimates of reserves and future income for the Subject Properties.
Very truly yours,
RYDER SCOTT COMPANY, L.P.
/s/ FREDERICK W. EMMERICH ------------------------------------ Frederick W. Emmerich Petroleum Engineer FWE/sw
Approved:
/s/ JOHN R. WARNER - ------------------------------------ John R. Warner, P.E. Senior Vice President
FREEPORT-MCMORAN OIL AND GAS ROYALTY PARTNERSHIP
Estimated Future Reserves and Income Attributable to a Net Overriding Royalty Interest In Certain Offshore Leases
(SEC Case)
As of December 31, 2000
All of the discounted present value of future net cash flows attributable to the Royalty estimated by Ryder Scott was accounted for by West Cameron Block 498 and by West Delta 34.
Because the Royalty is a "net" overriding interest (often referred to as a net profits interest), estimates of future net cash flows to the Trust are affected by a number of factors in addition to the engineering, well performance and other data taken into consideration by petroleum engineers in estimating the quantity and nature of gross oil and gas reserves in the ground. Such other factors include projections of operating and capital costs, oil and gas prices and the Working Interest Owner's evaluation of the economic feasibility of conducting additional operations. In addition, because oil and gas reserve quantities are calculated pursuant to the formula described in Ryder Scott's letter, these other factors will affect the quantities shown as estimated oil and gas reserves attributable to the Trust.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures. The preceding reserve data represent estimates only. Oil and gas reserve engineering must be recognized as a subjective process which involves, among other things, estimating underground accumulations of oil and gas that cannot be measured in an exact way, and estimates of other engineers might differ materially from those of Ryder Scott. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are inherently different from the quantities of oil and gas that are ultimately recovered.
Moreover, the discounted present values shown above should not be construed as the current market value of the estimated oil and gas reserves attributable to the Royalty. In accordance with applicable requirements of the SEC, future net cash flows were based, generally, on current prices and costs, whereas actual future prices or costs may be materially greater or less. Actual future net cash flows will also be affected by subsequent reserve revisions, supply and demand for oil and gas, curtailments by gas purchasers and changes in governmental regulations or taxation. Also, the 10 percent discount factor used to calculate present value, as required by the SEC, is not necessarily the most appropriate risk-adjusted rate of return, and present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to have been inaccurate.
The timing of realization of future net cash flows estimated in the above report is based on estimates of the future timing of actual production and sales of quantities of oil and gas. Because of payment practices followed in the oil and gas industry, there is a one or two month lag between the month in which a quantity of oil or gas is actually produced and the month in which revenue attributable to such production is actually received by the Working Interest Owner. The payment procedures in the Conveyance provide that amounts received by the Working Interest Owner in any given month are included in Gross Proceeds (as defined in the Conveyance) for purposes of computation of amounts payable on the last business day of the following month. See "Computation of the Royalty." Thereafter, distributions are made to Unit holders in accordance with the quarterly distribution procedures set forth in the Trust Indenture and described elsewhere herein. Furthermore, as described under "Computation of the Royalty" below, although revenues are reflected only after they are actually received, Costs (as defined in the Conveyance) accrued in a given month are taken into consideration in computing the amount of the Royalty payable on the last business day of the month following the month in which the Costs are incurred, even if they are not actually paid until later. Thus, for example, amounts payable on the last business day in January are computed based on Gross Proceeds received and Costs accrued during December. Generally, such Costs would include any excess of Costs over Gross Proceeds carried forward from the previous month, together with interest on such excess.
The Ryder Scott estimates were prepared on the basis of estimated production and Costs accrued through December 31, 2000. Thus, amounts received by the Working Interest Owner after November 30, 2000 attributable to production during 2000 have not been taken into account by Ryder Scott in making its estimates, even though these amounts will be included in Gross Proceeds for purposes of calculating amounts payable pursuant to the Royalty subsequent to 2000. The Working Interest Owner has estimated that if Ryder Scott had taken into account the 2001 Gross Proceeds from 2000 production, the total estimated future net
cash flow and the discounted present value of such estimate in the Ryder Scott letter would have been approximately $1.5 million higher (net to the Trust's interest). In addition, because Ryder Scott's estimates for the remaining period are based on estimated production and Costs accrued during each such period and because actual Gross Proceeds and Costs will not be based on production and Costs during the same period, the estimates for various time periods will not in any event correspond to the amount of payments pursuant to the Royalty during such periods.
Ryder Scott gave no effect in its estimates to amounts to which the Working Interest Owner is entitled as a result of gas imbalances for certain production (see Note 4 -- Gas Balancing Arrangements and Note 10 -- Supplementary Proved Oil and Gas Reserve Information). Pursuant to the Conveyance, proceeds from gas produced from the Royalty Properties but sold by other parties pursuant to gas balancing arrangements between the Working Interest Owner and others (underproduction) are not included in Gross Proceeds for purposes of calculating the Royalty. In the future the Working Interest Owner will be entitled to sell volumes equal to such underproduction or receive cash settlements. The amounts the Working Interest Owner will receive from the future sale of such underproduction may be more or less than those amounts received by third parties because of price fluctuations.
The estimated future net cash flows shown in Ryder Scott's letter have not been reduced for any capital expenditures on Productive Properties in excess of amounts estimated to be necessary to develop proved reserves attributed thereto. See "Computation of the Royalty" below. Similarly, such future net cash flows have also not been reduced for costs and expenses of the Trust, which are expected to be minimal and are estimated at approximately $.8 million. Additionally, Ryder Scott did not take into account the Cost Carry-Forward of $19.8 million net to the Trust, as of December 31, 2000, nor did it take into account the oil transportation deficiency of $.5 million applicable to 2000 production.
COMPUTATION OF THE ROYALTY
The following information is subject to the detailed provisions of the Conveyance that created the Royalty. The definitions, formulas, accounting procedures and other terms governing the computation of the Royalty are complex and extensive, and no attempt has been made below to describe all of such provisions. The following is a general description of the computation of the Royalty, and reference is made to the Conveyance, which is an exhibit to this report and is available from the Trustee upon request, for detailed provisions concerning such computation.
The Royalty is a property interest which was carved out of working interests in leases or portions thereof owned by the Company immediately prior to the creation of the Royalty. Therefore, the obligation to calculate and pay amounts attributable to the Royalty under the Conveyance is the obligation of the owner of the working interest out of which the Royalty was carved. The Working Interest Owner is free to transfer any portion of its working interest, burdened by the Royalty, and in the case of such transfer, the transferred interest will be treated as a separate property for purposes of computation of amounts payable pursuant to the Royalty. Until such transfer takes place, all of the Royalty Properties will be treated as one property for purposes of computation of amounts payable under the Conveyance.
The Royalty entitles the holder thereof to 90 percent of the Net Proceeds realized from the sale of oil, gas and other hydrocarbons, as, if, and when produced from the working interests subject to the Royalty. Under the Conveyance, "Net Proceeds" generally means the excess of Gross Proceeds received (on a cash basis) during a particular month over Costs incurred (on an accrual basis) during such month. Generally, such Costs include any excess of Costs over Gross Proceeds carried forward from the previous month, together with interest on such excess. This carry-forward amount includes the Cost Carry-Forward, which was $19.8 million to the Trust at December 31, 2000. Amounts equal to 90 percent of the Net Proceeds for any month are payable by the Working Interest Owner to the Partnership on the last business day of the following month.
"Gross Proceeds" means the amount received from sales of hydrocarbons produced from the Royalty Properties that are attributable to the working interests subject to the Royalty, net of lessor royalties and production payments existing at the time of the creation of the Trust which burdened the Royalty Properties prior to the effective date of the Conveyance, and subject to farmouts and certain other adjustments.
"Costs" means, generally, (i) all costs incurred by the Working Interest Owner in producing and operating the Royalty Properties (lease operating expenses), (ii) all capital costs incurred, or projected to be incurred, by the Working Interest Owner in drilling and completing exploratory and development wells and in connection with the installation of platforms, pipelines and other production facilities, (iii) an overhead charge and (iv) amounts recovered by the Working Interest Owner as estimated Abandonment Costs ("Abandonment Costs" means, generally, the future costs to be incurred by the Working Interest Owner to plug and abandon wells and dismantle and remove platforms, pipelines and other production facilities from the Royalty Properties).
The Working Interest Owner is entitled to accrue certain estimated future costs in accordance with a formula set forth in the Conveyance. The accrual formula provides that, for any month and with respect to a specific item of future costs, the Working Interest Owner may include in its costs an amount calculated by multiplying (a) the excess of (i) the total estimated amount of such item of future cost over (ii) the aggregate amount accrued in previous months with respect to such item, by (b) a fraction, the numerator of which is Adjusted Gross Proceeds for such month and the denominator of which is total estimated future Adjusted Gross Proceeds for such month and all future months. For this purpose, "Adjusted Gross Proceeds" means Gross Proceeds for a month less all Class A Costs for such month, such costs that were not covered in the previous month and interest thereon. Class A Costs are all costs that are not Class B Costs. Class B Costs for a month are (a) costs incurred to discover or develop minerals on certain leases, (b) any monthly future cost accruals, (c) such costs that were not covered by proceeds in the previous month and (d) interest thereon.
If Costs exceed Gross Proceeds for any month, the excess will be recovered by the Working Interest Owner, with interest at the prime rate (as defined in the Conveyance), compounded monthly, out of future Gross Proceeds prior to the making of further payments to the Partnership, but the Partnership and the Trustee are not liable for any operating, capital or other costs or liabilities attributable to the Royalty Properties or hydrocarbons produced therefrom. Such recovery will apply to Class B Costs as well. The Partnership and the Trustee are not obligated to return any Royalty income received in any period, but overpayments made by the Working Interest Owner would reduce future amounts payable.
The Working Interest Owner is required to maintain books and records sufficient to determine the amounts payable under the Conveyance. Additionally, in the event of a controversy between the Working Interest Owner and any purchaser as to the correct sales price of any production, amounts received by the Working Interest Owner and promptly deposited by it with an escrow agent shall not be considered as having been received by the Working Interest Owner, and therefore shall not be included as Gross Proceeds, until the controversy is resolved, but all amounts thereafter paid to the Working Interest Owner by the escrow agent shall be considered Gross Proceeds. Similarly, Costs will include any amounts the Working Interest Owner is required to pay as a refund, interest or penalty because the amount received by it as a sales price was in excess of that permitted by the terms of any applicable contract, statute, regulation, order, decree or other obligation. Because the Units are publicly traded, purchasers of Units in the market may, as a result of such procedures, receive distributions of amounts that would have been distributed to former holders if such amounts had not been held in escrow or, conversely, may have their distributions reduced or eliminated as a result of controversies about amounts which may have been collected. Within 30 days following the close of each calendar quarter, the Working Interest Owner is required to deliver to the Partnership a statement of the computation of Net Proceeds attributable to the quarter.
If a default occurs under the Conveyance, the holder of the Royalty may pursue any legal or equitable remedies available to it, including seeking specific performance of any covenant that has been breached. Defaults under the Conveyance include (1) failure on the part of the Company to observe or perform any covenant contained in the Conveyance, which failure materially adversely affects the interests of the holder of the Royalty, and (2) certain events of bankruptcy or insolvency relating to the Working Interest Owner.
CERTAIN FACTORS AFFECTING DISTRIBUTIONS
The amount of cash payable on account of the Royalty, and thus the amount of cash available for distribution to Unit holders, depends upon future sale of oil and gas and the prices received. The sale of crude
oil on West Cameron 498 depends not only on oil prices but also on transportation and operating costs. In December 1997, the Working Interest Owner entered into a crude oil agreement with an oil pipeline company to deliver on a daily basis specified quantities of crude oil from West Cameron 498. Under the terms of the agreement, the Working Interest Owner agreed to pay a transportation fee calculated at a sliding monthly rate based upon the total average daily volumes delivered from West Cameron 498 during the month. Should the annual minimum delivery volume not be met, a deficiency payment is assessed by the pipeline. During 2000, the Working Interest Owner did not deliver the minimum volume under the agreement; therefore, in February 2001, the pipeline company billed the Working Interest Owner approximately $.5 million for the 2000 deficiency. This amount is not included in the Cost Carry-Forward of $19.8 million as of December 31, 2000. Based on 2001 projected production, the minimum delivery volumes will not be met in 2001.
PRODUCTION AND DRILLING ACTIVITIES
There are 3 remaining Royalty Properties, all of which are currently producing. For a discussion concerning the oil and gas production from such properties in 2000 as well as information concerning other activities on such properties during 2000, see Item 7 -- Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 10 -- Supplementary Proved Oil and Gas Reserve Information.
OPERATING AGREEMENTS
All of the remaining Royalty Properties are operated by oil and gas companies that are not affiliated with the Company. Costs attributable to the Royalty Properties generally will be computed based on the costs charged to the Working Interest Owner's account under the terms of existing joint operating agreements.
Besides general provisions for proposing, conducting and sharing costs for joint operations on the Royalty Properties, the existing operating agreements contain provisions which can significantly affect the amount of capital and operating expenditures and vary the receipt of revenues from the sale of production. For example, the "non-consent" provisions of the operating agreements allow other joint interest owners to propose the drilling of wells and thereby require the Working Interest Owner to elect either to pay its share of the cost of drilling such wells or suffer a "non-consent" penalty. The particulars of non-consent penalties on the Royalty Properties vary somewhat between operating agreements, but generally require the forfeiture to the participating parties of a significant interest if the party elects not to participate in the drilling of certain exploratory wells. If a party elects not to participate in a development well on any of the Royalty Properties, that party's right to receive a share of production from such development well is suspended until such time as the participating parties have recovered an amount ranging from approximately 400 percent to approximately 600 percent of the cost of drilling, testing, completing and equipping the development well. The loss of revenues from any failure by the Working Interest Owner to participate in a development well would reduce the aggregate proceeds from the Royalty in the event such development well produced in paying quantities in excess of the cost of drilling, testing, completing and equipping such well. Neither the Partnership nor the Trustee is entitled to compel the Working Interest Owner to participate in any operation on a Royalty Property if the Working Interest Owner makes a "non-consent" election with respect thereto.
The Working Interest Owner may choose to conduct exploration and development operations on one or more of the Royalty Properties without the participation of some, or all, of the other joint interest owners by assuming the obligations of non-consenting parties. If the Working Interest Owner elects to assume a share of the costs associated with any non-consenting party's interest, such costs and the production, if any, attributable to the assumption of such interest will not be taken into account in the computation of the Net Proceeds.
The receipt of revenues from the sale of gas production could be delayed for extended periods of time by gas balancing arrangements which allow other joint interest owners to take gas production in excess of their ownership percentage if the Working Interest Owner is unable to take all or a part of its share of production. On the other hand, if the Working Interest Owner takes gas production in excess of its ownership percentage, the revenues attributable to the excess production will not be included in Gross Proceeds except to the extent such excess is offset by prior or subsequent deficits created after October 1, 1983 by the Working Interest
Owner taking less than its ownership percentage share of gas production. If a source of gas supply depletes before the Working Interest Owner has balanced all deficits created after October 1, 1983 with excess production volumes, the Working Interest Owner will be entitled to receive a cash settlement for such deficits from those joint interest owners with excess production totals. All such settlement receipts will be included in Gross Proceeds. See "Reserves" above.
SALES CONTRACTS AND PRICES
Oil production from the Royalty Properties is sold under short-term contracts at current market prices. Oil prices received by the Working Interest Owner have fluctuated widely. The average oil price that the Working Interest Owner received for crude oil sales during 2000 was 2.2 times higher than the average price received during 1999 and 2.1 times higher than that during 1998. Although current oil prices are up from year end prices, oil prices can be expected to continue to exhibit volatility as a result of such factors as the unstable situation in the Middle East, future actions of OPEC and future changes in worldwide economic conditions.
The Working Interest Owner currently sells gas at spot market prices from blocks that were previously subject to long-term contracts with Transcontinental Gas Pipe Line Corporation, but which contracts were terminated by the Working Interest Owner at the end of 1987 and the beginning of 1988 pursuant to the provisions of such contracts.
In December 1997, the Working Interest Owner entered into a crude oil agreement with an oil pipeline company to deliver on a daily basis specified quantities of crude oil from West Cameron 498. Under the terms of the agreement, the Working Interest Owner agreed to pay a transportation fee calculated at a sliding monthly rate based upon the total average daily volumes delivered from West Cameron 498 during the month. Should the annual minimum delivery volume not be met, a deficiency payment is assessed by the pipeline. During 2000, the Working Interest Owner did not deliver the minimum volume under the agreement; therefore, in February 2001, the pipeline company billed the Working Interest Owner approximately $.5 million for the 2000 deficiency. This amount will be included in the Cost Carry-Forward in 2001. The minimum proved oil reserves to be produced, based on Ryder Scott's reserve evaluation, net to the Working Interest Owner, for 2001 will be $178,081, declining to $74,070 in 2002. Based on 2001 projected production the minimum delivery volumes will not be met in 2001. However should production exceed the 2001 minimum, the Working Interest Owner is entitled to receive transportation without pay up to the cumulative prior undelivered volumes.
REGULATION
The production, sale and transportation of oil and gas from the Royalty Properties are subject to various forms of regulation by federal and state authorities, and are affected from time to time in varying degrees by political developments.
Energy Regulation. Sales of crude oil, condensate and gas liquids are not currently regulated and are made at market prices. Prior to 1993, the sale of certain categories of domestic natural gas by the Working Interest Owner was subject to regulation under the Natural Gas Act of 1938 (NGA) and the Natural Gas Policy Act (NGPA). The Natural Gas Wellhead Decontrol Act of 1989 amended both the price and non-price control provisions of the NGPA for the purpose of providing complete decontrol of first sales of natural gas by January 1, 1993. While sales of the Trust's gas can currently be made at uncontrolled market prices, subject to applicable contract provisions, Congress could reenact price controls in the future.
The Trust's sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation remain subject to extensive federal and state regulation. Several major regulatory changes have been implemented by Congress and the FERC from 1985 to the present that affect the economics of natural gas production, transportation and sales. In addition, the FERC continues to promulgate revisions to various aspects of the rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies, that remain subject to the FERC's jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors
of the natural gas industry and these initiatives generally reflect more light-handed regulation of the natural gas industry. The ultimate impact of the complex rules and regulations issued by the FERC since 1985 cannot be predicted. In addition, many aspects of these regulatory developments have not become final but are still pending judicial and FERC final decisions. The Working Interest Owner cannot predict what action the FERC will take on these matters, nor can it predict whether the FERC's actions will achieve its stated goal of increasing competition in natural gas markets. However, the Working Interest Owner does not believe that it will be treated materially different than other natural gas producers and marketers with which it competes.
Commencing in October 1993, the FERC issued a series of rules (Order Nos. 561 and 561-A) establishing an indexing system under which oil pipelines will be able to change their transportation rates, subject to prescribed ceiling levels. The indexing system, which allows, or may require, pipelines to make rate changes to track changes in the Producer Price Index for Finished Goods, minus one percent, became effective January 1, 1995. The Working Interest Owner is not able at this time to predict the effects of Order Nos. 561 and 561-A, if any, on the transportation costs associated with oil production from the interests burdened by the Royalty, or the effect of such rules on the Trust.
The Outer Continental Shelf Lands Act (OCSLA) requires that all pipelines operating on or across the Outer Continental Shelf (OCS) provide open-access, non-discriminatory service. Although the FERC has opted not to impose the regulations of Order No. 509, which implements the OCSLA, on gatherers and other non-jurisdictional entities, the FERC has retained the authority to exercise jurisdiction over those entities if necessary to permit non-discriminatory access to service on the OCS.
Operations the Working Interest Owner conducts relating to the Royalty Properties are on federal oil and gas leases, which the Minerals Management Service (MMS) administers. The MMS issues such leases through competitive bidding. These leases contain relatively standardized terms and require compliance with detailed MMS regulations and orders pursuant to the OCSLA (which are subject to change by the MMS). For offshore operations, lessees must obtain MMS approval for exploration plans and development and production plans prior to the commencement of such operations. In addition to permits required from other agencies (such as the Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency), lessees must obtain a permit from the MMS prior to the commencement of drilling. The MMS has promulgated regulations requiring offshore production facilities located on the OCS to meet stringent engineering and construction specifications. The MMS also has regulations restricting the flaring or venting of natural gas and has recently proposed to amend such regulations to prohibit the flaring of liquid hydrocarbons and oil without prior authorization. Similarly, the MMS has promulgated other regulations governing the plugging and abandonment of wells located offshore and the removal of all production facilities. To cover the various obligations of lessees on the OCS, the MMS generally requires that lessees post substantial bonds or other acceptable assurances that such obligations will be met. The cost of such bonds or other surety can be substantial and there is no assurance that the Working Interest Owner can obtain bonds or other surety in all cases. Additional financial responsibility requirements may be imposed under the Oil Pollution Act of 1990, as discussed under "Environmental Regulation."
Under certain circumstances, the MMS may require any Working Interest Owner operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect the Working Interest Owner's financial condition and operations. In addition, the MMS is conducting an inquiry into certain contract agreements from which producers on MMS leases have received settlement proceeds that are royalty bearing and the extent to which producers have paid the appropriate royalties on these proceeds. The Working Interest Owner believes that this inquiry will not have a material impact on its financial condition, liquidity or results of operations.
The MMS has issued a notice of proposed rulemaking in which it proposes to amend its regulations governing the calculation of royalties and the valuation of crude oil produced from federal leases. This proposed rule would modify the valuation procedures for both arm's length and non-arm's length crude oil transactions to decrease reliance on oil posted prices and assign a value to crude oil that better reflects market value, establish a new MMS form for collecting value differential data, and amend the valuation procedure for the sale of federal royalty oil. The Working Interest Owner cannot predict what action the MMS will take on
this matter, nor can it predict at this stage of the rulemaking proceeding how the Working Interest Owner might be affected by this amendment to the MMS' regulations.
In April 1997, after two years of study, the MMS withdrew proposed changes to the way it values natural gas for royalty payments. These proposed changes would have established an alternative market-based method to calculate royalties on certain natural gas sold to affiliates or pursuant to non-arm's length sales contracts. Informal discussions among the MMS and industry officials are continuing, although it is uncertain whether, and what changes may be proposed regarding gas royalty valuation. In addition, MMS has recently announced its intention to issue a proposed rule that would require all but the smallest producers to be capable of reporting production information electronically by the end of 1998.
Additional proposals and proceedings that might affect the natural gas industry are considered from time-to-time by Congress, the FERC, state regulatory bodies, and the courts. The Working Interest Owner cannot predict when or if any such proposals might become effective, or their effect, if any, on the Trust. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue indefinitely into the future.
Environmental Regulation. The Working Interest Owner's oil and gas activities on the Royalty Properties are subject to existing federal, state and local laws and regulations relating to health, safety, environmental quality and pollution control. The Working Interest Owner has advised the Trustee that it believes that its operations and facilities are in general compliance with applicable health, safety, and environmental laws and regulations. Events in recent years have, however, heightened environmental concerns about the oil and gas industry generally, and about offshore operations in particular. As a consequence, offshore oil and gas leases have become subject to more extensive governmental regulation, including regulations that may in certain circumstances impose absolute liability upon lessees for cost of removal of pollution and for pollution and natural resource damages resulting from their operations, and that may result in assessment of civil or criminal penalties against lessees, or even suspension or cessation of operations in the affected areas. Although the Working Interest Owner has advised the Trustee that current environmental regulation has not had a material adverse effect on the Working Interest Owner's present method of operations, the impact of changes in environmental laws, such as stricter environmental regulation and enforcement policies, cannot be predicted at this time.
The Oil Pollution Act of 1990 (OPA) and regulations promulgated pursuant thereto impose a variety of obligations on "responsible parties" with respect to the prevention of oil spills and liability for damages resulting from such spills. A "responsible party" includes the owner or operator of a facility, pipeline or vessel. For offshore facilities, the responsible party is the lessee or permittee or holder of a right of use and easement (granted under applicable state law or OCSLA) of the area in which the offshore facility is located. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages, including natural resource damages. While liability limits apply in some circumstances, a responsible party for an Outer Continental Shelf facility must pay all spill removal costs incurred by a federal, state or local government. The OPA establishes a liability limit (subject to indexing) for offshore facilities of all removal costs plus $75,000,000. A party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction, or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Few defenses exist to the liability imposed by OPA.
The OPA also imposes ongoing requirements on a responsible party, including proof of financial responsibility to cover a substantial portion of environmental clean-up and restoration costs that could be incurred by governmental entities in connection with an oil spill. Other requirements imposed by the OPA include the preparation of an oil spill contingency plan. The Working Interest Owner has advised the Trustee that it has in place appropriate spill contingency plans and has established adequate proof of financial responsibility for its offshore facilities. A failure to comply with ongoing requirements or inadequate cooperation in a spill event may subject a responsible party to civil or criminal enforcement action. In short, the OPA places a burden on offshore lease holders to conduct safe operations and take other measures to prevent oil spills; if one occurs, the OPA then imposes liability for resulting damages.
In addition, the OCSLA authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating on the OCS. Specific design and operational standards may apply to OCS vessels, rigs, platforms, vehicles and structures. Violations of environmental related lease conditions or regulations issued pursuant to the OCSLA can result in substantial civil and criminal penalties as well as potential court injunctions curtailing operations and the cancellation of leases. Such enforcement liabilities can result from either governmental prosecution or citizen initiated legal action.
The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of person that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site where the release occurred and companies that disposed or arranged for disposal of hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.
In recent years, at least three courts have ruled that certain waste products associated with the production of crude oil may be classified as "hazardous substances" subject to regulation and liability under CERCLA, depending on the characteristics of the waste products and circumstances under which they were created. In addition, legislation has been proposed in Congress from time to time that would reclassify certain oil and gas exploration and production wastes as "hazardous wastes," which would make the reclassified wastes subject to much more stringent handling, disposal and clean-up requirements under the Resource Conservation and Recovery Act. Any reclassification of oil and gas exploration and production wastes from non-hazardous to hazardous could have a significant impact on the operating costs of the Working Interest Owner, as well as the oil and gas industry in general. Initiatives to further regulate the disposal of oil and gas wastes are also pending in certain states, and these various initiatives could have a similar impact on the Working Interest Owner.
TITLE TO PROPERTIES
The Conveyance is subject to customary interests and burdens, to the terms and provisions of the underlying leases, to liens and other provisions of farm out, operating, pooling and unitization agreements and to minor encumbrances, easements and restrictions. The Royalty Properties are also subject to the OCSLA, the regulations promulgated thereunder and possibly certain provisions of the laws of the adjacent states. The Conveyance contains a special warranty of title in which the Company warranted title to the Royalty against persons claiming by, through or under the Company, but not otherwise.
FEDERAL INCOME TAX CONSIDERATIONS
All Unit holders are urged to consult their own tax advisors regarding the effects of acquisition, ownership and disposition of Units on their personal tax positions.
INTERNAL REVENUE SERVICE RULINGS
The following information regarding FTX's private letter rulings was supplied to the Trustee by FTX. In connection with the creation of the Trust and the distribution of Units to FTX's stockholders (the Distribution) FTX requested and received favorable private letter rulings from the Internal Revenue Service (Service) regarding certain tax matters. Among the principal rulings requested and received were the following:
1. For federal income tax purposes, the Trust and the Partnership will be classified as a trust and a partnership, respectively, and not as associations taxable as corporations.
2. For federal income tax purposes, the Trust will be characterized as a "grantor" trust as to the Unit holders and their transferees.
3. For federal income tax purposes, the Distribution will be treated as a distribution of the Royalty by FTX to the stockholders, followed by the contribution of the Royalty by the stockholders to the Partnership in exchange for interests therein, followed in turn by the contribution by the stockholders of the interests in the Partnership to the Trust in exchange for the Units.
4. FTX will recognize no gain or loss upon the transfer of the Royalty to its stockholders.
5. Each Unit holder will be entitled to deduct cost depletion with respect to its pro-rata interest in the Royalty computed with reference to the Unit holder's basis in the Units.
6. The Royalty will be considered an economic interest in oil and gas in place, and the Royalty will constitute a single property within the meaning of Section 614(a) of the Internal Revenue Code of 1954, as amended, as in effect when the transaction was consummated.
AREAS OF POTENTIAL TAX CONTROVERSY
Information Return Filing Requirements. Under the Internal Revenue Code of 1986, as amended (the Code), any partner who sells or exchanges (other than through a broker) an interest in a partnership holding "unrealized receivables" within the meaning of Section 751 of the Code is required to notify the partnership of such transaction in accordance with Treasury regulations. Any such partner who fails to so notify the partnership may be subject to a $50 penalty for each such failure. Furthermore, on a sale or exchange of Units, other than through a broker, the partnership is required to notify the Service of any such sale or exchange (of which it has notice) of a partnership interest after December 31, 1984, and to report the name and address of the transferee and the transferor who were parties to such transaction, along with all other information required by applicable Treasury regulations. The partnership must also provide this information to the transferor and the transferee. If the partnership fails to furnish any such notification, it may be subjected to a penalty of $50 per failure, up to an annual maximum of $100,000. Final Treasury regulations exempt partnerships from the requirement to report any sales which are reported by a broker on Form 1099-B.
The Code provides that depletion deductions subject to recapture under Section 1254 of the Code constitute "unrealized receivables" within the meaning of Section 751 of the Code. Section 1254 of the Code provides that for property placed in service by a taxpayer after December 31, 1986, depletion deductions which reduce the adjusted basis of such property must be recaptured as ordinary income upon a disposition of the property (to the extent gain is recognized on such disposition). It is unclear whether this recapture provision applies to any portion of the depletion claimed with respect to the Royalty (placed in service in 1983 by the Partnership) in the case of Units acquired after December 31, 1986. The Service has not issued any regulations or other pronouncements to indicate its interpretation of these recapture provisions as they might affect the transfer of partnership interests. Accordingly, Unit holders disposing of Units acquired after December 31, 1986 (other than through a broker) may be required to notify the Trustee in writing of such disposition and provide the Trustee with the Unit holder's name, address, taxpayer identification number and the date of the disposition. Failure to so notify the Trustee may subject such a Unit holder, as well as the Trust and the Partnership, to the above-described penalties. Without notification from Unit holders, the Trust and Partnership cannot comply with these reporting requirements because they have no other means of determining which Units disposed of during the year were acquired by the transferring Unit holder subsequent to December 31, 1986.
Other Possible Penalties. An owner of a security who receives income in respect of such interest must report the character and amount of such income, for federal tax purposes, in a manner which is consistent with the federal tax reports of the entity which was the source of the income. The consistency requirement is deemed to be waived if the taxpayer files a statement with the Service identifying the inconsistency. Because of the presence of "street name" investors and the possible existence of transfer record inaccuracies, holders of interests which are actively traded in the securities markets may encounter situations in which it is difficult to fully and accurately comply with the consistency requirement and other federal tax reporting requirements. Certain penalties could be assessed against a taxpayer that fails to comply with such requirements. Because of the complexity of the federal tax reporting requirements applicable to trusts (such as the Trust) which own interests in partnerships (such as the Partnership) and because all of the tax attributes of the Royalty flow
through the Partnership and the Trust to the Unit holders, there is an increased likelihood that Unit holders will violate the consistency requirement and other reporting requirements regarding their individual federal income tax returns and the information returns of the Trust and the Partnership. Any violations of the consistency requirements could lead to imposition of certain penalties on the Unit holders or other adverse results. Furthermore, the Trust or the Partnership might be subject to certain penalties in connection with their furnishing of statements and information to Unit holders or the government if such statements or information prove to be inaccurate due, for example, to differences between the transfer agent's records and actual ownership data. The Code provides reporting requirements designed to facilitate the transfer of information between partnerships and trusts and owners of interests therein held by nominees.
ITEM 2.
ITEM 2. PROPERTIES.
Reference is made to Item 1 of this report.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
The Trust is not currently subject to any legal proceedings.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF UNIT HOLDERS.
No matters were submitted to a vote of Unit holders during the fourth quarter of 2000.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S UNITS AND RELATED UNIT HOLDER MATTERS.
Freeport-McMoRan Oil and Gas Royalty Trust Units are traded on the over the counter market under the symbol "FMOLS." As of March 20, 2001, 14,975,390 Units were outstanding and held of record by , Unit holders.
The high and low sales prices of the Units as reported on the New York Stock Exchange and the over the counter Bulletin Board and distributable cash per Unit for each quarterly period of 2000 and 1999 were:
Distributable cash for any quarter is distributed to Unit holders in the month following the close of the quarter.
The Trust did not sell any securities in 2000.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
The following table sets forth in summary form selected financial data regarding the Trust. Such information should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Financial Statements and the notes thereto included elsewhere herein. Reference is also made to Item 1 of this Form 10-K.
The Trust has not reported estimates of total proved net oil or gas reserves to any federal authority or agency other than the SEC.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
The Cost Carry-Forward decreased by $2.6 million, from $22.4 million at December 31, 1999 to $19.8 million at December 31, 2000. Ryder Scott made estimates of future net cash flows as of December 31, 2000 as set forth in their letter appearing elsewhere in this report. Such proved reserve estimates are based on various assumptions, many of which are subject to uncertainties, as more fully discussed in Note 10 to the financial statements. These estimates do not consider changes in prices and costs subsequent to December 31, 2000, or the possibility of additional potentially recoverable reserves not currently classified as proved, and therefore should not be considered to be a prediction of actual amounts to be paid to the trustee or an estimate of fair market value. The Working Interest Owner has advised the Trustee that, based on an independent review of the oil and gas interests burdened by the Royalty, the net present value of the reserves contained therein is less than the cumulative excess cost carry-forward. See Note 1 to the Financial Statements. The information from the Working Interest Owner indicates that the Royalty may have little or no value, based on the net present value of reserves determined as a result of the independent review.
RESULTS OF OPERATIONS
No cash distributions were made during 2000, 1999 and 1998, because of the cost carry-forward due to capital expenditures and lower gas and oil revenues in 1999, 1998 and 1997. During 2000, Gross Proceeds exceeded total costs by approximately $2.9 million, primarily because of increased oil revenue from West Cameron Block 498. As a result, the cost carry-forward decreased to $19.8 million net to the Trust as of December 31, 2000. Since mid-1995, trust administrative expenses have been paid from the expense reserve. The calculation of distributable cash for each year follows:
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(1) Gross proceeds represent amounts received by the Working Interest Owner during the twelve month period ended November 30 of such year.
(2) Total costs represent amounts accrued by the Working Interest Owner during the twelve month period ended November 30 of such year. Includes interest to the Working Interest Owner of $2,082,725, $2,292,141 and $1,954,000 respectively. Total costs for 1999 also includes a credit of $4,636,212 for the reversal of plug and abandonment costs.
(3) Represents Class A costs incurred (recouped) in the applicable periods that remained outstanding as of the end of such period.
(4) Represents the net amount withdrawn from the Trust administrative expense reserve during the respective period.
Gross proceeds, which include gas and oil revenues, are calculated based on amounts received by the Working Interest Owner. Operating information follows:
There was a decrease in gas volumes and revenues during 2000 as compared to 1999 primarily as a result of the Working Interest Owner assigning its ownership interest in West Cameron Block 215, Breton Sound Block 55 and Vermilion Block 58 to the operator during 1999.
There was a slight increase in gas volumes for 1999 as compared to the 1998 period, however, the 1999 volume included a settlement for gas imbalance of 1.2 bcf. This gas imbalance settlement also affected the calculated average price received for gas during 1999. Gas volume and revenue, excluding the settlement for gas imbalances, decreased during 1999 as compared to 1998 due to normal production declines and to the Working Interest Owner assigning its interests in several properties to the operators. Gas revenue for 1999 included $1.5 million net to the Trust, for the settlement of gas imbalances on West Cameron Block 215.
Oil volume and revenue increased significantly during 2000 as compared to 1999 as a result of the workovers performed during 2000 and because of the increase in oil prices.
Oil volume for 1999 decreased by 63% from 1998. This decrease in oil volume coupled with a slight decrease in average oil prices resulted in a 63% decrease in oil revenues for 1999. The decrease in oil volume was a direct result of mechanical problems and well performance occurring during the last quarter of 1998 at West Cameron Block 498 extending into the first quarter of 1999. The operator began a workover program during the second quarter of 1999 and production increased during the fourth quarter of 1999. Production rates at West Cameron Block 498 field fluctuated during 1998 as production rates from individual wells fluctuated. During the second, third, and fourth quarters of 1999, the operator performed workovers on individual wells that offset the field decline and in some months increased production. Some of those workovers were designed to increase recoveries from existing producing intervals and others were designed to recover oil and gas from different intervals that were expected to be productive.
Costs consist of the following (in millions):
Lease operating expenses for the 2000 periods decreased over the 1999 period because the Working Interest Owner assigned its interest in West Cameron Block 215, Vermilion Block 58 and Breton Sound Block 55 to the operator, thereby reducing expenses. The Working Interest Owner believed the costs charged for High Island 552 to be excessive and conducted an audit of High Island Block 552 in the fourth quarter of 1999. This audit resulted in a credit issued by the operator of $1.5 million net to the Working Interest Owner. This credit was issued during the first quarter of 2000 and is offset by amounts owed the operator of approximately $544,000. In addition, the Working Interest Owner is entitled to operating and processing fees attributable to production from offsetting blocks being processed on the High Island A552 platform. The Working Interest Owner began suspending payments of operating expenses to the operator in early 1999.
Lease operating expenses for 1999 increased from 1998 primarily because of the increasing production costs associated with West Cameron Block 498, as well as, $.02 million being recorded during the third quarter to settle a disputed liability at Vermilion Block 310 offset by a $.4 million insurance adjustment credit. Exploration and development costs for both 1998 and 1997 reflects the drilling and development activity at West Cameron Block 498. Lease operating expenses were lower in 1997 as a result of declining production. Exploration and development costs primarily consist of costs incurred to explore and develop West Cameron Blocks 498 and 215 in 1997. Abandonment costs were accrued each year based on the estimate of costs required to abandon the Trust's properties -- see Note 8. During 1999, a credit of $4.6 million for accrued
abandonment cost is included in total costs as the result of reversing previously accrued abandonment cost associated with the assigned properties.
In December 1997, the Working Interest Owner entered into a crude oil agreement with an oil pipeline company to deliver on a daily basis specified quantities of crude oil from West Cameron 498. Under the terms of the agreement, the Working Interest Owner agreed to pay a transportation fee calculated at a sliding monthly rate based upon the total average daily volumes delivered from West Cameron 498 during the month. Should the annual minimum delivery volume not be met a deficiency payment is assessed by the pipeline. During 2000 the Working Interest Owner did not deliver the minimum volume under the agreement; therefore, in February 2001, the pipeline company billed the Working Interest Owner approximately $502,000 for the 2000 deficiency. Deficiency payments of approximately $724,000 for 1999 and $687,000 for 1998 were paid by the Working Interest Owner and are included in the Cost Carry-Forward of $19.8 million at December 31, 2001. However, should production exceed the 2000 minimum the Working Interest Owner is entitled to receive transportation without pay up to the cumulative prior undelivered volumes.
Exploration and development costs for 2000 relate primarily to the workovers and facility modifications made during 2000 at West Cameron Block 498. Development costs for 1999 also related to the development of West Cameron Block 498.
CAPITAL RESOURCES AND LIQUIDITY
All revenues received by the Trust, net of Trust administrative expenses and received for liabilities, are required to be distributed to the Unit holders in accordance with provisions of the Trust Indenture. The cost carry-forward, with interest at the prime rate, must be recouped from future Gross Proceeds before any distributions may be made to Unit holders.
At December 31, 2000, West Cameron Block 498 had 13 producing development wells, this compares to 10 development wells producing at December 31, 1999. The average daily production relating to revenue received by the Trust from this field during 2000 was approximately 785.8 barrels of oil and 2.1 mmcf of gas. The average daily production relating to revenue received by the Trust from this field during 1999 was approximately 595.6 barrels of oil and 1.3 Mmcf of gas. The average gross daily production figures may vary throughout the life of the field. These variations may be attributable to a number of factors, including the number of wells on production at a given point in time, natural depletion of wells, production techniques, and adjustments to flow rates in order to optimally produce the related reserves. At year end 2000, the field was producing approximately 4.2 mmcf per day and 955.51 barrels per day net to the Working Interest Owner. The Working Interest Owner owns a 23.1 percent working interest and a 19.2 net revenue interest prior to taking into account the Trust's Royalty interest.
Additional exploration may be proposed by the operators of certain other Royalty Properties. After analyzing each proposal, the Working Interest Owner will determine whether or not to participate in additional exploratory operations.
There are no exploration and development costs budgeted by the Working Interest Owner for 2001.
Estimated future abandonment costs, based on current laws and regulations, are accrued over the life of the Trust's properties (see Note 8). On May 19, 1999 the Working Interest Owner assigned its ownership interest in West Cameron Block 215, Breton Sound Block 55 and Vermilion Block 58 to the operator in exchange for the operator assuming all duties and obligations with respect to the assigned interest and existing wells and platforms. The assignment was effective January 1, 1999. As a result of this transaction the Working Interest Owner reversed the plug and abandonment accrual associated with the assigned properties, which reduced the Cost Carry-Forward by $3,989,615, net to the Trust. On August 30, 1999 the Working Interest Owner assigned its ownership interest in Vermilion Blocks 21/22 and paid $297,500 to the operator in exchange for the operator assuming all duties and obligations with respect to the assigned interest and existing wells and platforms. The assignment was effective April 1, 1999. As of December 31, 2000, the estimated remaining aggregate abandonment costs to be incurred for all of the Trust's properties totaled $4.2 million net to the Trust, all of which has been withheld from distributions to Unit holders. Such costs are by their nature
imprecise and can be expected to be revised over time because of changes in general and specific cost levels, government regulations, operations or technology. Any further adjustments to estimated abandonment costs or variances to actual costs will reduce or increase future distributable cash accordingly.
The Working Interest Owner has brought suit against a prior gas purchaser seeking reimbursement as excess royalty of a portion of amounts paid to the Minerals Management Service (MMS) by the Working Interest Owner to settle claims made by the MMS for additional royalty resulting from the Working Interest Owner's compromise of claims against the gas purchaser. The Trust's interest in the proceeds of the gas contract settlement were included in the Trust's Gross Proceeds and the funds paid to the MMS reduced the Trust's Gross Proceeds. The suit is in the early stages, and no trial date has been set. The amount of any recovery with respect to this claim is presently indeterminable. However, if the Working Interest Owner receives any amount in this litigation, a major portion of it will be treated as Gross Proceeds.
At certain times since late 1993, the Trust has been unable to pay its ongoing administrative expenses. To permit the Trust to pay its administrative expenses during the time the Trust incurs a Class A cost deficit, the Trustee, in accordance with the Trust Indenture, established a $2.4 million Trust administrative expense reserve to pay such expenses (see Note 6 -- Establishment of an Expense Reserve), of which $0.6 million remained at December 31, 2000.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The only significant market risk to the Trust is oil and gas commodities prices, which are discussed more fully in ITEM 7, "MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS."
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
STATEMENTS OF ROYALTY PROCEEDS AND DISTRIBUTABLE CASH
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
STATEMENTS OF CHANGES IN TRUST CORPUS
The accompanying notes are an integral part of these financial statements.
FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS
1. BACKGROUND AND STATUS
Freeport-McMoRan Oil and Gas Royalty Trust (the Trust) was created effective September 30, 1983. On that date, Freeport-McMoRan Inc. (FTX) transferred to a Partnership (the Partnership) a net overriding royalty interest in certain offshore oil and gas properties equal to 90 percent of the Net Proceeds (as defined in the Conveyance referred to below) from FTX's working interests in such properties and conveyed a 99.9 percent general partnership interest in the Partnership to the Trust. Such net overriding royalty interest is referred to herein as the "Royalty." The Overriding Royalty Conveyance which created the Royalty is referred to herein as the "Conveyance." IMC Global Inc. ("IMC") succeeded to FTX effective December 22, 1997, following the merger of FTX into IMC. Accordingly, IMC is now the Working Interest Owner and owns the oil and gas interests burdened by the Royalty. The Conveyance provides that the owner of the interests burdened by the Royalty will calculate and pay monthly to the Partnership an amount equal to 90 percent of the net proceeds for the preceding month. Net proceeds generally consist of the excess of gross revenues received from the Royalty Properties (Gross Proceeds), on a cash basis, over operating costs, capital expenditures and other charges, on an accrual basis (Net Proceeds). The Trust is passive, with The Chase Manhattan Bank as Trustee. The Trustee has only such powers as are necessary for the collection and distribution of revenues attributable to the Royalty, the payment of Trust liabilities and the protection of Trust assets.
The Trust Indenture provides generally that the Trust shall terminate upon the first to occur of: (i) the sale of all the Trust's interest in the Partnership, or the sale by the Partnership of all the assets of the Partnership including the Royalty, or (ii) a decision to terminate the Trust by the affirmative vote of Unit holders representing a majority of the Units. The Trust Indenture also provides that if the amount of cash per year for five successive years is less than $3 million, the Trustee will sell the Trust's interest in the Partnership or cause the Partnership to sell the Royalty.
The Trust's cash receipts last reached $3 million during 1995 and there have been no cash receipts since 1995. Therefore, the Trust indenture provides the Trustee must sell the Trust's interest in the Partnership or cause the Partnership to sell the Royalty. The Trustee is currently investigating alternatives to fulfill its responsibilities in that regard.
Ryder Scott Company Petroleum Engineers conducted an independent review of the oil and gas interest burdened by the Royalty and prepared estimates, as of December 31, 2000, of the discounted present value of future net revenues from proved reserves attributable to the Royalty. The report of Ryder Scott is set forth elsewhere in this report. The estimates were prepared in accordance with SEC regulations, which among other things require that estimated net revenues be based on prices and costs as of December 31, 2000. Ryder Scott estimated that the net present value (discounted at 10%) of proved reserves attributable to the Royalty was $15.5 million and that the undiscounted estimated future net revenues from proved reserves were $18.4 million as of December 31, 2000. However, the estimates do not take into account many additional factors that impact the value of the Royalty, including the following:
- Pursuant to the Conveyance, the Working Interest Owner is entitled to recoup certain costs before any payments are made with respect to the Royalty. When these costs cannot be paid out of current revenue, they are accrued and carried forward. As of December 31, 2000, the accumulated cost carry-forward was approximately $19.8 million. The estimated discounted present value of $15.5 million and the undiscounted estimated net revenues of $18.4 million in the Ryder Scott report do not take into account the cost carry-forward.
- The Ryder Scott estimates took into account only those reserves that were classified as proved reserve as of December 31, 2000, and only the estimated costs of developing and producing those proved reserves. Thus, the estimates did not take into account costs that may be incurred to
FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
discover, develop or produce reserves not classified as proved as of December 31, 2000, nor did they take into account future revenues, if any, from such reserves.
- The weighted average prices used in the Ryder Scott report were $23.52 per Bbl of oil and $5.85 per Mcf of gas. Oil and natural gas prices have declined substantially since December 31, 2000.
- Proceeds from gas produced but sold by other parties pursuant to gas balancing arrangements are not included in estimated future proceeds (see Note 4). As of December 31, 2000, the quantity of gas sold by third parties under the gas balancing arrangements was approximately .2 Bcf. Proceeds related to the underproduction position could result in additional proceeds to the Trust or reduce the cost-carryforward in future periods, however, the amount and timing of such proceeds are uncertain. In addition, other factors, including the credit worthiness of the counterparties should be considered in determining the probability and amount of future proceeds. The Ryder Scott estimates did not include proceeds that maybe received with respect to the gas balance arrangements.
- The Working Interest Owner has brought suit against a prior gas purchaser, seeking reimbursement of excess royalty of a portion of amounts paid to the Minerals Management Service (see Note 5). A successful outcome for the Working Interest Owner could result in additional proceeds to the Trust or reduce the cost-carryforward. However, the suit is in the early stages, and no trial date has been set. The amount of any recovery is presently indeterminable. The Ryder Scott estimates did not include proceeds, if any, from this lawsuit.
- The reserve for future abandonment costs for the Trust's properties totals $4.2 million. This amount is included in the cost carryforward of $19,755,720, as of December 31, 2000 (see Note 8). Such costs are by their nature imprecise and can be expected to be revised over time due to changes in general and specific cost levels, government regulation, operations or technology. The Ryder Scott estimates did not take into account any changes in such costs.
- In December 1997, the Working Interest Owner entered into a crude oil agreement with an oil pipeline company which included an annual minimum delivery volume (see Note 9). Since the agreement's inception, the Trust has been assessed a deficiency payment ranging from $.5 million to $.7 million on an annual basis. There are no assurances that the annual minimum delivery volume will be met in the future.
Accordingly the estimated discounted net present value of future net revenues should not be construed as the current market value of the estimated oil and gas reserves, since a market value determination would include these and other additional factors. The Ryder Scott report is included elsewhere in this report and includes additional information regarding the estimates.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The Trust's financial statements, which reflect the Trust's 99.9 percent interest in the Partnership , are prepared on the cash basis of accounting for reporting revenues and expenses. Therefore, revenues and expenses are recognized only as cash is received or paid and the associated receivables, payables and accrued expenses are not reflected in the accompanying financial statements. Under accounting principles generally accepted in the United States, revenues and expenses would be recognized on an accrual basis.
The initial carrying amount of the Royalty represented the Working Interest Owner's net book value applicable to the interest in the properties conveyed to the Trust on the date of creation of the Trust. Amortization of the Royalty has been charged directly against trust corpus using the future net revenue method. This method provides for calculating amortization by dividing the unamortized portion of the Royalty
FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
by estimated future net revenues from proved reserves and applying the resulting rate to the Trust's share of royalty proceeds.
The carrying value of the Royalty is limited to the discounted present value (at 10 percent) of estimated future net cash flows (as set forth in Note 10). Any excess carrying value is reduced and the adjustment is charged directly against trust corpus. The carrying value of the Royalty was $0 at December 31, 2000 and 1999.
Because the Trust is a grantor trust which is not a taxable entity, no income taxes are reported in the Trust's financial statements. The tax consequences of owning Units are included in the federal, state and local income tax returns of the individual Unit holders.
3. COST CARRYFORWARD
As a result of the capital costs incurred in recent years, a cumulative excess cost carry-forward of $19.8 million existed as of December 31, 2000. The cost carry-forward was $22.4 million at December 31, 1999. The cost carry-forward is subject to and includes an interest amount at the prime rate, which totaled $6.8 million net to the Trust at December 31, 2000. This excess cost carry-forward must be recouped by the Working Interest Owner out of future Gross Proceeds before distributions to the Unit holders can be resumed. See Note 1.
4. GAS BALANCING ARRANGEMENTS
As a result of past curtailments in gas takes by the principal purchaser of production from the Royalty Properties, certain quantities of gas have been sold by other parties with interests in the Royalty Properties pursuant to gas balancing arrangements. Proceeds from gas produced from the Royalty Properties but sold by other parties pursuant to such balancing arrangements (underproduction) are not included in Gross Proceeds. In the future, the Working Interest Owner will be entitled to sell volumes equal to such underproduction or receive cash settlements. On certain of the Royalty Properties, a cash settlement may be required, depending on future results, due to the lack of sufficient remaining reserves from which to makeup any underproduction. As of December 31, 2000, the unrecovered quantity of gas sold by third parties pursuant to such gas balancing arrangements since inception of the Trust was approximately .2 billion cubic feet (bcf), net to the Trust. Gross Proceeds may be increased in future periods when the Working Interest Owner is compensated either through the sale of gas or through cash settlements, the amount and timing of which are uncertain. In addition, other factors, including the credit worthiness of the counterparties should be considered in determining the probability and the amount of future proceeds.
On May 19, 1999 the Working Interest Owner assigned its ownership interest, to include gas imbalances, in West Cameron Block 215, Breton Sound Block 55 and Vermilion Block 58 to the operator in exchange for the operator assuming all duties and obligations with respect to the assigned interest and existing wells and platforms. The assignment was effective January 1, 1999. As a result of this transaction, the Working Interest Owner received approximately $1.5 million, net to the Trust, from the operator in settlement for the gas imbalances. On August 30, 1999 the Working Interest Owner assigned its ownership interest, to include gas imbalances in Vermilion Blocks 21/22 and paid $.3 million to the operator in exchange for the operator assuming all duties and obligations with respect to the assigned interest and existing wells and platforms. The assignment was effective April 1, 1999.
5. GAS CONTRACT SETTLEMENT
The Working Interest Owner has brought suit against a prior gas purchaser, seeking reimbursement as excess royalty of a portion of amounts paid to the Minerals Management Service (MMS) by the Working Interest Owner to settle claims made by the MMS for additional royalty resulting from the Working Interest
FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Owner's compromise of claims against the gas purchaser. The Trust's interest in the proceeds of the gas contract settlement were included in the Trust's Gross Proceeds and the funds paid to the MMS reduced the Trust's Gross Proceeds. The suit is in the early stages, and no trial date has been set. The amount of any recovery with respect to this claim is presently indeterminable. However, if the Working Interest Owner receives any amount in this litigation, a major portion of it will be treated as Gross Proceeds.
6. ESTABLISHMENT OF AN EXPENSE RESERVE
Because of the decline in Royalty income, at certain times since late 1993 the Trust was unable to pay its ongoing administrative expenses. To permit the Trust to pay its routine administrative expenses, the Trustee, in accordance with the Trust Indenture, established an expense reserve of $2.4 million of which $.6 million remained as of December 31, 2000. Because the Trust had no cash receipts in 1999, $.3 million was withdrawn from the expense reserve during 2000 to pay Trust administrative expenses.
The funding for this reserve is deposited with Chase Bank of Texas and invested in Chase Bank of Texas collateralized certificates of deposit. The average interest rate earned on these funds was 5.5 percent for 2000, 4.4 percent for 1999, and 4.5 percent for 1998.
7. FEDERAL INCOME TAX MATTERS
The Trustee reports on the basis that the Trust is a grantor trust. 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 was held to be taxable as a corporation, it would have to pay tax on its net taxable income at the corporate rate.
8. RESERVE FOR FUTURE ESTIMATED ABANDONMENT COSTS
Estimated future abandonment costs are accrued over the life of the Trust's properties based on current laws and regulations. Such costs are by their nature imprecise and can be expected to be revised over time because of changes in general and specific cost levels, government regulations, operations or technology. As of December 31, 2000, the estimated remaining aggregate abandonment costs to be incurred for all of the Trust's properties totaled $4.2 million net to the Trust, all of which has been withheld from distributions to Unit holders.
On May 19, 1999 the Working Interest Owner assigned its ownership interest in West Cameron Block 215, Breton Sound Block 55 and Vermilion Block 58 to the operator in exchange for the operator assuming all duties and obligations with respect to the assigned interest and existing wells and platforms. The assignment was effective January 1, 1999. On August 30, 1999 the Working Interest Owner assigned its ownership interest in Vermilion Blocks 21/22 and paid $.3 million to the operator in exchange for the operator assuming all duties and obligations with respect to the assigned interest and existing wells and platforms. The assignment was effective April 1, 1999. The completion of these assignments resulted in a reduction of estimated future abandonment costs totaling approximately $4.2 million, net to the Trust.
Any further adjustments to estimated abandonment costs or variances to actual costs will reduce or increase future distributable cash after consideration of the Cost Carry-Forward.
9. TRANSPORTATION AGREEMENT
In December 1997 the Working Interest Owner entered into a crude oil agreement with an oil pipeline company to deliver on a daily basis specified quantities of crude oil from West Cameron 498. Under the terms of the agreement the Working Interest Owner agreed to pay a transportation fee calculated at a sliding monthly rate based upon the total average daily volumes delivered from West Cameron 498 during the month. Should the annual minimum delivery volume not be met, a deficiency payment is assessed by the pipeline. FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
During 2000, 1999 and 1998, the Working Interest Owner did not deliver the minimum volume under the agreement, therefore, the pipeline company billed the Working Interest Owner for the deficiencies. In 2001 the pipeline company billed the Working Interest Owner approximately $.5 million for the 2000 deficiency. This amount is not included in the Cost Carry-Forward of $19.8 million at December 31, 2000. Deficiency payments of approximately $.7 million for 1999 and 1998, respectively, were paid by the Working Interest Owner and are included in the Cost Carry-Forward of $19.8 million at December 31, 2000.
10. SUPPLEMENTARY PROVED OIL AND GAS RESERVE INFORMATION (UNAUDITED)
Pursuant to the Financial Accounting Standards Board's (FASB) and SEC's disclosure standards for oil and gas producing activities, the Trust is required to include as supplementary information, estimates of quantities of proved oil and gas reserves attributable to the Trust. Since the Royalty is a net profits interest, the Partnership does not own and is not entitled to receive any specific volume of reserves. Reserves attributable to the Partnership have been estimated based on projections of reserves and future net cash flows attributable to the combined interests of the Working Interest Owner and the Partnership, and a formula based upon estimates of future net cash flows. As a result of estimating reserve volumes by using a formula based upon estimates of future net cash flows, such reserves are affected by changes in various economic factors including prices, costs and the level and timing of capital expenditures on the properties. Therefore, the reserve volume estimates set forth below are hypothetical and are not comparable to estimates of reserves attributable to a working interest.
The reserve volume and cash flow amounts set forth below are for the interest in the Royalty attributable to the Trust, based on the Trust's 99.9 percent interest in the Partnership. Estimates of proved oil and gas reserves attributable to the Trust's interest are based on reports of Ryder Scott Company L.P. (Ryder Scott). In preparing its estimates, Ryder Scott did not take into account (a) revenues received after November 30 attributable to production during the fourth quarter of the respective year, (b) as of December 31, 2000, 1999 and 1998, approximately .2 bcf, .2 bcf, and 1.4 bcf sold by other parties pursuant to certain gas balancing arrangements and (c) an excess Cost Carry-Forward of $19.8 million, $22.4 million and $25.6 million at December 31, 2000, 1999 and 1998, respectively. For purposes of the reserve volume and cash flow amounts set forth below, the Trustee adjusted the estimates of Ryder Scott to take into account the foregoing factors, based on calculations supplied by the Working Interest Owner. In accordance with the requirements of the FASB, the reserve disclosures below were calculated using year-end oil and gas prices being received and current operating and abandonment cost levels.
As discussed in Note 8, based on escalated estimates of costs to abandon the properties burdened by the Royalty, estimated remaining future abandonment costs approximately equal amounts previously withheld from distributions to Unit holders. For purposes of the reserve volume and cash flow amount set forth below, Ryder Scott has not considered the escalated estimates of these costs, nor has there been any adjustment to Ryder Scott's estimates, as the Trust is required to present the supplementary information assuming no escalation in costs.
FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Proved Oil and Gas Reserves. The following table sets forth estimates of the interest attributable to the Trust in proved oil and gas reserves and changes in such estimates. Oil, including crude oil, condensate and natural gas liquids, is stated in thousands of barrels; gas is stated in millions of cubic feet.
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(1) Estimates of proved reserves are subject to possible change, either upward or downward, as additional information becomes available. Because the Royalty is a net profits interest and reserve quantities are estimated pursuant to a formula based in part on the estimated future net cash flows, factors other than changes in estimates of gross quantities of reserves (such as changes in prices and costs) can result in changes in estimates of reserve quantities attributable to the Trust. Proved oil and gas reserves at December 31, 2000 and 1999, based on year-end prices, would provide estimated future net revenues in an amount less than the Cost Carry-Forward. Accordingly, there were no proved reserves as of December 31, 2000, 1999 and 1998 attributable to the Trust.
Standardized Measure of Discounted Future Net Cash Flows from Proved Oil and Gas Reserves. The supplementary information presented below reflects estimates of discounted future net cash flows from proved oil and gas reserves and changes in such estimates prepared in accordance with requirements prescribed by the FASB.
Future cash flows are determined by multiplying the estimated future net cash flows attributable to the combined interests of the Partnership and the Working Interest Owner by a factor of 90 percent (the Partnership's Royalty). The resulting amount is then multiplied by a factor of 99.9 percent reflecting the Trust's interest in the Partnership. Future net cash flows also include an estimate of the proceeds to be received from underdelivered gas (see Note 4 above) and give consideration to the cost carry-forward at December 31, 2000 (see Note 1 above).
It is emphasized that this supplementary information represents estimates which may be imprecise, and extreme caution should accompany its use and interpretation. The estimates were based on various assumptions, many of which are subject to uncertainties, and therefore, the estimates should not be considered to be a prediction of actual amounts to be paid to the Trustee. Additionally, as required under FASB's and SEC's standards, the supplementary information excludes consideration of anticipated future oil and gas prices and costs, does not consider discount rates other than 10 percent and does not consider additional potentially recoverable oil and gas reserves not currently classified as proved. Such factors should be considered in estimating the cash flows which ultimately could be derived from production of the related oil and gas reserves or sale of the reserves in-place.
FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED OIL AND GAS RESERVES:
CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED OIL AND GAS RESERVES:
FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Chase Bank of Texas, National Association (Trustee) and the Unit Holders of Freeport-McMoRan Oil and Gas Royalty Trust:
We have audited the accompanying statements of assets, liabilities and trust corpus of Freeport-McMoRan Oil and Gas Royalty Trust as of December 31, 2000 and 1999, and the related statements of royalty proceeds and distributable cash, and changes in trust corpus for each of the three years in the period ended December 31, 2000. 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 auditing standards generally accepted in the United States. 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.
As described in Note 2, these financial statements were prepared on the cash basis of accounting which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States.
In our opinion, the financial statements referred to above present fairly, in all material respects, the assets, liabilities and trust corpus of Freeport-McMoRan Oil and Gas Royalty Trust as of December 31, 2000 and 1999, and the royalty proceeds and distributable cash, and changes in trust corpus for each of the three years in the period ended December 31, 2000, on the cash basis of accounting described in Note 2.
ARTHUR ANDERSEN LLP
Houston, Texas March 30, 2001
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, and to the Trustee's knowledge no person beneficially owns more than 5 percent of the outstanding Units. The Trustee is a corporate trustee which may be removed by the majority vote of the of the Unit holders.
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
No person is known by the Trustee to own beneficially more than 5 percent of the Units.
(b) Security Ownership of Management
Chase Bank of Texas, National Association, as Trustee of the Trust, owns no Units. Chase Bank of Texas, National Association in its individual capacity also owns no Units.
(c) Change in Control
The Trust knows of no arrangements, including the pledge of Units of the Trust, the operation of which may at a subsequent date result in a change in control of the Trust.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
The parent of Chase Texas, Chase Manhattan Corporation, has banking relationships with the Company.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(a)1. Financial Statements
Reference is made to Item 8 of this Form 10-K.
(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
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* Incorporated by reference to Exhibits of like designation to the registrant's Annual Report on Form 10-K for the period ended December 31, 1983.
(b) Reports on Form 8-K
No reports on Form 8-K were filed during 2000.
SIGNATURE
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.
FREEPORT-McMoRan OIL AND GAS ROYALTY TRUST
By: THE CHASE MANHATTAN BANK, Trustee
By: /s/ MIKE ULRICH ---------------------------------- Mike Ulrich Senior Vice President and Trust Officer
March 30, 2001
The Registrant, Freeport-McMoRan Oil and Gas Royalty Trust, has no principal executive officer, principal financial officer, principal accounting officer, board of directors or persons performing similar functions. Accordingly, no additional signatures are required.
EXHIBIT INDEX
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* Incorporated by reference to Exhibits of like designation to the registrant's Annual Report on Form 10-K for the period ended December 31, 1983.