ITEM 1. BUSINESS.
DESCRIPTION OF THE TRUST
Freeport-McMoRan Oil and Gas Royalty Trust (the Trust) was created under the laws of the State of Texas. Texas Commerce Bank National Association (Texas Commerce) serves as Trustee of the Trust. The Trustee maintains its offices at 712 Main Street, Houston, Texas 77002. The telephone number of the Trustee is (713) 216-5447.
For a discussion of the (i) estimated reserves owned by the Trust as of December 31, 1994 and the estimated future net income of the Trust, see the report by Ryder Scott Company Petroleum Engineers contained on pages 10 through 16 hereof, (ii) financial condition and results of operations of the Trust, see Item 7 appearing on pages 30 through 32 hereof and (iii) financial statements and supplementary data of the Trust, see Item 8 appearing on pages 33 through 39, with special reference to Note 10 thereto appearing on pages 37 through 39 hereof.
Units of beneficial interest (the Units) in the Trust are traded on the New York Stock Exchange under the trading symbol "FMR". The term "Company", as used herein, includes Freeport-McMoRan Inc. (FTX), its divisions, direct and indirect subsidiaries and affiliates, except as otherwise indicated by the context. The term "Working Interest Owner" includes Freeport-McMoRan Oil & Gas Company, a division of FTX (FMOG), and the successors and assigns of its oil and gas working interests to the extent the context requires.
The Units are not an interest in or an obligation of the Company, the Working Interest Owner or any successor Working Interest Owner although they 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 Royalty Trust Indenture entered into between FTX and the Trustee (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 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
On September 30, 1983, pursuant to the terms of the Overriding Royalty Conveyance (the Conveyance), the Company transferred, for the benefit of FTX's stockholders, 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 the Company's 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. FMOG provides the staff and facilities to carry out the administrative duties for and on behalf of ARPMC and FTX 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 for cash 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 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 power 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.
Texas Commerce, which also acts as Trustee of the Trust, and its parent, Chemical Banking Corporation, have banking relationships with the Company.
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. Due to 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 professional fees. The costs and expenses of the Trust (including the Trustee's fees) are currently estimated to be $0.6 million for 1995. In addition, the Trustee, in accordance with the Trust Indenture, is establishing an expense reserve of approximately $2.4 million to cover approximately 3 years of Trust expenses as discussed in Note 7 -- Establishment of an Expense Reserve. This reserve was partially funded with $1.9 million from the January 1994 settlement payment described in Note 6 -- Gas Contract Settlement, and a portion has been funded from Royalty income. The remaining $0.3 million will be funded from future Royalty income received by the Trust prior to making any distributions to Unit holders. The costs of the Partnership are expected to be minimal. The costs and expenses of the Trust may increase 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 professional 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 holders of the Units, upon termination of the Trust and in certain other limited circumstances. However, the Trust is directed to effect such a sale (without any such vote) if the Trust's cash receipts for each of three successive years commencing after December 31, 1990 are less than $3 million. Any such sale must be for cash, and the Trustee must distribute the net proceeds of such sale (after satisfaction of any outstanding liabilities) to the Unit holders.
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 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. As noted above, the Trustee is required to sell the Trust's interest in the Partnership, or cause the Partnership to sell the Royalty, if the Trust's
cash receipts for each of three successive years are less than $3 million, thereby terminating the Trust pursuant to (i) above. Upon the termination of the Trust under (ii) above, the Trustee will sell for cash the Royalty Properties (or will cause the Partnership to sell for cash all of the assets of the Partnership). The Trustee will as promptly as possible distribute the proceeds of any such sales according to the respective interests and rights of the Unit holders after discharging all of the liabilities of the Trust and, if necessary, setting up reserves in such amounts as the Trustee in its discretion deems appropriate for contingent liabilities.
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. A total of 14,975,390 Units are outstanding.
DISTRIBUTIONS AND INCOME COMPUTATIONS
The Trustee determines for each month the amount 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 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. The Trustee distributes 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, the 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. There were no cash distributions to the Unit holders for the year ended December 31, 1994.
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, the 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. The Working Interest Owner is free to transfer its working interest (burdened by the Royalty) to third parties. In certain cases (involving properties which have not been producing) the Working Interest Owner is permitted to farmout interests in the Royalty Properties and to reduce the Royalty proportionately. See "THE ROYALTY PROPERTIES AND THE ROYALTY -- General and -- Production and Development 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 value and 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 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, Louisiana or California 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 the Company 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
The locations of the Royalty Properties in which the Trust continues to have an interest are shown on the map on page 9. Certain information concerning such Royalty Properties as of December 31, 1994 is shown below:
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(1) The working interest shown represents only that portion of the working interest that is subject to the Royalty.
(2) The Working Interest Owner has farmed out its interest in a nonproductive portion of High Island Block A-552, retaining an overriding royalty interest burdened by the Royalty in the portion farmed out. The working interest percentage and net acres reflect its interest in the portion of the block not subject to the farm out.
(3) In 1985, Tract 214 in the Santa Maria Basin was farmed out, with the Working Interest Owner retaining an overriding royalty interest burdened by the Royalty.
As of December 31, 1994, there were 6 gross (1.45 net) productive oil wells and 30 gross (6.92 net) productive gas wells on 13 of the remaining Royalty Properties where the Working Interest Owner retains a working interest.
All remaining Royalty Properties are operated by other oil and gas companies under joint operating agreements. 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 (including the Working Interest Owner) 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 substantial revenue interest in all but three of the remaining Royalty Properties and it has informed the Trustee that it may conduct further development and exploratory activities on certain of the Royalty Properties. See "Production and Development 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, 1994, has been made by Ryder Scott Company Petroleum Engineers, 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, 1994, 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 1995 attributable to sales of oil and gas produced in the fourth quarter of 1994. Therefore, the amounts set forth in the letter are not necessarily 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, 1994. Of the total discounted present value of future net cash flows attributable to the Royalty estimated by Ryder Scott, approximately 46 percent are under contract with Transcontinental Gas Pipeline Co. (Transco), a purchaser of natural gas, and approximately 54 percent are expected to be sold on the spot market. 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).
[The map shows the fields offshore Louisiana and Texas with an inset map of California identifying the location of the Trust's Royalty Properties listed on page 7 by block or tract number as of December 31, 1994.]
[RYDER SCOTT COMPANY PETROLEUM ENGINEERS LETTERHEAD]
March 28, 1995
Freeport-McMoRan Oil and Gas Royalty Trust c/o Texas Commerce Bank National Association, Trustee 600 Travis Street, Suite 1150 Houston, Texas 77002
Gentlemen:
At the request of Freeport-McMoRan Oil & Gas Company (FMOG), a division of 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, 1994. 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 and offshore California. This net overriding royalty interest (Royalty) is the property that FTX 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 FMOG and the successors and assigns of its oil and gas working interests to the extent the context requires.
Thirteen offshore leases 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 thirteen leases are hereinafter referred to as the "Subject Properties". All other leases originally subject to the Royalty have either expired, or have been farmed out with the working interest owner retaining an overriding royalty interest burdened by the Royalty. The Working Interest Owner has assured us that no leases other than the thirteen included in our evaluation have a material effect on the overall revenues or liabilities of the Partnership.
FMOG has informed us that two exploratory wells have been drilled in one of the Subject Properties (West Cameron Block 498) that discovered oil and gas pay in multiple reservoir sands. These two wells (West Cameron 498 No. 2 and No. 3) were drilled in 1994 and were temporarily abandoned. FMOG also informed us that the operator and other working interest owners (including FMOG) are participating in a 3D seismic survey on this block, which will not be completed and interpreted until the second quarter of 1995. The results of this survey will be used to optimize the location and extent of future drilling. At the request of FMOG, we have not included any estimated reserves from these wells at this time, pending interpretation of the 3D seismic data and any future drilling.
The estimated reserve quantities and future income quantities presented in this report are related to hydrocarbon prices. December 1994 hydrocarbon prices were used in the preparation of this report as required by SEC guidelines; however, actual future prices may vary significantly from December 1994 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 28, 1995 SEC PARAMETERS Estimated Net Reserve and Income Data Freeport-McMoRan Oil and Gas Royalty Partnership As of December 31, 1994
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 15.025 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. 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 of income has been accrued as of December 31, 1994 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 reimbursement is equal to the amount by which current unspent accruals exceed anticipated future abandonment costs.
Freeport-McMoRan Oil and Gas Royalty Trust March 28, 1995
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, 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:
Royalty Future Net Income Partnership Interest Net Reserves = -------------------------- Price per Unit of Reserves
The price per unit of reserves was calculated by dividing combined future gross revenues by combined net reserves.
Reserve Definitions
The proved reserves presented in this report comply with the Securities and Exchange Commission's Regulation S-X Part 210.4-10 (a) as clarified by subsequent Commission's Staff Accounting Bulletins, and are based on the following definitions and criteria:
Proved reserves of crude oil, condensate, natural gas, and natural gas liquids are estimated quantities that geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known reservoirs under existing operating conditions using the cost and price parameters discussed in other sections of this report. Reservoirs are considered proved if economic producibility is supported by actual production or formation tests. In certain instances, proved reserves are assigned on the basis of a combination of core analysis and electrical and other type logs which indicate the reservoirs
Freeport-McMoRan Oil and Gas Royalty Trust March 28, 1995
are analogous to reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. The area of a reservoir considered proved includes (1) that portion delineated by drilling and defined by fluid contacts, if any, and (2) the adjoining portions not yet drilled that can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of data on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. Proved reserves are estimates of hydrocarbons to be recovered from a given date forward. They may be revised as hydrocarbons are produced and additional data become available. Proved natural gas reserves are comprised of non-associated, associated and dissolved gas. An appropriate reduction in gas reserves has been made for the expected removal of natural gas liquids, for lease and plant fuel, and for the exclusion of nonhydrocarbon gases if they occur in significant quantities and are removed prior to sale.
Reserves that can be produced economically through the application of improved recovery techniques are included in the proved classification when these qualifications are met: (1) 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, and (2) it is reasonably certain the project will proceed. Improved recovery includes all methods for supplementing natural reservoir forces and energy, or otherwise increasing ultimate recovery from a reservoir, including (1) pressure maintenance, (2) cycling, and (3) secondary recovery in its original sense. Improved recovery also includes the enhanced recovery methods of thermal, chemical flooding, and the use of miscible and immiscible displacement fluids.
Estimates of proved reserves do not include crude oil, natural gas, or natural gas liquids being held in underground or surface storage.
Depending on the status of development these proved reserves are further subdivided into:
(i) "developed reserves" which are those proved reserves reasonably expected to be recovered through existing wells with existing equipment and operating methods, including (a) "developed producing reserves" which are those proved developed reserves reasonably expected to be produced from existing completion intervals now open for production in existing wells, and (b) "developed non-producing reserves" which are those proved developed reserves which exist behind the casing of existing wells which are reasonably expected to be produced through these wells in the predictable future where the cost of making such hydrocarbons available for production should be relatively small compared to the cost of a new well; and
(ii) "undeveloped reserves" which are those proved reserves reasonably expected to be recovered from new wells on undrilled acreage, from existing wells where a relatively large expenditure is required, and from acreage for which an application of fluid injection or other improved recovery technique is contemplated where the technique has been proved effective by actual tests in the area in the same reservoir. Reserves from undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are included only where it can be demonstrated with reasonable certainty that there is continuity of production from the existing productive formation.
All proved reserves included in this report are classified as developed.
Freeport-McMoRan Oil and Gas Royalty Trust March 28, 1995
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 FMOG.
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
FMOG furnished us with prices in effect at December 31, 1994 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, 1994 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 1994, 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, 1994 were not considered in this study.
Freeport-McMoRan Oil and Gas Royalty Trust March 28, 1995
Gas
The Working Interest Owner has furnished us with gas prices in effect at December 1994 and with its forecasts of future gas prices which take into account SEC guidelines, current market prices, contract prices and fixed and determinable price escalations where applicable. 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 which are likely to cause future yearly average gas prices to be somewhat lower than December gas prices. For gas sold under contract, the contract gas price including fixed and determinable escalations, exclusive of inflation adjustments, was used until the contract expires and then was adjusted to the current market price for the area and held at this adjusted price to depletion of the reserves. At the request of the Working Interest Owner, a market price of $1.49 per MMBTU was used in this study for all uncontracted gas and for gas produced subsequent to the expiration of gas contracts.
Costs
The current operating, development 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 operating, development and overhead 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 and the development costs are based on authorizations for expenditure for the proposed work or on actual costs for similar projects.
General
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 1994.
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.
Freeport-McMoRan Oil and Gas Royalty Trust March 28, 1995
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 PETROLEUM ENGINEERS
Kent A. Williamson, P. E. Group Vice President
KAW/sw
Of the total discounted present value of future net cash flows attributable to the Royalty estimated by Ryder Scott, approximately 29 percent was accounted for by West Delta Block 34, 39 percent by West Cameron Block 215 and 16 percent by West Cameron Block 65.
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. See "Computation of the Royalty" below.
The Ryder Scott estimates were prepared on the basis of estimated production and Costs accrued after December 31, 1994. Thus, amounts received by the Working Interest Owner after November 30,
1994 attributable to production during 1994 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 1994. The Working Interest Owner has estimated that if Ryder Scott had taken into account the 1995 Gross Proceeds from 1994 production, the total estimated future net cash flow in the Ryder Scott letter would have been approximately $1.1 million higher and the discounted present value of such estimate would have been approximately $0.9 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 or proceeds to be received in connection with the Transco gas settlement (see Note 5 -- Gas Balancing Arrangements, Note 6 -- Gas Contract Settlement, 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 not been reduced for costs and expenses of the Trust, which are currently estimated at $0.6 million per year, or of the Partnership, which are expected to be minimal. Ryder Scott also did not take into account the approximately $4 million of funds retained by the Working Interest Owner in a suspense account, as described in Note 6 -- Gas Contract Settlement.
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. 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 equal to 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; CONFLICTS OF INTEREST
The amount of cash payable on account of the Royalty, and thus the amount of cash available for distribution to Unit holders, depends upon numerous factors and may vary substantially from month to month. In addition, conflicts of interest may arise between the Working Interest Owner and the Trust. These factors and potential conflicts include the following:
Timing of Collections by the Working Interest Owner. An alteration in the timing of the receipt of payment for proceeds of production from the Royalty Properties from the collection pattern normally anticipated can occur for a number of reasons beyond the Working Interest Owner's control. Such altered timing can result in: (1) wide swings in Monthly Distribution Amounts, and (2) a delay from one quarter to the next in the timing of the actual cash distribution by the Trust to the Unit holders of amounts attributable to such delayed receipts. Accordingly, the Monthly Distribution Amount for any particular month is not necessarily indicative of future Monthly Distribution Amounts which will depend on future costs incurred and revenues received.
Capital Expenditures. Although the Working Interest Owner's management believes that the Royalty Properties have potential for reserve additions from future exploration and development activities, the success of such activities cannot be assured. The value of the Royalty, and thus of the Units, will depend in part upon the level of, and the degree of success of, such activities. In the event a decision is made to explore for or develop hydrocarbons on the Royalty Properties which are not presently proved, subsequent capital expenditures required to explore for, develop and produce the reserves could be of such magnitude that they would result in the elimination or reduction of distributions to Unit holders for a substantial period of time. See "Production and Development Drilling Activities" below.
Oil and Gas Surplus and Other Marketing Factors. The prices of crude oil have fluctuated significantly in recent years primarily as a result of an oversupply of crude oil on world markets. Such surplus, as well as other factors beyond the Working Interest Owner's control may affect adversely both the availability of a ready market for production from the Royalty Properties and the sales prices received for such production. A surplus of gas deliverability continues to exist in many areas of the United States. Gas market conditions have been significantly affected by gas price competition related to this excess deliverability, price competition from alternative fuels, energy conservation and a variety of other factors.
Variation of Partnership's Interest. Although the Royalty conveyed to the Partnership is set forth in the Conveyance, the actual amount of revenues from the Royalty Properties may be increased or reduced as a result of future farmouts, unit agreements and unit operating agreements. Certain portions of the Royalty have been and other portions of the Royalty may be extinguished as leases expire as a result of the failure to establish or maintain commercial production or to pay annual rentals. In addition, the Working Interest Owner's right to revenues from a well to be drilled in the future may be extinguished or suspended as a result of "non- consent" provisions of present or future operating agreements with other working interest owners. See "Operating Agreements" below. Since the Royalty was conveyed out of working interests, distributions to the Trust will be reduced, extinguished or suspended as, when and to the extent the Working Interest Owner's right to revenues from a well is reduced, extinguished or suspended.
Operating Hazards. Operation of the Royalty Properties is subject to all the risks incident to offshore exploration for and production of oil and gas, including blowouts, cratering, fires and marine perils such as capsizing, collision and adverse weather and seas. Any of these events could result in damage to or destruction of oil and gas wells or producing facilities, suspension of operations and pollution damage. Although losses and liabilities arising from such events would not require payment by the Trust of funds previously received, they would reduce the proceeds payable thereafter with respect to the Royalty.
Ownership of Adjacent Properties. The Working Interest Owner may own interests in offshore tracts that are adjacent to or in the vicinity of, but not included in, the Royalty Properties, and it may in the future acquire additional such tracts. Drilling conducted on the Royalty Properties may provide the Working Interest Owner or any successor with valuable information regarding such other tracts, which it would then be free to develop unburdened by the Royalty and which in some cases could drain oil and gas from the Royalty Properties.
Negotiation and Amendment of Contracts. The Working Interest Owner and the purchasers of gas from the Royalty Properties have the right to enter into and amend contracts for the sale of production without the consent of the Trustee. In addition, the Working Interest Owner is responsible for the marketing of its working interest share of any commercial quantities of oil or gas produced from the Royalty Properties. Although the Working Interest Owner is generally expected to seek the highest prices obtainable for the production, its negotiations regarding future contracts and possible revisions to existing contracts may be affected by factors which are of economic significance to it but not to the Unit holders, such as the existence or anticipation of other contractual arrangements between the Working Interest Owner and the purchaser. The Working Interest Owner is entitled to make arrangements for the marketing of its share of production from the Royalty Properties independently of other working interest owners.
Transfer of Working Interest; Abandonment. The Working Interest Owner is free to transfer all or a portion of its working interest in any Royalty Property (burdened by the Royalty) to any third party in sound financial condition. The Working Interest Owner is also free to enter into farmouts on the Royalty Properties, whereby it would transfer a portion of its interest (unburdened by the Royalty) while retaining a lesser interest (burdened by the Royalty) in return for the transferee's obligation to drill a well on the Royalty Property; however, it may not enter into such farmouts on the Productive Properties except with respect to exploratory wells. The Working Interest Owner has the right to abandon any well or lease if, in its opinion, such well or lease ceases to produce or is not capable of producing in paying quantities, and upon termination of any lease, the portion of the Royalty relating thereto will be extinguished. Should a lease on one of the Royalty Properties expire, the Working Interest Owner would thereafter be free to acquire a new lease on the same block, unburdened by the Royalty.
PRODUCTION AND DRILLING ACTIVITIES
Of the 13 remaining Royalty Properties, 12 are currently producing. For a discussion concerning the oil and gas production from such properties in 1994, as well as information concerning drilling activities on such properties during 1994, see Item 7 -- Management's Discussion and Analysis of Financial Condition and Results of Operations beginning on page 30 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 (other than Vermilion Block 21/22 and West Cameron Block 65), 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. With respect to Vermilion Block 21/22 and West Cameron Block 65, the non-consenting party must assign all its working interest in the previously designated development area, subject to retention by that party of its interest in wells previously drilled in such area and an overriding royalty interest in all subsequent wells drilled in such area. 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 1994 was approximately 16 percent lower than the average price received during 1993. 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 has held several long-term gas purchase contracts with Transco. By agreement effective October 1, 1988, and amended by agreement effective October 1, 1991, the Working Interest Owner and Transco agreed to cancel most of the existing long-term contracts and to enter into new gas purchase contracts which provide for an initial fixed price which is below the prices provided for in such cancelled contracts, but above then current spot market prices, plus an agreed
escalation to such fixed price. In consideration of the Working Interest Owner agreeing to cancel such contracts, the Working Interest Owner received approximately $12.3 million attributable to the Royalty Interest, of which $3.7 million was withheld for the IDC Recapture Amount and $8.6 million was included in Gross Proceeds for the distribution attributable to Unit holders of record on January 31, 1989, plus an obligation by Transco to pay an additional amount of $9.3 million which was received by the Working Interest Owner and included in Gross Proceeds for the distribution attributable to Unit holders of record on January 31, 1992, plus the obligation by Transco to make two additional future payments which resulted in payments received by the Working Interest Owner attributable to the Royalty as follows: (1) $2.6 million plus interest at 10 percent per annum on or before January 2, 1993, which was included in the distribution paid January 29, 1993 and (2) $2.6 million plus interest at 10 percent per annum on or before January 4, 1994, of which approximately $0.5 million was used to eliminate the cost carry-forward at December 31, 1993 and approximately $1.9 million was used to partially fund the $2.4 million reserve being established for Trust administrative expenses. See additional discussion in Note 6 -- Gas Contract Settlement and Note 7 -- Establishment of an Expense Reserve. The Working Interest Owner continues to sell gas at spot market prices from those blocks that were previously subject to long-term contracts with Transco, 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.
Presently Producing Properties. Gas is currently being produced from 12 of the 13 remaining Royalty Properties. Gas production from 5 of the Royalty Properties (including West Delta Block 34 and Vermilion Block 310, which accounted for approximately 45 percent of the Working Interest Owner's revenues from the Royalty Properties during 1994) is subject to gas purchase contracts with Transco. Gas sales to Transco accounted for approximately 48 percent, 53 percent and 61 percent of the Working Interest Owner's revenues attributable to oil and gas production from the Royalty Properties in 1994, 1993 and 1992, respectively.
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. The Working Interest Owner is subject to regulation by the Federal Energy Regulatory Commission (FERC) with respect to various aspects of its natural gas operations under the Natural Gas Act of 1938 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. Consequently, the Working Interest Owner believes the Trust's gas may be sold at market prices, subject to applicable contract provisions.
Commencing in April 1992, the FERC issued Order Nos. 636, 636-A, and 636-B (Order No. 636), which require interstate pipelines to provide transportation separate, or "unbundled", from the pipelines' sales of gas. Also, Order No. 636 requires pipelines to provide open-access transportation on a basis that is equal for all gas supplies. Although Order No. 636 does not directly regulate the Working Interest Owner's activities, the FERC has stated that Order No. 636 is intended to foster increased competition within all phases of the natural gas industry. It is unclear what impact, if any, increased competition within the natural gas industry under Order No. 636 will have on the Working Interest Owner's activities. Although Order No. 636, assuming it is upheld in its entirety, could provide the Working Interest Owner with additional market access and more fairly applied transportation service rates, Order No. 636 could also subject the Working Interest Owner to more restrictive pipeline imbalance tolerances and greater penalties for violation of those tolerances. As of early 1995, FERC had issued final orders accepting most pipelines' Order No. 636 compliance filings, and had commenced a series of one year reviews of individual pipeline implementations of Order No. 636. Numerous parties have filed petitions for review of Order No. 636, as well as orders in individual pipeline restructuring proceedings. Upon such judicial review, these orders may be remanded or
reversed in whole or in part. With Order No. 636 subject to court review, and pending ongoing FERC reviews of individual pipeline restructurings, it is difficult to predict with precision its ultimate effects.
In December 1992, the FERC issued Order No. 547, governing the issuance of blanket marketer sales certificates to all natural gas sellers other than interstate pipelines. The order eliminates the need for natural gas producers and marketers to seek specific authorization under Section 7 of the NGA from the FERC to make sales of natural gas for resale. The FERC intends Order No. 547, in tandem with Order No. 636, to foster a competitive market for natural gas by giving natural gas purchasers access to multiple supply sources at market-driven prices. Order No. 547 does not apply to sales by the Trust of gas produced from its own properties, but Order No. 547 may increase competition in markets in which the Trust's natural gas is sold.
FERC has recently announced its intention to re-examine certain of its transportation-related policies, including the appropriate manner in which interstate pipelines release transportation capacity under Order No. 636, and the use of market-based rates for interstate gas transmission. While any resulting FERC action would affect the Company only indirectly, these inquires are intended to further enhance competition in natural gas markets.
Commencing in October 1993, 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 pipelines to make rate changes to track changes in the Producer Price Index for Finished Goods, minus one percent, became effective January 1, 1995. FERC's decision in this matter is currently the subject of various petitions for judicial review. 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. In addition, gathering lines are currently exempt from the FERC's jurisdiction, regardless of whether they are on the OCS, but the FERC could eliminate this exemption. Commencing in May 1994, FERC issued a series of orders in individual cases that delineate its gathering policy. Among other matters, FERC slightly narrowed its statutory tests for establishing gathering status and reaffirmed that, except in situations in which the gatherer acts in concert with an interstate pipeline affiliate to frustrate FERC's transportation policies, it does not have jurisdiction over gathering facilities and services and that such facilities and services are properly regulated by state authorities. This FERC action may further encourage regulatory scrutiny of natural gas gathering by state agencies. In addition, FERC has approved several transfers by interstate pipelines of gathering facilities to unregulated, independent or affiliated gathering companies. This could increase competition among gatherers in areas with more than one gatherer. In other areas, it may eliminate federal regulatory protection previously available. Certain FERC orders delineating its new gathering policy are subject to pending court appeals. The policies may be revised or reversed as a result. The new gathering policy thus far announced by FERC does not address its jurisdiction over pipelines operating on or across the OCS pursuant to the OCSLA. If the FERC were to apply Order No. 509 to gatherers in the OCS, eliminate the exemption of gathering lines, and redefine its jurisdiction over gathering lines, then these acts could result in a reduction in available pipeline space for existing shippers in the Gulf of Mexico and elsewhere, such as the Working Interest Owner.
Certain operations the Working Interest Owner conducts 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, and has recently proposed additional safety-related regulations concerning the design and operating procedures for OCS production platforms and pipelines. 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".
From 1986 through 1992, the Working Interest Owner entered into several gas contract settlements with a gas purchaser related to the Royalty Properties which involved payments of cash by the gas purchaser to the Working Interest Owner. The Working Interest Owner included in the calculation of Gross Proceeds the payments received in connection with these settlements, net of amounts retained in a suspense account representing settlement proceeds that were subject to possible royalty obligations to the MMS. In December 1994, the Working Interest Owner entered into an agreement with the MMS relating to these gas contract settlements, resulting in a payment by the Working Interest Owner to the MMS. After this payment, approximately $4 million of the funds retained remain in the suspense account. The Working Interest Owner has informed the Trustee that it anticipates expenditures within the near future for development operations on the Royalty Properties in excess of $4 million and, accordingly, will retain the funds remaining in the suspense account for use as payments of these anticipated expenditures, as sufficient funds may not be otherwise available. The Trustee is evaluating the legal, accounting, tax and other issues relating to the authority of the Working Interest Owner to retain such amounts for use in exploratory and development operations on the Royalty Properties.
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 are subject to extensive governmental regulation, including regulations that may in certain circumstances impose absolute liability upon lessees for cost of removal of pollution and for pollution damages resulting from their operations, and that may require lessees to pay penalties, or even to suspend or cease 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 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. These include proof of financial responsibility to cover at least some costs in a potential spill. On August 25, 1993, the MMS published an advance notice of its intention to adopt a rule under OPA that would require responsible parties for offshore oil and gas facilities to establish evidence of $150 million in financial responsibility. Under the MMS advance description of its future rulemaking, financial responsibility could be established through insurance, guaranty, indemnity, surety bond, letter of credit, qualification as a self- insurer or a combination thereof. There is substantial opposition to the proposed rulemaking throughout the offshore oil and gas industry, and the MMS has informally indicated that it will not move forward with adoption of the rule until the United States Congress has had an opportunity to reconsider financial responsibility requirements imposed under OPA. The final form of any financial responsibility rule that may be adopted by the MMS cannot be predicted at this time; however, such rule has the potential to result in the imposition of additional annual costs on the Working Interest Owner's operations.
OPA also imposes other requirements, such as preparation of an oil spill contingency plan. 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 Outer Continental Shelf Lands Act authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating on the Outer Continental Shelf. Specific design and operational standards may apply to Outer Continental Shelf vessels, rigs, platforms, vehicles and structures. Violations of environmental related lease conditions or regulations issued pursuant to the Outer Continental Shelf Lands Act 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 or citizen prosecution.
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.
At least two courts have recently 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. 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 require-
ments 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 farmout, operating, pooling and unitization agreements and to minor encumbrances, easements and restrictions. The Royalty Properties are also subject to the Outer Continental Shelf Lands Act, 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 has been 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. The Distribution will be treated for federal income tax purposes 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.
None.
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 1994.
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 New York Stock Exchange under the symbol "FMR". At March 27, 1995, 14,975,390 Units were outstanding and held of record by 14,419 Unit holders.
The high and low sales prices of the Units as reported on the New York Stock Exchange and distributable cash per Unit for each quarterly period of 1993 and 1994 were:
Distributable cash for any quarter is distributed to Unit holders in the month following the close of the quarter.
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.
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(1) Includes $2.4 million, $2.3 million, $9.3 million, $0.8 million and $5.5 million in 1994, 1993, 1992, 1991 and 1990, respectively, related to various gas contract settlements. Also includes $22.1 million in 1991 related to the reversal of the IDC recapture charges previously deducted.
(2) Includes $6.3 million paid to the Trust for interest on the IDC Recapture reversal.
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.
RESULTS OF OPERATIONS
During 1994, The Trust's portion of Royalty proceeds attributable to production from the Royalty Properties amounted to $2.6 million. After giving effect to interest income of $0.05 million and Trust administrative expenses of $0.63 million, the remaining $2.0 million was applied to the funding of a reserve for future Trust administrative expenses (See Note 7 -- Establishment of an Expense Reserve) resulting in no distribution to Unit holders.
There were no cash distributions to the Unit holders for the year ended December 31, 1994 compared with $6.3 million, or $0.42295 per Unit, for 1993. The reduced cash available for distribution was caused primarily by lower gas production, higher capital expenditures and the funding of the reserve for Trust administrative expenses partially offset by lower abandonment accruals.
Gas revenues included in the 1994 Royalty proceeds totaled $6.3 million compared with $10 million for 1993. Gas volumes decreased 36 percent to 2.8 billion cubic feet (bcf) in 1994 from 4.4 bcf in 1993 primarily because of the depletion of wells at West Delta Block 34 and East Cameron Block 336 and the depletion of the West Cameron Block 498 field, as well as normal production declines at other properties. The average gas price realization for 1994 was $2.46 per thousand cubic feet (mcf), compared with $2.54 per mcf in 1993. Gas volumes included make up of gas sold under balancing agreements totaling 0.7 bcf in both 1994 and 1993.
Oil revenues of $2 million and $1.9 million were included in Royalty proceeds for 1994 and 1993, respectively. Oil volumes increased 21 percent to 145,800 barrels (bbls) in 1994 from 120,900 bbls in 1993, primarily as a result of increased oil production at West Cameron 251. The increase in oil volumes was partially offset by a decrease in the average oil price realization to $14.97 per bbl in 1994 compared with $17.92 per bbl in 1993.
Capital costs reduced 1994 Royalty proceeds by $4.3 million, or $0.28964 per Unit, compared to a $2.4 million, or $0.16052 per Unit, reduction in 1993. This increase in capital costs for 1994 was the result of costs incurred in connection with exploratory drilling on West Delta Block 34, West Cameron Block 65 and West Cameron Block 498.
Accruals for future estimated abandonment costs reduced Royalty proceeds by $1.4 million, or $0.09188 per Unit, in 1994 compared with $3.6 million, or $0.23764 per Unit in 1993.
Cash distributions to Unit holders for the year ended December 31, 1993 amounted to $6.3 million or $0.42295 per Unit, compared to $16.1 million or $1.07296 per Unit, for 1992. The 1993 distribution reflects a 61 percent decrease, primarily due to the lower settlement payments received from a gas purchaser, higher abandonment accruals, higher capital expenditures and lower gas production in 1993.
Settlement payments received by the Trust from a natural gas purchaser (see Note 6 -- Gas Contract Settlement) totaled $2.3 million, or $0.15315 per Unit, in January 1993 compared to $9.3 million, or $0.61744 per Unit, in January 1992. As a result of the need to increase accruals for future estimated abandonment costs, distributions were reduced by $3.6 million, or $0.23764 per Unit, in 1993 compared to $1.2 million, or $0.07820 per Unit, in 1992. Capital costs reduced 1993 Royalty proceeds by $2.4 million, or $0.16052 per Unit, compared to a $0.7 million, or $0.04890 per Unit, reduction in 1992 distributions. The increase in capital costs in 1993 was the result of costs incurred in connection with exploratory drilling on West Delta Block 34.
Distributable cash for 1993 included gas revenues of $10 million compared to $10.7 million for 1992. Gas volumes decreased 13 percent to 4.4 bcf in 1993 from 5.1 bcf in 1992. This decrease was primarily due to a decrease in production on West Delta Block 34 because of platform maintenance and repairs, the depletion of a well at West Cameron Block 494 and a well at High Island Block A-552,
together with normal production declines. This decrease was mitigated by an increase in production on a recompleted gas well at West Cameron Block 215 and an $0.18 per mcf increase in the average gas price realization to $2.54 per mcf in 1993 compared to $2.36 per mcf in 1992. Gas volumes included make-up of gas sold under certain balancing agreements totaling 0.7 bcf in 1993 and 0.6 bcf in 1992.
Oil revenues of $1.9 million and $1.1 million were included in distributable cash for 1993 and 1992, respectively. Oil volumes increased to 120,900 bbls in 1993 from 64,300 bbls in 1992, primarily as a result of the increased production from a recompleted well at West Cameron Block 215. The increase in oil production was partially offset by a decrease in the average oil price realization to $17.92 per bbl in 1993 compared to $19.37 per bbl in 1992.
CAPITAL RESOURCES AND LIQUIDITY
All revenues received by the Trust, net of Trust administrative expenses and liabilities, are generally distributed to the Unit holders in accordance with provisions of the Trust Indenture. Primarily as a result of costs associated with additional seismic and exploratory drilling activity anticipated at West Cameron Block 498 and the continued funding of the reserve for Trust administrative expenses, the amount and timing of future distributions to Unit holders is presently indeterminable.
Capital expenditures associated with the exploratory activities at West Cameron Block 498 for 1995 are currently estimated to be $3.5 million net to the Trust, including the cost of the 3D seismic survey begun in November 1994. Total capital expenditures for 1995 are presently budgeted at $3.9 million net to Trust, including West Cameron Block 498 activities. However, the extent of additional future capital expenditures will depend upon the seismic and drilling results at West Cameron Block 498. Actual expenditures could vary significantly from the estimate. From 1986 through 1992, the Working Interest Owner entered into several gas contract settlements with a gas purchaser related to the Royalty Properties which involved payments of cash by the gas purchaser to the Working Interest Owner. The Working Interest Owner included in the calculation of Gross Proceeds the payments received in connection with these settlements, net of amounts retained in a suspense account representing settlement proceeds that were subject to possible royalty obligations to the MMS. In December 1994, the Working Interest Owner entered into an agreement with the MMS relating to these gas contract settlements, resulting in a payment by the Working Interest Owner to the MMS. After this payment, approximately $4 million of the funds retained remain in the suspense account. The Working Interest Owner has informed the Trustee that anticipates expenditures within the near future for development operations on the Royalty Properties in excess of $4 million and, accordingly, will retain the funds remaining in the suspense account for use as payments of these anticipated expenditures, as sufficient funds may not be otherwise available. The Trustee is evaluating the legal, accounting, tax and other issues relating to the authority of the Working Interest Owner to retain such amounts for use in exploratory and development operations on the Royalty Properties.
These cost estimates are provided by the outside operators and may vary from actual costs depending on the success of drilling, difficulties incurred and numerous other factors outside the control of the operator. The operators of the Trust properties are analyzing other capital expenditures for exploration and development activities. These expenditures would serve to reduce and could further delay resumption of distributions to Unit holders.
West Delta Block 34 Well Nos. 10 and 11 were plugged and abandoned during the first quarter of 1994 due to unexpected adverse results from production tests which were below the minimum requirements for the wells to sustain commercial production. Total capital expenditures associated with these two wells equaled $4.6 million net to the Trust, of which $2.5 million were incurred in 1994. No further drilling is presently anticipated on West Delta Block 34.
As a result of plugging and abandoning West Delta Block 34 Well No. 10, the estimated net proved undeveloped reserves of approximately 1.7 bcf of natural gas and approximately 3,000 bbls of oil, having discounted (at 10%) estimated future net cash flows of approximately $9.2 million included in
the Trust's total proved reserves at December 31, 1993, have been eliminated from the Trust's total proved reserves at December 31, 1994.
Exploratory drilling on West Cameron Block 65, which began in March 1994, was successfully completed resulting in a commercial discovery. The Well No. 7, went on production in November 1994. Estimated net proved reserves of 160,000 mcf of natural gas and 2,500 bbls of oil, having discounted (at 10%) estimated future net cash flows of approximately $0.5 million were assigned to this well.
In June 1994, an exploratory well at West Cameron Block 498, Well No. 2, was drilled and temporarily abandoned after discovering approximately 760 feet of net hydrocarbon pay. In July 1994, a second exploratory well, No. 3, was drilled and temporarily abandoned after penetrating a separate fault block and encountering approximately 150 feet of net hydrocarbon pay from multiple sand reservoirs, some of which were encountered by the No. 2 Well. All the Working Interest Owners of West Cameron Block 498 are participating in a 3D seismic survey of the block which is expected to be completed during the second quarter of 1995. The results of this survey will be used to optimize the location and extent of future drilling. The results of this additional drilling will help determine the location, size and capacity of the platform and facilities required to produce and market these reserves. At December 31, 1994, costs associated with the exploration activities at West Cameron Block 498 resulted in a cumulative cost carry-forward of $476,435. In February 1995, Royalty proceeds were more than sufficient to eliminate the then cumulative cost carry-forward of $281,912 with the excess being applied towards the funding of the reserve for future Trust administrative expenses bringing the balance of the reserve to $2.1 million at February 28, 1995.
Due to the lack of Royalty income in late 1993 and 1994, the Trust was 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 in January 1994 a $2.4 million Trust administrative expense reserve to pay such expenses (see Note 7 -- Establishment of an Expense Reserve), of which $2 million had been funded through December 1994.
In January 1994, the Trust received from the Working Interest Owner $2.9 million representing the Trust's share of the final scheduled payment pursuant to the gas contract settlement. After a reduction for an allocable portion of estimated future abandonment costs, $0.5 million of the remaining $2.4 million was used to eliminate the cumulative cost carry-forward at December 31, 1993, and $1.9 million was used to partially fund the reserve for Trust administrative expenses. Accordingly, no distribution was made to Unit holders for the month of January 1994. Unit holders should be aware of the tax consequences regarding these matters. Additional discussion can be found in Note 6 -- Gas Contract Settlement, Note 7 -- Establishment of an Expense Reserve and Note 8 -- Federal Income Tax Matters.
The operators of the Trust properties have provided escalated estimates of future costs to abandon the Trust properties upon their depletion. See Note 9 -- Reserve for Future Estimated Abandonment Costs and Note 10 -- Supplementary Proved Oil and Gas Reserve Information. In December 1994, such estimates, net of abandonment cost incurred, totaled $13.6 million net to the Trust, of which $12.8 million net to the Trust has been withheld from distributions to Unit holders as of December 31, 1994. Based on the revised estimated future abandonment costs, future distributions to Unit holders will be reduced by approximately $0.05 per Unit over the remaining productive lives of the properties, subject to future revisions of such costs. In the first quarter of 1995, $0.01066 per Unit was deducted for estimated abandonment costs.
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. THE TRUST
Freeport-McMoRan Oil and Gas Royalty Trust (the Trust) was created effective September 30, 1983. On that date, Freeport-McMoRan Inc. (FTX) transferred a net overriding royalty interest in certain offshore oil and gas properties to a Partnership (Partnership) 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. See "The Royalty Properties and the Royalty -- Computation of the Royalty". 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 Texas Commerce Bank National Association 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.
2. THE ROYALTY
Freeport-McMoRan Oil & Gas Company (FMOG), Division of FTX (the Working Interest Owner), presently 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).
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The Trust financial statements, which reflect the Trust's 99.9 percent interest in the Partnership as though the Partnership did not exist, 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 generally accepted accounting principles, revenues and expenses would be recognized on an accrual basis.
The initial carrying amount of the Royalty represents FTX'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 is 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 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. Neither the initial carrying value nor the remaining unamortized balance at December 31, 1994 is necessarily indicative of the fair market value of the Royalty held by the Trust.
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.
FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
4. DISTRIBUTIONS TO UNIT HOLDERS
As a result of the capital costs associated with drilling on West Delta Block 34, West Cameron Block 65 and West Cameron Block 498 as well as the funding of a reserve for Trust administrative expenses (Note 7), there were no distributions during 1994. At December 31, 1994 there was a cumulative excess Class A cost carry-forward of $476,435 net to the Trust, related to the drilling on West Cameron Block 498.
5. 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 Adjusted 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. 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, 1994, the unrecovered quantity of gas sold by third parties pursuant to such gas balancing arrangements during the period from October 1, 1983 through September 30, 1994 was approximately 2 billion cubic feet (bcf), net to the Trust. Under the terms of the Conveyance, Adjusted Gross Proceeds will 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 is uncertain.
6. GAS CONTRACT SETTLEMENT
Pursuant to a gas contract settlement agreement effective October 1, 1988, and amended by an agreement effective October 1, 1991, settlement payments of $9.3 million (approximately $0.62 per Unit) and $2.3 million (approximately $0.15 per Unit) were included in distributions paid to Unit holders of record on January 31, 1992 and January 29, 1993, respectively. In January 1994, the Trust received from the Working Interest Owner $2.9 million representing the Trust's share of the final scheduled payment resulting from this settlement. After a reduction for an allocable portion of estimated future abandonment costs, the remaining $2.4 million, approximately $0.16 per Unit, was used to eliminate the cumulative cost carry-forward at December 31, 1993 and to partially fund the reserve for Trust administrative expenses described in Note 7 below. As a result, no distribution was made to Unit holders in connection with this settlement payment.
From 1986 through 1992, the Working Interest Owner entered into several gas contract settlements with a gas purchaser related to the Royalty Properties which involved payments of cash by the gas purchaser to the Working Interest Owner. The Working Interest Owner included in the calculation of Gross Proceeds the payments received in connection with these settlements, net of amounts retained in a suspense account representing settlement proceeds that were subject to possible royalty obligations to the Minerals Management Service (the MMS). In December 1994, the Working Interest Owner entered into an agreement with the MMS relating to these gas contract settlements, resulting in a payment by the Working Interest Owner to the MMS. After this payment, approximately $4 million of the funds retained remain in the suspense account. The Working Interest Owner has informed the Trustee that it anticipates expenditures within the near future for development operations on the Royalty Properties in excess of $4 million and, accordingly, will retain the funds remaining in the suspense account for use as payments of these anticipated expenditures, as sufficient funds may not be otherwise available. The Trustee is evaluating the legal, accounting, tax and other issues relating to the
FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
authority of the Working Interest Owner to retain such amounts for use in exploratory and development operations on the Royalty Properties.
7. ESTABLISHMENT OF AN EXPENSE RESERVE
Because of the lack of current Royalty income, the Trust has been unable to pay its ongoing administrative expenses. To permit the Trust to pay its routine administrative expenses during the time the Trust incurs a Class A cost deficit, the Trustee, in accordance with the Trust Indenture, is establishing an expense reserve of approximately $2.4 million to cover approximately 3 years of Trust expenses. This reserve was partially funded with $1.9 million from the January 1994 settlement payment described in Note 6 above, and a portion has been funded from Royalty income. The remaining $0.3 million will be funded from future Royalty income received by the Trust prior to making any distribution to Unit holders. As a result of the capital expenditures described in "Capital Resources and Liquidity" above and the continued funding of the Trust administrative expense reserve the amount and timing of future distributions to Unit holders is presently indeterminable. In addition, there will be tax consequences for the Unit holders as described in Note 8 below.
The funding for this reserve is deposited with Texas Commerce Bank and invested in Texas Commerce Bank collateralized certificates of deposit.
The average interest rate earned on these funds for 1994 was 2.8 percent.
8. FEDERAL INCOME TAX MATTERS
The Working Interest Owner began accruing an estimate of IDC Recapture Amount pursuant to the Conveyance effective with the May 1987 distribution. The IDC Recapture Amount is intangible drilling cost (IDC) recapture income (IDC Recapture Income) recognized (or considered to be incurred, pursuant to the Conveyance) by the Company in connection with the original distribution of the Units, but not to exceed $13.9 million plus interest and penalties attributable thereto (IDC Recapture Amount). In September 1991, the tax issue with the Internal Revenue Service (Service) relating to the recapture of IDC in connection with the creation of the Trust was resolved in a manner favorable to the Trust. As a result, the royalty amounts paid to the Trust on October 31, 1991 were based on a computation which took into account the reversal of IDC recapture charges previously deducted, plus associated interest, and therefore $28,398,517, or $1.89634 per Unit, was included as part of the Trust's October distribution amount, to which Unit holders of record at October 31, 1991 were entitled. The October distribution amount plus interest was paid to such Unit holders on January 10, 1992, the regular quarterly payment date. For tax purposes such distribution was deemed received by Unit holders in 1991. In computing royalty amounts payable in future months, no IDC recapture charges will be deducted.
In January 1994, the Trust received from the Working Interest Owner its share of the final scheduled payment made pursuant to the gas contract settlement as described in Note 6 above. Unit holders will be required to report taxable income attributable to the gas contract settlement payment even though no distributions attributable to such payment were received by the Unit holders. The expense reserve established for Trust administrative expenses described in Note 7 above, however, will give rise to future tax deductions as additional administrative expenses are incurred.
9. RESERVE FOR FUTURE ESTIMATED ABANDONMENT COSTS
The operators of the Trust properties have provided estimates of future costs to abandon the Trust properties upon their depletion. The December 1994 escalated estimate, net of abandonment costs incurred, totals $13.6 million net to the Trust, of which $12.8 million net to the Trust had been withheld from distributions to Unit holders as of December 31, 1994. The actual costs to abandon the
FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Trust properties may vary from these estimates. Any excess will reduce future distributions and, to the extent that actual costs are less than amounts withheld, amounts will be added to distributable cash.
10. SUPPLEMENTARY PROVED OIL AND GAS RESERVE INFORMATION (UNAUDITED)
Pursuant to the Financial Accounting Standards Board's (FASB) 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 necessarily 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 Petroleum Engineers (Ryder Scott) as of December 31, 1994, 1993 and 1992. The reports were based on estimated production and costs after December 31, 1994, 1993 and 1992, respectively. In preparing its December 31, 1994, 1993 and 1992 estimates, Ryder Scott did not take into account (a) revenues received after November 30, 1994, 1993 and 1992 attributable to production during the fourth quarter of the respective year, (b) as of December 31, 1994, 1993 and 1992, approximately 2.0 bcf, 2.7 bcf and 3.4 bcf sold by other parties pursuant to certain gas balancing arrangements and (c) as of December 31, 1993 and December 31, 1992 approximately $2.6 million plus interest and $5.2 million plus interest, respectively, to be received in connection with the Transco gas contract settlement. In connection with such settlement, $2.3 million, net of $0.8 million withheld for estimated future abandonment costs, and $9.3 million were included in distributions paid to Unit holders of record January 29, 1993 and January 31, 1992, respectively. In addition, $2.9 million, approximately $2.4 million after a reduction for an allocable portion of estimated future abandonment costs, was received in January 1994. A portion of such amount was used to eliminate the cumulative cost carry-forward at December 31, 1993 and the remaining $1.9 million was used to partially fund the $2.4 million reserve being established for Trust administrative expenses, resulting in no distribution to Unit holders for the month of January 1994. For purposes of the reserve volume and cash flow amounts set forth below, the Trustee adjusted the December 31, 1994, 1993 and 1992, estimates of Ryder Scott to take into account the foregoing factors, based on calculations supplied by the Working Interest Owner.
As discussed in Note 9, based on escalated estimates of costs to abandon the Trust properties, approximately $0.8 million remains to be deducted from future distributions to cover abandonment costs. For purposes of the reserve volume and cash flow amount set forth below, Ryder Scott has not considered these future deductions based on escalated estimates, nor has the Trustee adjusted 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 for the years ended December 31, 1994, 1993 and 1992, respectively. Oil, including crude oil, condensate and natural gas liquids, is stated in thousands of barrels; gas is stated in millions of cubic feet.
Although the exploratory drilling at West Cameron Block 498 resulted in the discovery of significant hydrocarbons, the block is considered unevaluated as of December 31, 1994 and therefore, no proved reserves have been assigned. Further drilling based on the results of the 3D seismic survey will help to determine the extent of these reserves. ------------
(1) Revisions of previous estimates confirm that 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.
(2) Extensions and discoveries include reserves related to West Delta Block 34 No. 10 in 1993, which was plugged and abandoned in April 1994 after unsuccessful attempts to complete the well and reserves related to West Cameron Block 65 No. 7 in 1994.
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 the proceeds to be received from underdelivered gas (see Note 5 above) and the proceeds received from the 1994 Transco gas contract settlement payment (see Note 6 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.
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:
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(1) Includes approximately $2.6 million plus interest and $5.2 million plus interest at December 31, 1993 and December 31, 1992, respectively, related to a gas contract settlement (See Note 6 above).
(2) Extensions and Discoveries include discounted future net cash flow related to West Delta Block 34 No. 10 in 1993, which was plugged and abandoned in April 1994 after unsuccessful attempts to complete the well and in 1994 is reflected in Changes in Prices and other. Extensions and Discoveries for 1994 include discounted future net cash flow related to West Cameron Block 65 No. 7 in 1994.
(3) "Accretion of discount" reflects the change in discounted present value due to the passage of time.
FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Texas Commerce Bank National Association (Trustee) and the Unit Holders of Freeport-McMoRan Oil and Gas Royalty Trust:
We have audited the statements of assets, liabilities and trust corpus of Freeport-McMoRan Oil and Gas Royalty Trust as of December 31, 1994 and 1993, 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, 1994. These financial statements are the responsibility of the Trustee and the General Partner of the Royalty Partnership. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 3, these financial statements were prepared on the cash basis of accounting which is a comprehensive basis of accounting other than generally accepted accounting principles.
In our opinion, the financial statements referred to above present fairly, in all material respects, the assets, liabilities and trust corpus of Freeport-McMoRan Oil and Gas Royalty Trust as of December 31, 1994 and 1993, and the royalty proceeds and distributable cash, and changes in trust corpus for each of the three years in the period ended December 31, 1994, on the cash basis of accounting described in Note 3.
ARTHUR ANDERSEN LLP
New Orleans, Louisiana, March 3, 1995
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 holders of the Units.
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
Texas Commerce Bank National Association, as Trustee of the Trust, owns no Units. Texas Commerce Bank 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.
Texas Commerce Bank National Association, which also acts as Trustee of the Trust, and its parent, Chemical Banking Corporation, have 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 by the registrant during the fourth quarter of 1994.
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: TEXAS COMMERCE BANK NATIONAL ASSOCIATION, Trustee
By: _________________________________ Michael J. Ulrich Vice President and Trust Officer
March 27, 1995
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.