ITEM 1. BUSINESS.
DESCRIPTION OF THE TRUST
GENERAL
The TEL Offshore Trust ("Trust"), created under the laws of the State of Texas, maintains its offices at the office of the Corporate Trustee, Chase Bank of Texas, National Association (formerly known as Texas Commerce Bank National Association) ("Corporate Trustee"), 712 Main Street, Houston, Texas 77002. The telephone number of the Trust is 713-216-5712. George Allman, Jr., W. Leslie Duffy and Richard L. Melton serve as individual trustees ("Individual Trustees") of the Trust. The Individual Trustees and the Corporate Trustee may hereinafter collectively be referred to as Trustees.
The principal asset of the Trust consists of a 99.99% interest in the TEL Offshore Trust Partnership ("Partnership"). Chevron U.S.A. Inc. ("Chevron") owns the remaining .01% interest in the Partnership. The Partnership owns an overriding royalty interest ("Royalty"), equivalent to a 25% net profits interest, in certain oil and gas properties (the "Royalty Properties") located offshore Louisiana.
On November 18, 1988, Chevron acquired most of the Gulf of Mexico offshore oil and gas properties of Tenneco Oil Company ("Tenneco"), including all the Royalty Properties. As a result of the acquisition, Chevron replaced Tenneco as the Working Interest Owner and Managing General Partner of the Partnership. Chevron also assumed Tenneco's obligations under the instrument conveying the Royalty to the Partnership (the "Conveyance").
On October 30, 1992, Pennzoil Company ("Pennzoil") acquired certain oil and gas producing properties from Chevron, including four of the Royalty Properties. The four Royalty Properties acquired by Pennzoil were East Cameron 354, Eugene Island 348, Eugene Island 367 and Eugene Island 208. As a result of such acquisition, Pennzoil replaced Chevron as the Working Interest Owner of such properties on October 30, 1992. Pennzoil also assumed Chevron's obligations under the Conveyance with respect to such properties.
On December 1, 1994, Texaco Exploration and Production Inc. ("Texaco") acquired one of the Royalty Properties from Chevron. The Royalty Property acquired by Texaco was West Cameron 643. As a result of such acquisition, Texaco replaced Chevron as the Working Interest Owner of such property on December 1, 1994. Texaco also assumed Chevron's obligations under the Conveyance with respect to such property.
On October 1, 1995, SONAT Exploration Company ("SONAT") acquired the East Cameron 354 property from Pennzoil. In addition, on October 1, 1995, Amoco Production Company ("Amoco") acquired the Eugene Island 367 property from Pennzoil. As a result of such acquisitions, SONAT and Amoco replaced Pennzoil as the Working Interest Owners of the East Cameron 354 and Eugene Island 367 properties, respectively, on October 1, 1995, and also assumed Pennzoil's obligations under the Conveyance with respect to such properties.
Effective January 1, 1998 Energy Resource Technology, Inc. ("Energy") acquired the East Cameron 354 property from SONAT. As a result of such acquisition, Energy replaced SONAT as the Working Interest Owner of the East Cameron 354 property effective January 1, 1998, and also assumed SONAT's obligations under the Conveyance with respect to such property.
Chevron remains the Managing General Partner of the Partnership. The Royalty Properties continue to be subject to the Royalty, and the Trust and Partnership, in general, continue to operate as if the above-described sales of the Royalty Properties had not occurred.
Unless the context in which such terms are used indicates otherwise, the terms "Working Interest Owner" and "Working Interest Owners" as used herein generally refer to the owner or owners of the Royalty Properties (Tenneco Exploration, Ltd. through October 31, 1986; Tenneco for periods from October 31, 1986 until November 18, 1988; Chevron with respect to all Royalty Properties for periods from
November 18, 1988 until October 30, 1992, and with respect to all Royalty Properties except East Cameron 354, Eugene Island 348, Eugene Island 367 and Eugene Island 208 for periods from October 30, 1992 until December 1, 1994, and with respect to the same properties except West Cameron 643 thereafter; Pennzoil with respect to East Cameron 354, Eugene Island 348, Eugene Island 367 and Eugene Island 208 for periods from October 30, 1992 until October 1, 1995, and with respect to Eugene Island 348 and Eugene Island 208 thereafter; Texaco with respect to West Cameron 643 for periods beginning on or after December 1, 1994; SONAT with respect to East Cameron 354 for periods from October 1, 1995 until January 1, 1998; Amoco with respect to Eugene Island 367 for periods beginning on or after October 1, 1995; and Energy with respect to East Cameron 354 for periods beginning on or after January 1, 1998).
A total of 4,751,510 units of beneficial interest in the Trust ("Units") are issued and outstanding. On October 22, 1996, the Trust Units were delisted from the National Association of Securities Dealers Automated Quotation System ("NASDAQ") SmallCap Market. The delisting was a result of a determination by NASDAQ that the Trust would not be able to sustain long-term compliance with NASDAQ continued listing standards. The Trust has been advised by NASDAQ that the Trust Units are being traded on the OTC Bulletin Board. The Trust Units may also be traded on pink sheets. From inception of the Trust to December 31, 1997, distributions to Unit holders totaled approximately $74,773,000, or approximately $15.73 per Unit.
The terms of the TEL Offshore Trust Agreement (the "Trust Agreement") provide, among other things, that: (1) the Trust is a passive entity whose activities are generally limited to the receipt of revenues attributable to the Trust's interest in the Partnership and the distribution of such revenues, after payment of or provision for Trust expenses and liabilities, to the owners of the Units; (2) the Trustees may sell all or any part of the Trust's interest in the Partnership or cause the sale of all or any part of the Royalty by the Partnership with the approval of a majority of the Unit holders; (3) the Trustees can establish cash reserves and can borrow funds to pay liabilities of the Trust and can pledge the assets of the Trust to secure payment of such borrowings; (4) to the extent cash available for distribution exceeds liabilities or reserves therefor established by the Trust, the Trustees will cause the Trust to make quarterly cash distributions to the Unit holders in January, April, July and October of each year; and (5) the Trust will terminate upon the first to occur of the following events: (i) total future net revenues attributable to the Partnership's interest in the Royalty, as determined by independent petroleum engineers, as of the end of any year, are less than $2 million or (ii) a decision to terminate the Trust by the affirmative vote of Unit holders representing a majority of the Units. Total future net revenues attributable to the Partnership's interest in the Royalty were estimated at $24.3 million as of October 31, 1997. (See "Termination of the Trust" and Note 9 of the Notes to Financial Statements under Item 8 of this Form 10-K for further information regarding estimated future net revenues.) Upon termination of the Trust, the Trustees will sell for cash all the assets held in the Trust estate and make a final distribution to Unit holders of any funds remaining after all Trust liabilities have been satisfied.
The terms of the Agreement of General Partnership of the Partnership (the "Partnership Agreement") provide that the Partnership shall dissolve upon the occurrence of any of the following: (a) December 31, 2030, (b) the election of the Trust to dissolve the Partnership, (c) the termination of the Trust, (d) the bankruptcy of the Managing General Partner of the Partnership, (e) the dissolution of the Managing General Partner or its election to dissolve the Partnership; provided that the Managing General Partner has agreed not to elect to dissolve the Partnership.
Under the Conveyance and the Partnership Agreement, the Trust is entitled to its share (99.99%) of 25% of the Net Proceeds, as hereinafter defined, realized from the sale of the oil, gas and associated hydrocarbons when produced from the Royalty Properties. See "Description of Royalty Properties." The Conveyance provides that the Working Interest Owners will calculate, for each quarterly period commencing the first day of February, May, August and November, an amount equal to 25% of the Net Proceeds from its oil and gas properties for the period. "Net Proceeds" means for each quarterly period, the excess, if any, of the Gross Proceeds, as hereinafter defined, for such period over Production Costs, as hereinafter
defined, for such period. "Gross Proceeds" means the amounts received by the Working Interest Owners from the sale of oil, gas and associated hydrocarbons produced from the properties burdened by the Royalty, subject to certain adjustments. Gross Proceeds do not include amounts received by the Working Interest Owners as advance gas payments, "take-or-pay" payments or similar payments unless and until such payments are extinguished or repaid through the future delivery of gas. "Production Costs" means, generally, costs incurred on an accrual basis by the Working Interest Owners in operating the Royalty Properties, including capital and non-capital costs. In general, Net Proceeds are computed on an aggregate basis and consist of the aggregate proceeds to the Working Interest Owners from the sale of oil and gas from the Royalty Properties less (a) all direct costs, charges and expenses incurred by the Working Interest Owners in exploration, production, development, drilling and other operations on the Royalty Properties (including secondary recovery operations); (b) all applicable taxes (including severance and ad valorem taxes) excluding income taxes; (c) all operating charges directly associated with the Royalty Properties; (d) an allowance for costs, computed on a current basis at a rate equal to the prime rate of The Chase Manhattan Bank (National Association) plus 1/2% on all amounts by which, and for only so long as, costs and expenses for the Royalty Properties incurred for any quarter have exceeded the proceeds of production from such Royalty Properties for such quarter; (e) applicable charges for certain overhead expenses as provided in the Conveyance; (f) the management fees and expense reimbursements owing the Working Interest Owners; and (g) a special cost reserve for the future costs to be incurred by the Working Interest Owners to plug and abandon wells and dismantle and remove platforms, pipelines and other production facilities from the Royalty Properties and for future drilling projects and other estimated future capital expenditures on the Royalty Properties. The Trustees are not obligated to return any royalty income received in any period, but future amounts otherwise payable shall be reduced by the amount of any prior overpayments of such royalty income. The Working Interest Owners are required to maintain books and records sufficient to determine amounts payable under the Royalty. The Working Interest Owners are also required to deliver to the Corporate Trustee a statement of the computation of Net Proceeds no later than the tenth business day prior to the quarterly record date.
The Royalty Properties are required to be operated in accordance with standards applicable to a prudent oil and gas operator. The Working Interest Owners are free to transfer their working interest in any of the Royalty Properties (burdened by the Royalty) to third parties. The Working Interest Owners are also free to enter into farm-out agreements whereby a Working Interest Owner 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 Properties. The Working Interest Owners have the right to abandon any well or lease and upon termination of any lease, the part of the Royalty relating thereto will be extinguished. The Royalty Properties are primarily operated by the Working Interest Owners although certain other parties operate some of the Royalty Properties.
The discussions of terms of the Trust Agreement, Partnership Agreement and Conveyance contained herein are qualified in their entirety by reference to the Trust Agreement, Partnership Agreement and Conveyance themselves, which are exhibits to this Form 10-K and are available upon request from the Corporate Trustee.
The Trust has no employees. Administrative functions of the Trust are performed by the Corporate Trustee.
HISTORY OF THE TRUST
Tenneco Offshore Company, Inc. ("Tenneco Offshore") created the Trust effective January 1, 1983, pursuant to a Plan of Dissolution ("Plan"), which was approved by Tenneco Offshore's stockholders on December 22, 1982. In accordance with the Plan, the assets of Tenneco Offshore were transferred to the Trust as of January 1, 1983, and Units were exchanged for shares of common stock of Tenneco Offshore on the basis of one Unit for each share of common stock held by stockholders of record on January 14, 1983. Additionally, the Partnership was formed, in which the Trust owned a 99.99% interest and Tenneco owned a .01% interest. The Partnership was formed solely for the purpose of owning the Royalty, receiving the proceeds from the Royalty, paying the liabilities and expenses of the Partnership and disbursing remaining
revenues to the Trust and the Managing General Partner of the Partnership in accordance with their interests. The Plan was effected by transferring an overriding royalty interest equivalent to a 25% net profits interest in the oil and gas properties of Tenneco Exploration, Ltd. ("Exploration I") located offshore Louisiana to the Partnership, contributing the common stock of Tenneco Offshore II Company ("Offshore II") to the Trust, and issuing certificates evidencing Units in liquidation and cancellation of Tenneco Offshore's common stock.
On October 31, 1986, Exploration I was dissolved and the oil and gas properties of Exploration I were distributed to Tenneco subject to the Royalty. Tenneco, who was then serving as the Managing General Partner of the Partnership, assumed the obligations of Exploration I, including its obligations under the Conveyance. The dissolution of Exploration I had no impact on future cash distributions to Unit holders.
As discussed above, on November 18, 1988, Chevron replaced Tenneco as the Working Interest Owner and Managing General Partner of the Partnership and assumed Tenneco's obligations under the Conveyance. On October 30, 1992, Pennzoil acquired certain oil and gas producing properties from Chevron, including four of the Royalty Properties. The four Royalty Properties acquired by Pennzoil were East Cameron 354, Eugene Island 348, Eugene Island 367 and Eugene Island 208. As a result of such acquisition, Pennzoil replaced Chevron as the Working Interest Owner of such properties and assumed Chevron's obligations under the Conveyance with respect to such properties on October 30, 1992. On December 1, 1994, Texaco acquired one of the Royalty Properies from Chevron. The Royalty Property acquired by Texaco is West Cameron 643. As a result of such acquisition, Texaco replaced Chevron as the Working Interest Owner of such property and assumed Chevron's obligations under the Conveyance with respect to such property on December 1, 1994. On October 1, 1995, SONAT and Amoco acquired the East Cameron 354 and Eugene Island 367 properties, respectively, from Pennzoil. As a result of such acquisitions, SONAT and Amoco replaced Pennzoil as the Working Interest Owners of the East Cameron 354 and Eugene Island 367 properties, respectively, and also assumed Pennzoil's obligations under the Conveyance with respect to such properties on October 1, 1995. Effective January 1, 1998 Energy acquired the East Cameron 354 property from SONAT. As a result of such acquisition, Energy replaced SONAT as the Working Interest Owner of the East Cameron 354 property and also assumed SONAT's obligations under the Conveyance with respect to such property effective January 1, 1998.
DESCRIPTION OF THE UNITS
Each Unit is evidenced by a transferable certificate issued by the Corporate Trustee, which ranks equally as to distributions and has one vote on any matter submitted to Unit holders. Each Unit represents an undivided interest in the Trust, which in turn owns a 99.99% interest in the Partnership.
DISTRIBUTIONS
The Trustees distribute the Trust's income pro rata for each calendar quarter within 10 days after the end of each such quarter. Distributions of the Trust's income are made to Unit holders of record on the Quarterly Record Date, which is the last business day of each quarterly period, or such later date as the Trustees determine is required to comply with legal requirements. The Trustees determine for each quarterly period the amount available for distribution. Such amount (the "Quarterly Income Amount") consists of the cash received from the Royalty during such quarterly period plus any other cash receipts of the Trust, less the obligations of the Trust paid during such quarterly period, and adjusted for changes made by the Trust during such quarter in any cash reserves established for the payment of contingent or future obligations of the Trust. For a discussion of the cash reserves being established by the Trust, see "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources" in Item 7 of this Form 10-K.
Within 90 days of the close of each year, the net federal taxable income of the Trust for each quarterly period ending in such year is reported by the Trustees for federal tax purposes to the Unit holder of record to whom the Quarterly Income Amount was distributed.
POSSIBLE REQUIREMENT THAT UNITS BE DIVESTED
The Trust Agreement imposes no restrictions based on nationality or other status of the persons or other entities who are eligible to hold Units. However, the Trust Agreement provides that if at any time the Trust or any of the Trustees are named as a party in any judicial or administrative or other governmental proceeding which seeks the cancellation or forfeiture of any interest in any property located in the United States in which the Trust has an interest because of the nationality or any other status of any one or more owners of Units, or if at any time the Trustees in their reasonable discretion determine that such a proceeding is threatened or likely to be asserted and the Trust has received an opinion of counsel stating that the party asserting or likely to assert the claims has a reasonable probability of succeeding in such claim, the following procedures will be applicable:
(a) The Trustees, in their discretion, may seek from an investment banking firm to be selected by the Trustees an opinion as to whether it is in the Trust's best interest for the Trustees to take the actions permitted by (b)(i) through (iii) below.
(b) The Trustees may take no action with respect to the potential cancellation or forfeiture or may seek to avoid such cancellation or forfeiture by the following procedure:
(i) The Trustees will promptly give written notice ("Notice") to each record owner of Units as to the existence of or probable assertion of such controversy. The Notice will contain a reasonable summary of such controversy, will include materials which will permit an owner of Units to promptly confirm or deny to the Trustees that such owner is a person whose nationality or other status is or would be an issue in such a proceeding ("Ineligible Holder") and will constitute a demand to each Ineligible Holder that he dispose of his Units, to a party who would not be an Ineligible Holder, within 30 days after the date of the Notice.
(ii) If an Ineligible Holder fails to dispose of his Units as required by the Notice, the Trustees will have the right to redeem and will redeem, during the 90 days following the termination of the 30-day period specified in the Notice, any Unit not so transferred for a cash price equal to the mean between the closing bid and ask prices of the Units in the over-the-counter market or, if the Units are then listed on a stock exchange, the closing price of the Units on the largest stock exchange on which the Units are listed, on the last business day prior to the expiration of the 30-day period stated in the Notice. The procedures for any such purchase are
more fully described in the Trust Agreement. The Trustee shall cancel any Units acquired in accordance with the foregoing procedures thereby increasing the proportionate interest in the Trust of other holders of Units.
(iii) The Trustees may, in their sole discretion, cause the Trust to borrow any amounts required to purchase Units in accordance with the procedures described above.
LIABILITY OF UNIT HOLDERS
It is the intention of the Working Interest Owners and the Trustees that the Trust be an "express trust" under the Texas Trust Act. Under Texas law, beneficiaries of an express trust are not personally liable for the obligations of the trust, even if the assets of the trust are insufficient to discharge its obligations. However, it is unclear under Texas law whether the Trust will be held to constitute an express trust and, if it is not held to be an express trust, whether the holders of Units would be jointly and severally liable for the obligations of the Trust as would general partners of a partnership.
Under current judicial decisions, the Federal Energy Regulatory Commission ("FERC") is not considered to be empowered to compel refunds from overriding royalty interest owners with respect to gas price overcharges. However, future laws, regulations or judicial decisions might permit the FERC or other governmental agencies to require such refunds from overriding royalty interest owners or create filing, reporting or certification obligations with respect to a trust created for such overriding royalty interest owners. Moreover, other parties, such as oil or gas purchasers, may be able to instigate private lawsuits or other legal action to compel refunds from overriding royalty interest owners with respect to oil or gas pricing overcharges.
The Working Interest Owners have agreed that they will not seek to recover from the Unit holders the amount of any refunds they are required to make except out of future revenues payable to the Trust. The Trustees will be liable to the Unit holders if the Trustees allow any liability to be incurred without taking any and all action necessary 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 will be non-recourse to the Unit holders. However, the Trustees will not be liable to the 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. The Trustees will be indemnified from the Trust assets, to the extent that the Trustees' actions do not constitute gross negligence, fraud or misconduct.
Each Unit holder should consider, in weighing the possible exposure to liability in the event the Trust were not classified as an express trust, (a) the substantial value and passive nature of the Trust assets, (b) the restrictions on the power of the Trustees to incur liabilities on behalf of the Trust and (c) the limited activities to be conducted by the Trustees.
FEDERAL INCOME TAX MATTERS
OWNERSHIP OF UNITS
The IRS has ruled that the Trust is a grantor trust and that the Partnership is a partnership for federal income tax purposes. Thus, the Trust will incur no federal income tax liability, each Unit holder will be treated as owning an interest in the Partnership and each Unit holder of record as of the last business day of each quarter will be allocated a share of the income and deductions of the Trust, including the Trust's share of the income and deductions of the Partnership (computed on an accrual basis), for such quarter. Also, each Unit holder will be entitled to compute cost depletion with respect to his share of income from the Royalty based on his basis in the Royalty. A Unit holder will have a basis in the Royalty equal to the basis in his Units. Unit holders that acquired Units after October 11, 1990, are entitled to percentage depletion on Royalty income attributable to such Units.
Since the IRS has ruled that the Trust is a grantor trust and that the Partnership is a partnership for federal income tax purposes, the Trustees will treat each Unit holder as owning an interest in the Partnership and will report to the Unit holders in a manner consistent with the Trust Agreement and the Partnership Agreement, allocating income and deductions of the Partnership and the Trust for each quarter to the Unit
holders of record as of the last business day of such quarter. Also, since the IRS has ruled that the Royalty is a non-operating economic interest giving rise to income subject to depletion, the Trustees will treat the Royalty as a single property giving rise to income subject to depletion, although the computation of depletion will be made by each Unit holder based upon information provided by the Trustees.
The Tax Reform Act of 1986 made significant changes as to the classification of certain income and expense items. Royalty income is considered portfolio income. Since all income from the Partnership is royalty income, this amount, net of depletion, is portfolio income and, subject to certain exceptions and transitional rules, such royalty income cannot be offset by losses from passive businesses. Additionally, interest income is portfolio income. Administrative expense is an investment expense.
BACKUP WITHHOLDING
Distributions from the Trust are generally subject to backup withholding at a rate of 31% of such distributions. Backup withholding will not normally apply to distributions to a Unit holder, however, unless such Unit holder fails to properly provide to the Trust his taxpayer identification number ("TIN") or the IRS notifies the Trust that the TIN provided by such Unit holder is incorrect.
SALE OF UNITS
Generally, except for recapture items, the sale, exchange or other disposition of a Unit will result in capital gain or loss measured by the difference between the basis in the Unit and the amount realized. Such gain or loss would be capital gain or loss if such Unit was held by the Unit holder as a capital asset. For units sold on or prior to May 6, 1997, such capital gain will be long-term if such Unit holder's holding period exceeded one year as of the date of sale or exchange. The Taxpayer Relief Act of 1997 reduced the maximum capital gains rate to 20% for capital assets sold after May 6, 1997, but the holding period necessary to qualify for the reduced rate increased to eighteen months effective for sales after July 28, 1997. A special "mid-term" rate (generally 28%) applies to capital assets sold after July 28, 1997 with a holding period of over one year but not over eighteen months. Effective for property placed in service after December 31, 1986, the amount of gain, if any, realized upon the disposition of oil and gas property is treated as ordinary income to the extent of the intangible drilling and development costs incurred with respect to the property and depletion claimed with respect to such property to the extent it reduced the taxpayer's basis in the property. Depletion attributable to a positive Section 743(b) basis adjustment of a Unit acquired after 1986 will also be subject to recapture as ordinary income upon disposition of the Unit or upon disposition of the oil and gas property to which the depletion is attributable. The balance of any gain or any loss will be capital gain or loss if such Unit was held by the Unit holder as a capital asset.
FOREIGN UNIT HOLDERS
In general, a Unit holder who is a nonresident alien individual or which is a foreign corporation (collectively "Foreign Taxpayer") will be subject to tax on the gross income produced by the Royalty at a rate equal to 30% (or lower treaty rate, if applicable). This tax will be withheld by the Trustees and remitted directly to the United States Treasury. A Foreign Taxpayer may elect to treat the income from the Royalty as effectively connected with the conduct of a United States trade or business under Section 871 or Section 882 of the Internal Revenue Code of 1986, as amended (the "Code") (or pursuant to any similar provisions of applicable treaties). Upon making such election such Unit holder is entitled to claim all deductions with respect to such income, but he must file a United States income tax return to claim such deductions. This election once made is irrevocable (unless an applicable treaty allows the election to be made annually). However, for tax years beginning after December 31, 1987, such effectively connected income is subjected to withholding equal to the highest applicable percentage (tax rate) -- 39.6% for individual foreign Unit holders and 35% for corporate foreign Unit holders.
Section 897 of the Code and the Treasury Regulations thereunder treat the publicly traded Trust as if it were a United States real property holding corporation. Accordingly, Foreign Unit holders owning greater than 5 percent of the outstanding Units (or 237,576 Units) are subject to United States income tax on the
gain on the disposition of their Units. Foreign Unit holders owning 5 percent or less are not subject to United States income tax on the gain on the disposition of their Units.
Federal income taxation of a Foreign Taxpayer is a highly complex matter which may be affected by many other considerations. Therefore, each Foreign Taxpayer should consult his own tax adviser as to the advisability of his ownership of Units.
TAX-EXEMPT ORGANIZATIONS
Investments in publicly traded partnerships are treated the same as investments in other partnerships for purposes of the rules governing unrelated business taxable income. The Royalty and interest income of the Partnership should not be unrelated business taxable income so long as, generally, a Unit holder did not incur debt to acquire a Unit or otherwise incur or maintain a debt that would not have been incurred or maintained if such Unit had not been acquired. Legislative proposals have been made from time to time which, if adopted, would result in the treatment of Royalty income as unrelated business income. Tax-exempt Unit holders should consult their own tax advisors with respect to the treatment of Royalty income.
STATE LAW CONSIDERATIONS
The Trust and the Partnership have been structured so as to cause the Units to 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 under the laws of Louisiana. In that event, the tax, probate, devolution of title and administration laws of Louisiana or other states applicable to real property may apply to the Units, even if held by a person who is not a resident thereof. Application of such laws could make the inheritance and related matters with respect to the Units substantially more onerous than had the Units been treated as interests in intangible personal property. Unit holders should consult their legal and tax advisers regarding the applicability of these considerations to their individual circumstances.
TERMINATION OF THE TRUST
The terms of the TEL Offshore Trust Agreement provide that the Trust will terminate upon the first to occur of the following events: (1) total future net revenues attributable to the Partnership's interest in the Royalty, as determined by independent petroleum engineers, as of the end of any year, are less than $2 million or (2) a decision to terminate the Trust by the affirmative vote of Unit holders representing a majority of the Units. Total future net revenues attributable to the Partnership's interest in the Royalty were estimated at $24.3 million as of October 31, 1997, based on the reserve study of DeGolyer and MacNaughton, independent petroleum engineers, discussed herein. Based on the DeGolyer and MacNaughton reserve study, as of October 31, 1997, it is estimated that approximately 80% of future net revenues from the Royalty Properties are expected to be received by the Trust during the next 3 years. Because the Trust will terminate in the event estimated future net revenues fall below $2.0 million, it would be possible for the Trust to terminate even though some or all of the Royalty Properties continued to have remaining productive lives. Upon termination of the Trust, the Trustees will sell for cash all of the assets held in the Trust estate and make a final distribution to Unit holders of any funds remaining after all Trust liabilities have been satisfied. The estimates of future net revenues discussed above are subject to the limitations described in the DeGolyer and MacNaughton reserve study. The reserve study is limited to reserves classified as proved; therefore, future capital expenditures for recovery of reserves not classified as proved by DeGolyer and MacNaughton are not included in the calculation of estimated future net revenues. In addition, the estimates of future net revenues discussed above are subject to large variances from year to year and should not be construed as exact. There are numerous uncertainties present in estimating future net revenues for the Royalty Properties. The estimate may vary depending on changes in market prices for crude oil and natural gas, the recoverable reserves, annual production and costs assumed by DeGolyer and MacNaughton. In addition, future economic and operating conditions as well as results of future drilling plans may cause significant changes in such estimate. The discussion set forth above is qualified in its
entirety by reference to the Trust Agreement itself, which is an exhibit to this Form 10-K and is available upon request from the Corporate Trustee.
In addition, in the event of a dissolution of the Partnership (which could occur under the circumstances described above under "Description of the Trust") and a subsequent winding up and termination thereof, the assets of the Partnership (i.e., the Royalty) could either (i) be distributed in kind ratably to the Trust and the Managing General Partner or (ii) be sold and the proceeds thereof distributed ratably to the Trust and the Managing General Partner. In the event of a sale of the Royalty and a distribution of the cash proceeds thereof to the Trust and the Managing General Partner, the Trustee would make a final distribution to Unit holders of the Trust's portion of such cash proceeds plus any other cash held by the Trust after payment of or provision for all liabilities of the Trust, and the Trust would be terminated.
ROYALTY INCOME, DISTRIBUTABLE INCOME AND TOTAL ASSETS
Reference is made to Items 6, 7 and 8 of this Form 10-K for financial information relating to the Trust.
DESCRIPTION OF ROYALTY PROPERTIES
PRODUCING ACREAGE AND WELLS
The Partnership's interest consists of an overriding royalty interest, equivalent to a 25% net profits interest, in the Royalty Properties as follows:
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(1) As of October 31, 1997, there were no wells in the process of drilling. See "Operations" under Item 7 of this report for a discussion of drilling activity during 1997. (2) As of October 31, 1997, there were 79 producing completions. (3) Multiple completions are counted as one well. South Timbalier 36 has 10 multiple completion wells and South Timbalier 37 has 6 multiple completion wells. (4) This lease expired in 1996. (5) This lease was abandoned and expired in 1991.
RESERVES
A study of the proved oil and gas reserves attributable to the Partnership, in which the Trust has a 99.99% interest, has been made by DeGolyer and MacNaughton, independent petroleum engineering consultants, as of October 31, 1997. The following letter summarizes such reserve study. Such study reflects estimated production, reserve quantities and future net revenue based upon estimates of the future timing of actual production without regard to when received by the Trust, which differs from the manner in which the Trust recognizes its royalty income. See Notes 3 and 9 in the Notes to Financial Statements under Item 8 of this Form 10-K.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data in the DeGolyer and MacNaughton letter represent estimates only and should not be construed as being exact. The discounted present values shown by the DeGolyer and MacNaughton letter should not be construed as the current market value of the estimated gas and oil reserves attributable to the Royalty Properties or the costs that would be incurred to obtain equivalent reserves, since a market value determination would include many additional factors. In accordance with applicable regulations of the Securities and Exchange Commission (the "SEC"), estimated future net revenues were based, generally, on current prices and costs, whereas actual future prices and costs may be materially greater or less. In addition, because the reserve study is limited to proved reserves, future capital expenditures for recovery of reserves not classified as proved by DeGolyer and MacNaughton are not included in the calculation of estimated future net revenues. Reserve assessment is a subjective process of estimating the recovery from underground accumulations of gas and oil that cannot be measured in an exact way, and estimates of other persons might differ materially from those of DeGolyer and MacNaughton. Accordingly, reserve estimates are often different from the quantities of hydrocarbons that are ultimately recovered.
The Partnership's share of gas sales are recorded by the Working Interest Owners on the cash method of accounting. Under this method, revenues are recorded based on actual gas volumes sold which could be more or less than the volumes the Working Interest Owners are entitled to based on their ownership interests. The Partnership's Royalty income for a period reflects the actual gas sold during the period. Chevron has advised the Trust that, as of October 31, 1997, approximately 109,900 Mcf had been overtaken by Chevron from the Eugene Island 339 property. The Partnership's share of revenues related to the overtaken gas was included in the Partnership's Royalty income in the periods during which the gas was sold. Accordingly, the reserves and future Royalty income attributable to the Partnership, as discussed in the DeGolyer and MacNaughton letter and shown in Note 9 in the Notes to Financial Statements under Item 8 of this Form 10-K, have been reduced by the Partnership's share of such imbalance. The standardized measure of discounted future Royalty income attributable to the Partnership was reduced by approximately $73,600 in 1997 related to such imbalance. Chevron has advised the Trust that sufficient gas reserves exist on Eugene Island 339 for underproduced parties to recoup their share of the gas imbalance on that property.
During 1994, Pennzoil, the Working Interest Owner on the Eugene Island 348 property, settled a gas imbalance on that property for approximately $2,696,000. The Trust's share of this settlement amount was approximately $674,000, of which approximately $166,100, $5,000 and $150,000 was recovered from the Trust by the Working Interest Owner during 1997, 1996 and 1995, respectively, and the remainder will be subject to recovery from the Trust in future periods, in accordance with the Conveyance. The Working Interest Owner has advised the Trust that future Royalty income attributable to all of the Royalty Properties owned by Pennzoil will be used to offset the Trust's share of such settlement amounts. Based on current production, prices and expenses for the Royalty Properties owned by Pennzoil, it is estimated that Royalty income attributable to such properties will be retained by Pennzoil for the remaining life of the Trust. The Trust does not anticipate that retention of such Royalty income by Pennzoil will have a material effect on the Trust's Royalty income as a whole.
LETTER REPORT AS OF OCTOBER 31, 1997 ON RESERVES AND REVENUE OF CERTAIN PROPERTIES OWNED BY THE TEL OFFSHORE TRUST PARTNERSHIP SEC CASE
DEGOLYER AND MACNAUGHTON ONE ENERGY SQUARE DALLAS, TEXAS 75206
January 30, 1998
Chevron USA Inc. Chevron Place 935 Gravier Street New Orleans, Louisiana 70012
Gentlemen:
Pursuant to your request, we have prepared estimates, as of October 31, 1997, of the extent and value of the proved crude oil, condensate, and natural gas reserves of a net profits interest owned by TEL Offshore Trust Partnership (the Trust Partnership). This net profits interest (the Trust Partnership Interest) is in certain offshore leases owned by Chevron USA Inc. (Chevron), as successor in title to Tenneco Oil Company (Tenneco), by Pennzoil Petroleum Company (Pennzoil), as successor in title to Chevron, and by Texaco Exploration and Production, Inc. (Texaco), as successor in title to Chevron. The interest appraised consists of a 25-percent net profits interest in 17 leases (the Subject Properties), which are located in the Gulf of Mexico offshore from Louisiana. Before acquisition by Chevron, the Subject Properties had been transferred to Tenneco upon the dissolution of Tenneco Exploration Ltd. (Exploration I), a limited partnership formerly comprised of Tenneco and Tenneco West Inc. Exploration I conveyed the net profits interest to the Trust Partnership, which is 99.99-percent owned by TEL Offshore Trust, by the Conveyance of Overriding Royalty Interests effective January 1, 1983. The Subject Properties were acquired by Chevron on November 18, 1988. Certain of the Subject Properties were subsequently acquired by Pennzoil effective July 1, 1992, and certain others were acquired by Texaco effective December 1, 1994. One of the Pennzoil Subject Properties was subsequently acquired by SONAT Exploration Company (SONAT) and certain other Pennzoil Subject Properties were acquired by Amoco Production Company (Amoco), both effective October 1, 1995.
During this investigation, we consulted freely with the officers and employees of Chevron and were given access to such accounts, records, geological and engineering reports, and other data as were desired for examination. In the preparation of this report we have relied, without independent verification, upon information furnished by Chevron with respect to property interests owned by the Trust Partnership, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. It was not considered necessary to make a field examination of the physical condition and operation of the Subject Properties.
Our reserves estimates are based on a detailed study of the Subject Properties and were prepared by the use of standard geological and engineering methods generally accepted by the petroleum industry. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, consideration of the stage of development of the reservoir, and the quality and completeness of basic data.
Reserves estimated herein are expressed as gross and net reserves. Gross reserves are defined as the total estimated petroleum to be produced from the Subject Properties after October 31, 1997. Combined net reserves are defined as those reserves remaining after deducting royalties from gross reserves. Net reserves are defined as that portion of the combined net reserves attributable to the interests owned by the Trust Partnership Interest after deducting interests owned by others. Gas volumes are expressed as sales gas reserves at a temperature of 60 degrees Fahrenheit and at a legal pressure bases of 14.73 pounds per square inch absolute. Sales gas is defined as the total gas to be produced from the reservoirs, measured at the point
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of delivery, after reduction for fuel usage, flare, and shrinkage resulting from field separations and precessing. Condensate reserves estimated herein are those to be obtained by normal separator recovery.
Petroleum reserves included in this report are classified as proved and are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs as of the date the estimate is made, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:
PROVED--Reserves that have been proved to a high degree of certainty by analysis of the producing history of a reservoir and/or by volumetric analysis of adequate geological and engineering data. Commercial productivity has been established by actual production, successful testing, or in certain cases by favorable core analyses and electrical-log interpretation when the producing characteristics of the formation are known from nearby fields. Volumetrically, the structure, areal extent, volume, and characteristics of the reservoir are well defined by a reasonable interpretation of adequate subsurface well control and by known continuity of hydrocarbon-saturated material above known fluid contacts, if any, or above the lowest known structural occurrence of hydrocarbons.
DEVELOPED--Reserves that are recoverable from existing wells with current operating methods and expenses.
Developed reserves include both producing and nonproducing reserves. Estimates of producing reserves assume recovery by existing wells producing from present completion intervals with normal operating methods and expenses. Developed nonproducing reserves are in reservoirs behind the casing or at minor depths below the producing zone and are considered proved by production from other wells in the field, by successful drill-stem tests, or by core analyses from the particular zones. Nonproducing reserves require only moderate expense to be brought into production.
UNDEVELOPED--Reserves that are recoverable from additional wells yet to be drilled.
Undeveloped reserves are those considered proved for production by reasonable geological interpretation of adequate subsurface control in reservoirs that are producing or proved by other wells but are not recoverable from existing wells. This classification of reserves requires drilling of additional wells, major deepening of existing wells, or installation of enhanced recovery or other facilities.
Reserves recoverable by enhanced recovery methods, such as injection of external fluids to provide energy not inherent in the reservoirs, may be classified as proved developed or proved undeveloped reserves depending upon the extent to which such enhanced recovery methods are in operation. These reserves are considered to be proved only in cases where a successful fluid-injection program is in operation, a pilot program indicates successful fluid injection, or information is available concerning the successful application of such methods in the same reservoir and it is reasonably certain that the program will be implemented.
The properties evaluated consist of 17 leases located offshore from Louisiana. These 17 leases include 13 productive properties (including 2 leases covering separate portions of the south half of Ship Shoal Block 183) and 4 leases to which no reserves have been assigned. Pennzoil owns an interest in one of the productive properties and in one of the leases to which no reserves have been assigned. Texaco owns an
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interest in four of the productive properties. SONAT and Amoco own an interest in one property each, but only the SONAT property is productive.
The reserves volumes and revenue values shown in this report were estimated from projections of reserves and revenue attributable to the combined interests, which consist of the Trust Partnership Interest and the interests retained in the Subject Properties by Chevron, Pennzoil, Texaco, SONAT, or Amoco. Net reserves attributable to the Trust Partnership Interests were estimated by allocating to the Trust Partnership a portion of the estimated combined net reserves of the Subject Properties based on future revenue. The formula used to estimate the net reserves attributable to the Trust Partnership Interest is as follows:
This formula was applied separately to the Pennzoil, Texaco, SONAT, and Amoco groups of properties and then to the Chevron (remaining properties) group; the results were then added together to obtain the total reserves and revenue for the Trust Partnership Interest. Because the net reserves volumes attributable to the Trust Partnership Interest are estimated using an allocation of reserves based on estimates of future revenue, a change in prices or costs will result in changes in the estimated net reserves. Therefore, the estimated net reserves attributable to the Trust Partnership Interest will vary if different future price and cost assumptions are used. Trust Partnership Interest net revenue and net reserves estimates included in this report have been estimated from reserves and revenue attributable to the combined interests using procedures and calculation methods as specified by Chevron and represented by Chevron to be in accordance with the Conveyance of Overriding Royalty Interests.
Units have been formed for several common reservoirs that underlie the Subject Properties and adjacent leases. In those cases, the estimated gross reserves of the entire reservoir are shown and the resulting combined Trust Partnership and Chevron, Pennzoil, Texaco, SONAT, or Amoco interests in the reservoir unit are used to calculate combined interests net reserves.
In the Eugene Island Block 339 field, gas from certain properties has been produced and sold, but one owner has not taken its full share of the produced gas. In this case, there is in effect a gas-balancing agreement whereby gas not taken is credited to the account of the owner not currently selling its share of the produced gas. That gas is to be recovered by increasing this party's share of the monthly gas production in the future. The net reserves and revenue shown herein are the future reserves and revenue attributable to the Trust Partnership Interest, including adjustments for the existing balancing agreement in the Eugene Island Block 339 field.
Data available from wells drilled on the appraised properties through October 1997 were used in estimating gross ultimate recovery. Gross production estimated through October 31, 1997, was deducted from the gross ultimate recovery to arrive at estimates of gross reserves. In most fields, this required that the production rates be estimated for 4 months, since production data for certain properties were available only through June 1996.
DEGOLYER AND MACNAUGHTON
Net proved reserves attributable to the Trust Partnership Interest, as of October 31, 1997, are estimated as follows:
OIL AND NATURAL CONDENSATE GAS (BBL) (MCF) ---------- --------- Proved Developed and Undeveloped Reserves Reserves as of October 31, 1996....... 918,021 4,893,525 Revisions of Previous Estimates....... 146,239 63,599 Improved Recovery..................... 0 0 Purchases of Minerals in Place........ 0 0 Extensions, Discoveries, and Other Additions........................... 11,887 221,520 Production............................ (374,154) (1,782,704) Sales of Minerals in Place............ 0 0 Reserves as of October 31, 1997....... 701,993 3,395,940 Proved Developed Reserves Reserves as of October 31, 1996....... 917,883 4,885,185 Reserves as of October 31, 1997....... 695,022 3,169,790
Revenue values in this report are expressed in terms of estimated combined future net revenue, future net revenue attributable to the Trust Partnership Interest, and present worth of these future net revenues. Future gross revenue is that revenue which will accrue from the production and sale of the estimated combined net reserves. Combined future net revenue values were calculated by deducting operating expenses and capital costs from the future gross revenue of the combined interest. These monthly values for the aggregate of the combined interest in the Subject Properties were reduced by a trust overhead charge furnished by Chevron. Capital and abandonment costs for longer-life properties were accrued at the end of each quarter in amounts specified by Chevron beginning in January 1998. The future accrual or escrow amounts for each of the five groups of properties were deducted from the combined future net revenue at the end of each quarter, as specified by Chevron. Interest on the balance of the accrued capital and abandonment costs at the rate of 4.75 percent per year as specified by Chevron was credited monthly as a reduction in operating costs. The adjusted revenue resulting from subtracting the overhead charge and accrued capital and abandonment costs was multiplied by a factor of 25 percent to arrive at the future net revenue attributable to the Trust Partnership Interest. The above calculations were made monthly for each of the five groups of the properties (Chevron, Pennzoil, Texaco, SONAT, and Amoco). Interest was charged monthly on the net profits deficit balances (costs not recovered currently) at the rate of 4.75 percent per year as specified by Chevron. Present worth is defined as future net revenue discounted at a specified arbitrary discount rate compounded monthly over the expected period of realization; in this report, present worth values using a discount rate of 10 percent are reported. Future income tax expenses were not taken into account in estimating future net revenue and present worth. No deductions were made in the foregoing reserves for any outstanding production payments.
Revenue values in this report were estimated using the initial prices and costs provided by Chevron. Future prices were estimated using guidelines established by the Securities and Exchange Commission (SEC) and the Financial Accounting Standards Board (FASB). These guidelines require the use of prices for oil and condensate in effect on October 31, 1997. The initial and future prices and producing rates used in this report have been reviewed by Chevron and it has represented that the gas prices and rates used herein are those that the Trust Partnership could reasonably expect to receive on October 31, 1997. The assumptions used for estimating future prices and costs are as follows:
OIL AND CONDENSATE PRICES
Oil and condensate prices applicable in October 1997 were used as initial prices with no increases based on inflation. The initial oil and condensate prices were furnished by Chevron.
DEGOLYER AND MACNAUGHTON
NATURAL GAS PRICES
Initial gas prices furnished by Chevron were prices in effect on October 31, 1997, and were represented to be in accordance with existing gas contracts. Chevron further represents that these contracts provide for periodic price redeterminations, but do not provide for any fixed or determinable escalations. Therefore, the initial prices were used for the remaining life of the properties.
OPERATING AND CAPITAL COSTS
Current estimates of operating costs were used for the life of the properties with no increases in the future based on inflation. Future capital expenditures were estimated using 1997 values and were not adjusted for inflation. Abandonment costs have been estimated as capital costs for all properties, including the four leases which are considered depleted and to which no reserves have been assigned.
A summary of estimated revenue and costs attributable to the combined interest in proved reserves of the Subject Properties and the future net revenue and present worth attributable to the Trust Partnership Interest, as of October 31, 1997, is as follows:
1 Includes abandonment costs.
2 Future income tax expenses were not taken into account in the preparation of these estimates.
In our opinion, the information relating to estimated proved reserves, estimated future net revenue from proved reserves, and present worth of estimated future net revenue from proved reserves of oil, condensate, and gas contained in this report has been prepared in accordance with Paragraphs 10-13, 15 and 30(a)-(b) of Statement of Financial Accounting Standards No. 69 (November 1982) of the FASB and Rules 4-10(a) (1)-(13) of Regulation S-X and Rule 302(b) of Regulation S-K of the SEC; provided, however, future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein.
DEGOLYER AND MACNAUGHTON
To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature or information beyond the scope of this report, we are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.
In our opinion, we have made the investigations necessary to enable us to estimate the petroleum reserves reported herein. Estimates of oil, condensate, and gas reserves and future net revenue should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves and revenue estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.
Submitted,
DeGOLYER and MacNAUGHTON
JAMES W. HAIL, JR., P.E. James W. Hail, Jr., P.E. Senior Vice President DeGolyer and MacNaughton
While estimates of reserves attributable to the Royalty are shown in order to comply with requirements of the SEC, there is no precise method of allocating estimates of physical quantities of reserves to the Partnership and the Trust, since the Royalty is not a working interest and the Partnership does not own and is not entitled to receive any specific volume of reserves from the Royalty. Reserve quantities in the DeGolyer and MacNaughton reserve study have been allocated based on a revenue formula described in the foregoing letter. The quantities of reserves indicated by such formula will be affected by future changes in various economic factors utilized in estimating future gross and net revenues from the Royalty Properties. Therefore, the estimates of reserves set forth in the DeGolyer and MacNaughton letter are to a large extent hypothetical and differ in significant respects from estimates of reserves attributable to a working interest. For a further discussion of reserves, reference is made to Note 9 in the Notes to Financial Statements under Item 8 of this Form 10-K.
The future net revenues contained in the DeGolyer and MacNaughton letter have not been reduced for future costs and expenses of the Trust, which are expected to approximate $455,300 annually. The costs and expenses of the Trust may increase in future years, depending on increases in accounting, engineering, legal and other professional fees, as well as other factors.
In addition, because the DeGolyer and MacNaughton reserve study is limited to proved reserves, future capital expenditures for recovery of reserves not classified as proved by DeGolyer and MacNaughton are not included in the calculation of future net revenues. Such capital expenditures could have a significant effect on the actual future net revenues attributable to the Partnership's interest in the Royalty.
The Trust Agreement provides that the Trust will terminate in the event total future net revenues attributable to the Partnership's interest in the Royalty as determined by independent petroleum engineers, as of the end of any year, are less than $2.0 million. See "Business -- Termination of the Trust".
The Working Interest Owners have advised the Trust that there have been no events subsequent to October 31, 1997 that have caused a significant change in the estimated proved reserves referred to in the DeGolyer and MacNaughton letter.
OPERATIONS AND PRODUCTION
Reference is made to the Section entitled "Operations" under Item 7 of this Form 10-K for information concerning operations and production.
MARKETING
The amount of cash distributions by the Trust is dependent on, among other things, the sales prices for oil and gas produced from the Royalty Properties and the quantities of oil and gas sold. The oil and gas industry in the United States during the past decade has been affected generally by a surplus in deliverability in comparison to demand. Demand for oil and gas has generally trailed deliverability during this period due to a number of factors including the implementation of energy conservation programs, a shift in economic activity away from energy intensive industries and competition from alternative fuel sources.
Spot domestic natural gas prices were seasonally higher in early 1997 and late 1997, but are declining in early 1998. Crude oil prices generally decreased in 1997 and early 1998.
It should be noted that substantial uncertainties exist with regard to future oil and gas prices, which are subject to material fluctuations due to changes in production levels and pricing and other actions taken by major petroleum producing nations, as well as the regional supply and demand for gas, weather, industrial growth, conservation measures, competition and other variables.
GAS MARKETING
During 1997, gas sales by the Working Interest Owners under a contract with Texaco Natural Gas, Inc. and NGC Corporation accounted for 61% and 33%, respectively, of total gas revenues from the Royalty Properties. Such contracts provide for gas to be purchased by Texaco Natural Gas, Inc. and NGC Corporation at a calculated price based on the monthly Inside FERC Tennessee-Louisiana Zone 1 index.
Effective August 31, 1996, Chevron's Natural Gas Business Unit and Warren Petroleum Company merged with NGC Corporation. As a result of this merger, since September 1996 all of Chevron's natural gas and natural gas liquids relative to the Trust's Royalty Properties have been committed and sold to NGC
Corporation at spot market index prices. See "Certain Relationships and Related Transactions" under Item 13 of this Form 10-K.
It should be noted that the Conveyance provides that amounts received by the producer pursuant to "take-or-pay" provisions are not included within the Royalty payable to the Trust unless and until gas is actually delivered pursuant to the "make-up" provisions, if any, of the applicable contract. Accordingly, amounts received by the Working Interest Owners as "take-or-pay" payments are not included in the calculation of the Royalty payable, and the income received by the Trust is restricted to amounts paid for gas actually delivered.
Due to the seasonal nature of demand for natural gas and its effects on sales prices and production volumes, the amount of gas sold with respect to the Royalty Properties may vary. Generally, production volumes and prices are higher during the first and fourth quarters of each calendar year. Because of the time lag between the date on which the Working Interest Owners receive payment for production from the Royalty Properties and the date on which distributions are made to Unit holders, the seasonality that generally affects production volumes and prices of is generally reflected in distributions to the Trust in later periods.
The following paragraphs discuss the marketing of gas from the principal Royalty Properties.
WEST CAMERON 643. West Cameron 643 contributed approximately 60% of the revenues from gas sales from the Royalty Properties in 1997. The average price received for natural gas from all of the Working Interest Owner's purchasers on West Cameron 643 during 1997 was $2.72 per Mcf and the price received for February 1998 was $2.10 per Mcf. The gas from West Cameron 643 is currently committed under the contract with Texaco Natural Gas, Inc.
SHIP SHOAL 182/183. Ship Shoal 182/183 contributed approximately 28% of the revenues from gas sales from the Royalty Properties in 1997. The average price received for natural gas from all of the Working Interest Owner's purchasers on Ship Shoal 182/183 during 1997 was $2.64 per Mcf and the price received for February 1998 was $2.14 per Mcf. The gas from Ship Shoal 182/183 is committed to NGC Corporation, as described above.
EUGENE ISLAND 339. Eugene Island 339 contributed approximately 5% of the revenues from gas sales from the Royalty Properties in 1997. The average price received for natural gas from all of the Working Interest Owner's purchasers on Eugene Island 339 during 1997 was $2.80 per Mcf and the price received for February 1998 was $2.26 per Mcf. The gas from Eugene Island 339 is committed to NGC Corporation, as described above.
OIL MARKETING
Crude oil purchases by Texaco, Inc. and by the Supply and Distribution Department of Chevron accounted for approximately 68% and 32%, respectively, of total crude oil revenues from the Royalty Properties during 1997.
Texaco, Inc. purchases crude oil at prices based on its own published pricing bulletin with an adjustment for gravity and transportation charges. Average monthly prices for fiscal 1997 ranged from $18.06 per bbl to $24.37 per bbl. The average crude oil price under this arrangement for February 1998 was approximately $15.33 per bbl.
The Supply and Distribution Department of Chevron purchases crude oil at prices based on its own published pricing bulletins with an adjustment for gravity and transportation charges. Average monthly prices for fiscal 1997 ranged from $17.28 per bbl to $23.91 per bbl. The average price of crude oil sold under this arrangement for February 1998 was approximately $13.95 per bbl.
COMPETITION AND REGULATION
COMPETITION
The Working Interest Owners experience competition from other oil and gas companies in all phases of its operations. Numerous companies participate in the exploration for and production of oil and gas. The Working Interest Owners have advised the Trust that they believe that their competitive positions are affected by price and contract terms. Business is affected not only by such competition, but also by general economic developments, governmental regulations and other factors.
REGULATION -- GENERAL
The production of oil and gas by the Working Interest Owners is affected by many state and federal regulations with respect to allowable rates of production, drilling permits, well spacing, marketing, environmental matters and pricing. Future regulations could change allowable rates of production or the manner in which oil and gas operations may be lawfully conducted. Sales of natural gas in interstate commerce for resale and the transportation of natural gas in interstate commerce are subject to regulation by the Federal Energy Regulatory Commission ("FERC") under the Natural Gas Act of 1938, as amended (the "Natural Gas Act").
The operations of the Working Interest Owners under federal oil and gas leases offshore the United States are subject to regulations of the United States Department of Interior which currently impose absolute liability upon lessees for the cost of cleanup of pollution resulting from their operations.
In the past, the federal government regulated the prices at which natural gas could be sold. However, in July 1989, the Natural Gas Decontrol Act of 1989 was enacted, which provided for complete price decontrol of first sales of gas as of January 1993 through repealing Title I of the Natural Gas Policy Act of 1978. Prior to January 1993, this Act provided for: (1) immediate decontrol of gas to which no first sales contract applied on date of enactment; (2) decontrol of gas under existing gas contracts as the contracts expire or are terminated; (3) decontrol in May 1991 of gas covered by sales contracts on the date of enactment and produced from wells spudded after the date of enactment and (4) decontrol of gas under contracts renegotiated after March 23, 1989 to provide that maximum lawful prices will not apply.
Commencing in late 1985 and early 1986, the FERC issued a series of rules and orders (Order No. 436, Order No. 500, and related orders) that made sweeping changes in its regulations governing the transportation and marketing of natural gas supplies. Among other things, the new regulations (i) require interstate pipelines that elect to transport gas for others under self-implementing authority to provide transportation services to all shippers on a non-discriminatory basis; (ii) permit each existing firm sales customer of such pipelines to modify over at least a five-year period its existing purchase obligations; (iii) establish a complicated procedure to permit pipelines that transport gas under the regulations to credit the volumes transported on a volumetric basis against take-or-pay obligations under contracts in existence on June 23, 1987; and (iv) establish guidelines that permit pipelines to recover from customers all or a portion of payments made to producers in settlement of take-or-pay contract disputes. On August 24, 1990, the D.C. Circuit upheld most aspects of the final rule in the Order No. 500 series. Only issues regarding pregranted abandonment of converted transportation services and double-crediting were remanded by the Court to the FERC for further action. The pregranted abandonment issue is addressed in Order No. 636. With respect to the double crediting issue, on April 4, 1991, the FERC issued Order 500-K in which it ruled that its take-or-pay crediting regulations did not result in producers providing double take-or-pay credits in certain circumstances.
On April 8, 1992, the FERC issued Order No. 636, which implemented a major restructuring of interstate pipeline operations in order to enhance the competitive structure of the pipeline industry and maximize the benefits of a competitive wellhead market resulting from wellhead price decontrols. Order No. 636 requires, among other things, that all interstate pipelines eliminate their bundled city gate sales services by unbundling their sales services from their transportation services. Unbundled sales customers have been given the right to reduce their firm sales entitlements in whole or in part, thereby enabling such customers to negotiate with other parties for long-term supplies. Order No. 636 also requires that open access pipelines provide transportation services comparable in quality for all gas supplies, whether purchased from the pipeline or elsewhere. The FERC would require that operational terms and conditions imposed on a pipelines transportation service result in nondiscriminatory treatment for pipeline sales gas
and third party sales gas. In this way, pipelines, producers, marketers and all other merchants of gas would be able to compete on an equal footing. The stated purpose of Order No. 636 is to create a national gas market where a buyer can reach many sellers by meaningful access to the pipeline transportation grid. On August 3, 1992, the FERC issued Order No. 636-A, which largely reaffirmed Order No. 636 and denied stay of the implementation of the new rule pending judicial review. On November 27, 1992, the FERC issued Order No. 636-B, which uniformly upheld the regulations adopted in Order Nos. 636 and 636-A. As a result of these orders, individual so-called "restructuring" proceedings were established for each interstate pipeline to develop particularized features and procedures for each pipeline's system to implement Order No. 636. On July 16, 1996, the D.C. Circuit issued its opinion on review of Order No. 636. The opinion upheld most elements of Order No. 636 including the unbundling of sales and transmission services, curtailment of pipeline capacity, implementation of the capacity release program and the mandatory imposition of straight-fixed-variable ("SFV") rate design for interstate pipelines. The D.C. Circuit did remand certain aspects of Order No. 636 to the Commission for further explanation including, INTER ALIA, the right-of-first-refusal mechanism, the eligibility of customers to receive notice transportation service, and SFV mitigation measures. On February 27, 1997, the FERC issued Order No. 636-C, its order on remand from the D.C. Circuit. Order No. 636-C is currently pending on rehearing before the FERC. Appeals of individual pipeline restructuring orders are still pending before the D.C. Circuit.
Although the Working Interest Owners are unable to predict the consequences of the new rules, the Working Interest Owners believe such rules could have a significant effect on all segments of the natural gas industry. Although the new rules do not directly regulate gas producers such as Working Interest Owners, the FERC has stated that the rules are intended primarily to foster increased competition in the natural gas industry and to allow more accurate price signals to be transmitted from consumers to producers, such as the Working Interest Owners.
On December 9, 1988, the FERC issued Order No. 509 which provides every jurisdictional interstate natural gas pipeline that transports gas on or across the OCS with a blanket certificate authorizing and requiring nondiscriminatory transportation of natural gas on behalf of others, and requires every OCS pipeline to file tariffs to implement that blanket certificate authorization. The service performed under the blanket certificate includes both firm and interruptible transportation service and OCS pipelines must, pursuant to the blanket certificate, provide open and nondiscriminatory access for both owner and nonowner shippers. Order No. 509 also provided that if an OCS pipeline received a request for service, the pipeline would be required to allocate capacity pro rata in order to provide the requested service. Order No. 509 will facilitate the transportation and marketability of OCS gas. On August 14, 1992, the D.C. Circuit remanded the final rule back to the FERC for further consideration as to whether the FERC has authority to require a pipeline to file to abandon service to a shipper prior to the termination of the underlying contract and to charge a replacement shipper the generally applicable rate, not the old shipper's rate. On October 4, 1993, the FERC issued Order No. 559 in which the FERC (1) addressed the issues raised by the Court's August 14, 1992 order and (2) amended certain regulations and removed other regulations promulgated in Order No. 509. Specifically, the Commission removed the regulations concerning the capacity allocation program established in Order No. 509 and the regulation providing for abandonment authority. The capacity allocation regulations promulgated in Order No. 509 have been subsumed by the Order No. 636 capacity release program.
In September of 1991, the FERC issued a final rule in Order 537 in which it amended its regulations for the transportation of natural gas pursuant to Section 311 of the NGPA. Generally, the final rule requires that for interstate pipeline transportation under Section 311, the "on behalf of" entity (interstate pipeline or local distribution company) must either (1) have physical custody of or transport the gas at some point during the transaction or (2) hold title to the gas at some point during the transaction for a purpose related to its status as an intrastate pipeline or an LDC. In addition, the final rule authorizes Section 311 transportation services by interstate pipelines for end users located in the service areas of non-transporting, non-title holding intrastate pipelines and LDC's that certify that the interstate pipeline's transportation is on their behalf. On September 21, 1992, the FERC issued Order No. 537-A which largely upheld the regulations adopted in Order No. 537. On January 14, 1993, the FERC issued Order No. 537-B which clarified Order No. 537-A. On April 25, 1994, the United States Court of Appeals for the D.C. Circuit upheld Order Nos. 537, 537-A and 537-B.
On February 28, 1996, the FERC issued a Statement of Policy regarding the application of its jurisdiction under the NGA and the Outer Continental Shelf Lands Act over new natural gas facilities and services on the Outer Continental Shelf ("OCS"). In its Policy Statement, the FERC concluded that it will retain its existing primary function test to determine whether particular facilities on the OCS constitute gathering facilities exempt from the FERC's NGA jurisdiction. However, the FERC added a new factor to its primary function test for facilities that are designed to collect gas produced in water depths of 200 meters or more. Such facilities now will be presumed to qualify as gathering facilities up to the point or points of potential connection with the interstate pipeline grid. Downstream of that point, the facilities will be evaluated under the existing primary function test. Existing interstate pipelines and gathering facilities would retain their present status barring some change in circumstances. On June 14, 1996, the Commission dismissed all requests for rehearing of its February 28, 1996 order.
On July 17, 1996, the FERC issued Order No. 587 which revised the FERC's regulations to require interstate natural gas pipelines to follow standardized procedures issued by the Gas Industry Standards Board ("GISB") for certain business practices, I.E., nominations, allocations, balancing, measurement, invoicing, capacity release and electronic communication between the pipelines and those with whom they do business. On January 30, 1997, in Order No. 587-B, the FERC incorporated into its regulations a second set of GISB standards that would, INTER ALIA, require interstate pipelines to conduct business transactions and provide other information according to Internet protocols and to abide by certain business practice standards dealing with nominations, flowing gas and capacity release. On March 4, 1997, the FERC issued Order No. 587-C which amended the FERC's regulations to adopt standards requiring interstate pipelines to publish certain information on Internet web pages and to implement new business practice standards covering nominations and flowing gas. The Commission has denied requests for rehearing of Order Nos. 587, ET SEQ. The appeal of Order No. 587 is pending before the D.C. Circuit. The intent of these standards is to establish a more efficient and integrated pipeline grid which will reduce the variations in pipeline business practices and allow buyers to obtain and transport gas from all potential sources of supply more easily and efficiently.
The Trust cannot predict the full effect that continuing judicial, legislative and regulatory involvement in various natural gas issues will have on prices, markets or terms of sale of natural gas.
ENVIRONMENTAL REGULATIONS
GENERAL
The Working Interest Owners' oil and gas activities on the Royalty Properties are subject to existing and evolving federal, state and local environmental laws and regulations. The Working Interest Owners have advised the Trust that they believe that their operations and facilities are in general compliance with applicable health, safety, and environmental laws and regulations that have taken effect at the federal, state and local levels. In addition, events in recent years have heightened environmental concerns about the oil and gas industry generally, and about offshore operations in particular. The Working Interest Owners' operation of federal offshore oil and gas leases is 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 require lessees to suspend or cease operations in the affected areas.
Under the Oil Pollution Act of 1990, as amended by the Coast Guard Authorization Act of 1996, (collectively, "OPA"), parties responsible for offshore facilities must establish and maintain evidence of oil-spill financial responsibility ("OSFR") for costs attributable to potential oil spills. OPA requires a minimum of $35 million in OSFR for offshore facilities located on the OCS. This amount is subject to upward regulatory adjustment up to $150 million. Responsible parties for more than one offshore facility are required to provide OSFR only for their offshore facility requiring the highest OSFR. On March 25, 1997, the Mineral Management Service proposed regulations for establishing the amount of OSFR to be required for particular facilities. Under the proposed rule, the amount of OSFR will increase as the volume of a facility's worst-case oil spill increases. Accordingly, for facilities with worst-case spills of less than 35,000 barrels, only $35 million in OSFR will be required; for worst-case spills of over 35,000 barrels, $70 million will be required; for worst-case spills of over 70,000 barrels, $105 million will be required; and for worst-case spills of over 105,000 barrels, $150 million will be required. In addition, all OSFR below $150 million remains subject to upward regulatory adjustment if warranted by the particular operational,
environmental, human health or other risks involved with a facility. Although the Working Interest Owners have advised the Trust that current environmental regulation has had no material adverse effect on the Working Interest Owners' present method of operations, the impact of the recently adopted and proposed regulatory changes, and of future environmental regulatory developments such as stricter environmental regulation and enforcement policies, cannot presently be quantified.
The Working Interest Owners' operations are subject to regulation, principally under the following federal statutes, along with their analogous state statutes.
WATER
The Federal Water Pollution Control Act of 1972, as amended, and the Oil Pollution Act of 1990 impose certain liabilities and penalties upon persons and entities, such as the Working Interest Owners, for any discharges of petroleum products in reportable quantities, for the costs of removing an oil spill, and for natural resource damages. State laws for the control of water pollution also provide varying civil and criminal penalties and liabilities in the case of a release of petroleum or its derivatives in surface waters. The federal NPDES permits prohibit the discharge of produced water, sand and other substances related to the oil and gas industry to coastal waters of Louisiana and Texas. Although the cost to reformat operations to comply with these zero discharge mandates under federal or state law may be significant, the entire industry will experience similar costs. The Working Interest Owners believe that these costs will not have a material adverse impact on their operations.
AIR EMISSIONS
Amendments to the federal Clean Air Act were enacted in late 1990 and require most industrial operations in the United States, including offshore operations, to incur future capital expenditures in the next several years for air emission control equipment in connection with maintaining and obtaining operating permits and approvals addressing other air emission related issues. The Environmental Protection Agency ("EPA") and state environmental agencies have been developing regulations to implement these requirements. Some of the Working Interest Owners' facilities are included within the categories of hazardous air pollutant sources which will be affected by these regulations and these regulations could make operation of the Royalty Properties more costly.
SOLID WASTE
The Working Interest Owners' operations may generate wastes that are subject to the federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. The EPA has limited disposal options for certain hazardous wastes and may adopt more stringent disposal standards for nonhazardous wastes. Furthermore, it is possible that some wastes that are currently classified as nonhazardous, perhaps including wastes generated during drilling and production operations, may in the future be designated as "hazardous wastes". Such changes in the regulations would result in more rigorous and costly disposal requirements which could result in increased operating expenses on the Royalty Properties.
NORM
Oil and gas exploration and production activities have been identified as generators of low-level naturally-occurring radioactive materials ("NORM"). The generation, handling and disposal of NORM in the course of offshore oil and gas exploration and production activities is currently regulated in federal and state waters. These regulations could result in an increase in operating expenses on the Royalty Properties.
SUPERFUND
The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without regard to the fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a "hazardous substance" into the environment. These persons include the current or previous owner and operator of a facility and companies that disposed or arranged for the disposal of the hazardous substance found at a facility. CERCLA also authorizes the EPA and, in some cases, private parties to take actions in response to threats to the public health or the environment and to seek recovery from such responsible classes of persons of the costs, which can be substantial, of such action. Although "petroleum" is excluded from CERCLA's definition of a
"hazardous substance", in the course of their operations, the Working Interest Owners may generate wastes that fall within CERCLA's definition of "hazardous substances." The Working Interest Owners may be responsible under CERCLA for all or part of the costs to clean up facilities at which such substances have been disposed. Such clean-up costs may make operation of the Royalty Properties more expensive for the Working Interest Owners.
OFFSHORE OPERATIONS
Offshore oil and gas operations are subject to regulations of the United States Department of the Interior, including regulations promulgated pursuant to the Outer Continental Shelf Lands Act, which impose liability upon a lessee, such as the Working Interest Owners, under a federal lease for the cost of clean-up of pollution resulting from a lessee's operations. In the event of a serious incident of pollution, the Department of the Interior may require a lessee under federal leases to suspend or cease operations in the affected areas.
ITEM 2.
ITEM 2. PROPERTIES.
Reference is made to Item 1 of this Form 10-K.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
There are no material pending legal proceedings to which the Trust is a party.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
There were no matters submitted to a vote of security holders during the fourth quarter of 1997.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
The Units were traded on the National Association of Securities Dealers Automated Quotation System ("NASDAQ") SmallCap Market under the symbol TELOZ prior to October 22, 1996. On October 22, 1996, the Trust Units were delisted from the NASDAQ SmallCap Market. The Trust has been advised by NASDAQ that the Trust Units are being traded on the OTC Bulletin Board. The Trust Units may also be traded on pink sheets. The high and low sales price as reported by NASDAQ and the OTC Bulletin Board, as applicable, for each quarter for the years ended December 31, 1997 and 1996, were as follows:
SALES PRICES ------------------------------------------ 1997 1996 -------------------- -------------------- QUARTER HIGH LOW HIGH LOW - ------------------------------------ --------- --------- --------- --------- First............................... $ 1.688 $ 1.250 $ 1.000 $ 0.750 Second.............................. $ 3.750 $ 1.323 $ 1.313 $ 0.750 Third............................... $ 4.500 $ 2.375 $ 1.438 $ 0.750 Fourth.............................. $ 5.375 $ 4.313 $ 1.500 $ 0.875
Sales prices on the OTC Bulletin Board reflect inter-dealer prices, without retail mark-up, mark-down or commission, and may not necessarily represent actual transactions.
The distributions paid each quarter for the years ended December 31, 1997 and 1996, were as follows:
DISTRIBUTION PAID ------------------------------- QUARTER 1997 1996 - ------------------------------------- ------------- ------------- First................................ $ .155052 $ .000000 Second............................... $ .392365 $ .000000 Third................................ $ .316595 $ .124258 Fourth............................... $ .410961 $ .000000
At March 20, 1998, the 4,751,510 Units outstanding were held by 2,612 Unit holders of record.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
LIQUIDITY AND CAPITAL RESOURCES
The Trust's source of capital is the Royalty income received from its share of the Net Proceeds from the Royalty Properties. Reference is made to Note 9 in the Notes to Financial Statements under Item 8
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Trustees and Unit Holders of TEL Offshore Trust:
We have audited the accompanying statements of assets, liabilities and trust corpus of TEL Offshore Trust as of December 31, 1997 and 1996, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 1997. These financial statements are the responsibility of the Trustees. 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 described in Note 3, these financial statements were prepared on 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 TEL Offshore Trust as of December 31, 1997 and 1996, and its distributable income and changes in trust corpus for each of the three years in the period ended December 31, 1997, on the comprehensive basis of accounting described in Note 3.
ARTHUR ANDERSEN LLP
Houston, Texas March 27, 1998
TEL OFFSHORE TRUST STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
The accompanying notes are an integral part of these financial statements.
TEL OFFSHORE TRUST NOTES TO FINANCIAL STATEMENTS
(1) TRUST ORGANIZATION AND PROVISIONS
Tenneco Offshore Company, Inc. ("Tenneco Offshore") created the TEL Offshore Trust ("Trust") effective January 1, 1983, pursuant to the Plan of Dissolution ("Plan") approved by Tenneco Offshore's stockholders on December 22, 1982. In accordance with the Plan, the TEL Offshore Trust Partnership ("Partnership") was formed in which the Trust owns a 99.99% interest and Tenneco Oil Company ("Tenneco") owned a .01% interest. In general, the Plan was effected by transferring an overriding royalty interest ("Royalty") equivalent to a 25% net profits interest in the oil and gas properties (the "Royalty Properties") of Tenneco Exploration, Ltd. ("Exploration I") located offshore Louisiana to the Partnership and issuing certificates evidencing units of beneficial interest in the Trust in liquidation and cancellation of Tenneco Offshore's common stock.
On October 31, 1986, Exploration I was dissolved and the oil and gas properties of Exploration I were distributed to Tenneco subject to the Royalty. Tenneco, who was then serving as the Managing General Partner of the Partnership, assumed the obligations of Exploration I, including its obligations under the instrument conveying the Royalty to the Partnership (the "Conveyance"). The dissolution of Exploration I had no impact on future cash distributions to holders of units of beneficial interests.
On November 18, 1988, Chevron U.S.A. Inc. ("Chevron") acquired most of the Gulf of Mexico offshore oil and gas properties of Tenneco, including all the Royalty Properties. As a result of the acquisition, Chevron replaced Tenneco as the Working Interest Owner and Managing General Partner of the Partnership. Chevron also assumed Tenneco's obligations under the Conveyance.
On October 30, 1992, Pennzoil Company ("Pennzoil") acquired certain oil and gas producing properties from Chevron, including four of the Royalty Properties. The four Royalty Properties acquired by Pennzoil were East Cameron 354, Eugene Island 348, Eugene Island 367 and Eugene Island 208. As a result of such acquisition, Pennzoil replaced Chevron as the Working Interest Owner of such properties on October 30, 1992. Pennzoil also assumed Chevron's obligations under the Conveyance with respect to such properties.
On December 1, 1994, Texaco Exploration and Production Inc. ("Texaco") acquired one of the Royalty Properties from Chevron. The Royalty Property acquired by Texaco was West Cameron 643. As a result of such acquisition, Texaco replaced Chevron as the Working Interest Owner of such property on December 1, 1994. Texaco also assumed Chevron's obligations under the Conveyance with respect to such property.
On October 1, 1995, SONAT Exploration Company ("SONAT") acquired the East Cameron 354 property from Pennzoil. In addition, on October 1, 1995, Amoco Production Company ("Amoco") acquired the Eugene Island 367 property from Pennzoil. As a result of such acquisitions, SONAT and Amoco replaced Pennzoil as the Working Interest Owner of the East Cameron 354 and Eugene Island 367 properties, respectively, on October 1, 1995, and also assumed Pennzoil's obligations under the Conveyance with respect to such properties.
All of the Royalty Properties continue to be subject to the Royalty, and it is anticipated that the Trust and the Partnership will continue to operate, in general, as if the above-described sales of the Royalty Properties had not occurred.
Unless the context in which such terms are used indicates otherwise, in these Notes to Financial Statements the terms "Working Interest Owner" and "Working Interest Owners" generally refer to the owner or owners of the Royalty Properties (Exploration I through October 31, 1986; Tenneco for periods from October 31, 1986 until November 18, 1988; Chevron with respect to all Royalty Properties for periods from November 18, 1988 until October 30, 1992, and with respect to all Royalty Properties except East Cameron 354, Eugene Island 348, Eugene Island 367 and Eugene Island 208 for periods from October 30, 1992 until December 1, 1994, and with respect to the same properties except West
TEL OFFSHORE TRUST NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(1) TRUST ORGANIZATION AND PROVISIONS -- (CONTINUED) Cameron 643 thereafter; Pennzoil with respect to East Cameron 354, Eugene Island 348, Eugene Island 367 and Eugene Island 208 for periods from October 30, 1992 until October 1, 1995, and with respect to Eugene Island 348 and Eugene Island 208 thereafter; Texaco with respect to West Cameron 643 for periods beginning on or after December 1, 1994; SONAT with respect to East Cameron 354 for periods beginning on or after October 1, 1995; and Amoco with respect to Eugene Island 367 for periods beginning on or after October 1, 1995;
On January 14, 1983, Tenneco Offshore distributed units of beneficial interest ("Units") in the Trust to holders of Tenneco Offshore's common stock on the basis of one Unit for each common share owned on such date.
The terms of the Trust Agreement, dated January 1, 1983, provide, among other things, that:
(a) the Trust is a passive entity and cannot engage in any business or investment activity or purchase any assets;
(b) the interest in the Partnership can be sold in part or in total for cash upon approval of a majority of the Unit holders;
(c) the Trustees, as defined below, can establish cash reserves and borrow funds to pay liabilities of the Trust and can pledge the assets of the Trust to secure payments of the borrowings. At December 31, 1991, a cash reserve of $120,000 had been established for future Trust general and administrative expenses. During 1992 and 1993, in anticipation of future periods when the cash received from the Royalty may not be sufficient for payment of Trust expenses, the reserve for future Trust general and administrative expenses was increased each quarter by an amount equal to the difference between $150,000 and the amount of the Trust's general and administrative expenses for such quarter. In 1994 in anticipation of future periods when the cash received from the Royalty may not be sufficient for payment of Trust expenses, the Trust determined, in accordance with the Trust Agreement, to begin further increasing the Trust's cash reserve each quarter by an amount equal to the difference between $200,000 and the amount of the Trust's general and administrative expenses for such quarter. During 1994 and 1995, the aggregate amount of cash reserved by the Trust was $347,638 and $370,258, respectively. During 1996, the Trust used $397,845 from the Trust's cash reserve account to pay the Trust's general and administrative expenses for the first, second and fourth quarters, when no royalty income was received by the Trust. In the third quarter of 1996, when Royalty income was received, the Trust reserved $99,536. Therefore, the net cash used from the Trust's cash reserve account in 1996 was $298,309. During 1997, the aggregate amount of cash reserved by the Trust was $593,066. The total amount of the Trust's cash reserve at December 31, 1997 was $1,472,689. In addition, in the first quarter of 1998, the Trust has determined that the Trust's cash reserve is currently sufficient to provide for future administrative expenses in connection with the winding up of the Trust. The Trust has determined that a cash reserve equal to three times the average expenses of the Trust during each of the past three fiscal years is sufficient at this time to provide for future administrative expenses in connection with the winding up of the Trust. This reserve amount for 1998 will be $1,366,035. The excess amount of $106,654 will be distributed to Unit holders, and no deposits are expected to be made to the Trust's cash reserve account during 1998.
(d) the Trustees will make cash distributions to the Unit holders in January, April, July and October of each year as discussed in Note 4; and
(e) the Trust will terminate upon the first to occur of the following events: (i) total future net revenues attributable to the Partnership's interest in the Royalty, as determined by independent petroleum engineers, as of the end of any year, are less than $2.0 million or (ii) a decision to terminate the Trust by the affirmative vote of Unit holders representing a majority of the Units. Future net
TEL OFFSHORE TRUST NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(1) TRUST ORGANIZATION AND PROVISIONS -- (CONTINUED) revenues attributable to the Royalty were estimated at $24.3 million as of October 31, 1997. (See Note 9 for further information regarding estimated future net revenues.) Upon termination of the Trust, the Corporate Trustee will sell for cash all assets held in the Trust estate and make a final distribution to the Unit holders of any funds remaining, after all Trust liabilities have been satisfied.
The Trust is administered by Chase Bank of Texas, National Association (formerly known as Texas Commerce Bank National Association) ("Corporate Trustee") and George Allman, Jr., W. Leslie Duffy and Richard L. Melton ("Individual Trustees"), as trustees ("Trustees").
(2) OVERRIDING ROYALTY INTEREST
The Royalty entitles the Trust to its share (99.99%) of 25% of the Net Proceeds attributable to the Royalty Properties. The Conveyance, dated January 1, 1983, provides that the Working Interest Owners will calculate, for each period of three months commencing the first day of February, May, August and November, an amount equal to 25% of the net proceeds from its oil and gas properties for the period. Generally, Net Proceeds are the amounts received by the Working Interest Owners from the sale of minerals from its oil and gas properties less operating and capital costs incurred, management fees and expense reimbursements owing the Managing General Partner of the Partnership, applicable taxes other than income taxes, and a special cost reserve. The Special Cost Reserve Account is for the future costs to be incurred to plug and abandon wells, dismantle and remove platforms, pipelines and other production facilities, and for the estimated amount of future capital expenditures on the Royalty Properties. Net proceeds do not include amounts received by the Working Interest Owners as advance gas payments, "take-or-pay" payments or similar payments, unless and until such payments are extinguished or repaid through the future delivery of gas.
Crude oil sales to Chevron accounted for approximately 32%, 85% and 73% of crude oil revenues from the Royalty Properties during 1997, 1996 and 1995, respectively. Chevron purchased crude oil at prices based on its own published pricing bulletins with an adjustment for gravity and transportation charges. Average monthly prices for fiscal 1997 ranged from $17.28 per bbl to $23.91 per bbl. The average price of crude oil sold under this arrangement for February 1998 was approximately $13.95 per bbl. Sales to Texaco Inc. accounted for approximately 68%, 14% and 24% of crude oil revenues from the Royalty Properties during 1997, 1996 and 1995, respectively. Sales to Texaco Natural Gas Inc. and NGC Corporation accounted for approximately 61% and 33%, respectively, of total gas revenues from the Royalty Properties during 1997.
The Trust's share of Royalty income was reduced by approximately $473,900, $373,500 and $120,000 in 1997, 1996 and 1995, respectively, for management fees paid to the Working Interest Owners as reimbursement for expenses incurred by them on behalf of the Trust. Such management fees were calculated as 3% of the Trust's share of the sum of revenues, production expenses and capital expenditures attributable to the Royalty Properties in each of the three years above.
(3) BASIS OF ACCOUNTING
The financial statements of the Trust are prepared on the following basis:
(a) Royalty income is recorded when received by the Corporate Trustee on the last business day of each calendar quarter; and
(b) Trust general and administrative expenses are recorded when paid, except for the cash reserved for future general and administrative expenses as discussed in Note 1.
This manner of reporting income and expenses is considered to be the most meaningful because the quarterly distributions to Unit holders are based on net cash receipts received from the Working Interest
TEL OFFSHORE TRUST NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(3) BASIS OF ACCOUNTING -- (CONTINUED) Owners. The financial statements of the Trust differ from financial statements prepared in accordance with generally accepted accounting principles, because, under such principles, Royalty income and Trust general and administrative expenses for a quarter would be recognized on an accrual basis. In addition, amortization of the overriding royalty interest, calculated on a units-of-production basis, is charged directly to Trust corpus since such amount does not affect distributable income.
Cash and cash equivalents include all highly liquid short-term investments with original maturities of three months or less.
Effective January 1, 1996, the Trust adopted Statement of Financial Accounting Standards ("SFAS") No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." The adoption of SFAS 121 did not have a material impact on the financial position or distributable income of the Trust.
(4) DISTRIBUTIONS TO UNIT HOLDERS
In accordance with the provisions of the Trust Agreement, generally all Net Proceeds received by the Trust, net of Trust general and administrative expenses and any cash reserves established for the payment of contingent or future obligations of the Trust, are distributed currently to the Unit holders. The amounts distributed are determined on a quarterly basis and are payable to Unit holders of record as of the last business day of each calendar quarter. However, cash distributions are made in January, April, July and October and include interest earned from the quarterly record date to the date of distribution.
(5) SPECIAL COST ESCROW ACCOUNT
The Conveyance provides for reserving funds for estimated future "Special Costs" of plugging and abandoning wells, dismantling platforms and other costs of abandoning the Royalty Properties, as well as for the estimated amount of future drilling projects and other capital expenditures on the Royalty Properties. As provided in the Conveyance, the amount of funds to be reserved is determined based on factors including estimates of aggregate future production costs, aggregate future Special Costs, aggregate future net revenues and actual current net proceeds. Deposits into this account reduce current distributions and are placed in an escrow account and invested in short-term certificates of deposit. Such account is herein referred to as the "Special Cost Escrow Account". The Trust's share of interest generated from the Special Cost Escrow Account, approximately $215,900, $150,700 and $112,500 for 1997, 1996 and 1995, respectively, serves to reduce the Trust's share of allocated production costs. As of December 31, 1997, 1996 and 1995, approximately $4,622,000, $4,068,000 and $2,572,000 respectively, remained in the Special Cost Escrow Account. Special Cost Escrow Account funds will generally be utilized to pay Special Costs to the extent there are not adequate current net proceeds to pay such costs. Special Costs that have been paid are no longer included in the Special Cost Escrow Account calculation. Deposits to the Special Cost Escrow Account will generally be made when the balance in the Special Cost Escrow Account is less than 125% of future Special Costs and there is a Net Revenues Shortfall (a calculation of the excess of estimated future costs over estimated future net revenues pursuant to a formula contained in the Conveyance). When there is not a Net Revenues Shortfall, amounts in the Special Cost Escrow Account will generally be released, to the extent that Special Costs have been incurred. Amounts in the Special Cost Escrow Account will also be released when the balance in such account exceeds 125% of future Special Costs. The discussion of the terms of the Conveyance and Special Cost Escrow Account contained herein is qualified in its entirety by reference to the Conveyance itself, which is an exhibit to this Form 10-K and is available upon request from the Corporate Trustee.
In the first quarter of 1998, there was a net release of funds from the Special Cost Escrow Account of approximately $513,800. The release was primarily a result of a decrease in the current estimate of
TEL OFFSHORE TRUST NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(5) SPECIAL COST ESCROW ACCOUNT -- (CONTINUED) projected capital expenditures of the Royalty Properties. Additional deposits to the Special Cost Escrow Account may be required in future periods in connection with other production costs, other abandonment costs, other capital expenditures and changes in the estimates and factors described above. Such deposits could result in a significant reduction in Royalty income in the periods in which such deposits are made.
In 1997, the Working Interest Owners deposited a net amount of approximately $554,500 into the Special Cost Escrow Account. The deposit was made primarily due to an increase in the current estimate of projected capital expenditures, production costs and abandonment costs of the Royalty Properties.
In 1996, the Working Interest Owners deposited approximately $1,496,000 into the Special Cost Escrow Account. The deposit was made primarily due to an increase in the current estimate of projected capital expenditures, production costs and abandonment costs of the Royalty Properties.
In 1995, the Working Interest Owners deposited a net amount of approximately $207,000 into the Special Cost Escrow Account. The deposit was made primarily due to an increase in the current estimate of projected capital expenditures on the Royalty Properties.
(6) FEDERAL INCOME TAX MATTERS
The Internal Revenue Service has ruled that the Trust is a grantor trust and therefore the Trust will incur no federal income tax liability.
(7) COMMITMENTS AND CONTINGENCIES
During 1994, Pennzoil, the Working Interest Owner on the Eugene Island 348 property, settled a gas imbalance on that property for approximately $2,696,000. The Trust's share of this settlement amount was approximately $674,000, of which approximately $166,100, $5,000 and $150,000 was recovered from the Trust by the Working Interest Owner during 1997, 1996 and 1995, respectively, and the remainder will be subject to recovery from the Trust in future periods, in accordance with the Conveyance. The Working Interest Owner has advised the Trust that future Royalty income attributable to all of the Royalty Properties owned by Pennzoil will be used to offset the Trust's share of such settlement amounts. Based on current production, prices and expenses for the Royalty Properties owned by Pennzoil, it is estimated that Royalty income attributable to such properties will be retained by Pennzoil for the remaining life of the Trust. The Trust does not anticipate that retention of such Royalty income by Pennzoil will have a material effect on the Trust's Royalty income as a whole.
The Working Interest Owners have advised the Trust that, although they believe that they are in general compliance with applicable health, safety and environmental laws and regulations that have taken effect at the federal, state and local levels, costs may be incurred to comply with current and proposed environmental legislation which could result in increased operating expenses on the Royalty Properties.
(8) SUBSEQUENT EVENT
Effective January 1, 1998, Energy Resource Technology, Inc. ("Energy") acquired the East Cameron 354 property from SONAT. As a result of such acquisition, Energy replaced SONAT as the Working Interest Owner of the East Cameron 354 property effective January 1, 1998, and also assumed SONAT's obligations under the Conveyance with respect to such property.
(9) SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)
Estimates of the proved oil and gas reserves attributable to the Partnership's royalty interest are based on a report prepared by DeGolyer and MacNaughton, independent petroleum engineering consultants. Estimates were prepared in accordance with guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board. Accordingly, the estimates are based on
TEL OFFSHORE TRUST NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(9) SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED) -- (CONTINUED) existing economic and operating conditions in effect at October 31, 1997, with no provision for future increases or decreases except for periodic price redeterminations in accordance with existing gas contracts.
The reserve volumes and revenue values attributable to the Partnership's royalty interest were estimated from projections of reserves and revenue attributable to the combined interests consisting of the Partnership's royalty interest and the retained interest of the Working Interest Owners in the Royalty Properties. Net reserves attributable to the Partnership's royalty interest were estimated by allocating to the Partnership a portion of the estimated combined net reserves of the subject properties based on the ratio of the Partnership's interest in future net revenues to combined future gross revenues. Because the net reserve volumes attributable to the Partnership's royalty interest are estimated using an allocation of reserves based on estimates of future revenue, a change in prices or costs will result in changes in the estimated net reserves. Therefore, the estimated net reserves attributable to the Partnership's royalty interest will vary if different future price and cost assumptions are used. All reserves attributable to the Partnership's royalty interest are located in the United States.
The Partnership's share of gas sales are recorded by the Working Interest Owners on the cash method of accounting. Under this method, revenues are recorded based on actual gas volumes sold which could be more or less than the volumes the Working Interest Owners are entitled to based on their ownership interests. The Partnership's Royalty income for a period reflects the actual gas sold during the period. Chevron has advised the Trust that as of October 31, 1997, approximately 109,900 Mcf were overtaken by Chevron from the Eugene Island 339 property in prior periods. The Partnership's share of revenue related to the overtaken gas was included in the Partnership's Royalty income in the periods during which the gas was sold. Accordingly, the reserves and future Royalty income attributable to the Partnership, as discussed in the DeGolyer and MacNaughton letter, have been reduced by the Partnership's share of such imbalance. The standardized measure of discounted future Royalty income attributable to the Partnership was reduced by approximately $73,600 in 1997 related to such imbalance. Chevron has advised the Trust that sufficient gas reserves exist on Eugene Island 339 for underproduced parties to recoup their share of the gas imbalance on that property.
Distributable income for the Partnership for the periods ended December 31, 1997, 1996 and 1995 included net proceeds relating to production of reserves from the Royalty Properties for the twelve months ended October 31, 1997, 1996 and 1995, respectively. Accordingly, all reserve information included in the tables below is as of October 31, 1997, 1996 and 1995.
TEL OFFSHORE TRUST NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(9) SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED) -- (CONTINUED)
Estimated net proved reserves attributable to the Partnership's royalty interest for the periods indicated, are as follows:
(SEE NOTES ON FOLLOWING PAGE)
TEL OFFSHORE TRUST NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(9) SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED) -- (CONTINUED)
The following table sets forth estimates of the standardized measure of discounted future Royalty income (based upon a discount rate of 10 percent) from estimated future production of proved oil and gas reserves attributable to the Partnership as of October 31, 1997, 1996 and 1995:
1997 1996 1995 --------- --------- --------- (THOUSANDS) Future Royalty income................ $ 24,285 $ 30,903 $ 7,693 Discount at 10% per annum............ (3,825) (6,352) (2,168) --------- --------- --------- Standardized measure of discounted future Royalty income from proved oil and gas reserves, discounted at 10% per annum(c)................... 20,460 24,551 5,525 Additional disclosures: Amounts attributable to Pennzoil(d)..................... (250) (77) (140) --------- --------- --------- Standardized measure of discounted future Royalty income from proved oil and gas reserves, discounted at 10% per annum, net of amounts attributable to Pennzoil(c)..................... $ 20,210 $ 24,474 $ 5,385 ========= ========= =========
The following table summarizes the changes in the standardized measure of discounted future Royalty income for the Partnership for the twelve months ended October 31, 1997, 1996 and 1995:
1997 1996 1995 --------- --------- --------- (THOUSANDS) Beginning balance(c)................. $ 24,551 $ 5,525 $ 5,145 Revisions of previous estimates(a).................... 152 16,426 1,997 Extensions, discoveries and other additions....................... 745 2,825 -- Royalty income..................... (7,003) (786) (1,383) Accretion of discount.............. 2,455 553 515 Other(b)........................... (440) 8 (749) --------- --------- --------- Net changes in standardized measure................... (4,091) 19,026 380 --------- --------- --------- Ending balance(c).................... 20,460 24,551 5,525 Additional disclosures: Amounts attributable to Pennzoil(d)..................... (250) (77) (140) --------- --------- --------- Ending balance, net of amounts attributable to Pennzoil(c)..... $ 20,210 $ 24,474 $ 5,385 ========= ========= ========= - ------------
NOTES:
(a) Primarily represents net effect of changes in prices, cost estimates and reserve quantity revisions attributable to the Royalty Properties on the royalty computation.
(b) Primarily represents changes in estimated timing of production and changes in the Special Cost Escrow Account.
(c) Future income taxes are not applicable for purposes of these estimates since the Partnership is a nontaxable entity.
(d) As a result of the imbalance settlement by Pennzoil, discussed in Note 7, the associated volumes and future royalty income related to the Pennzoil owned properties have been excluded from the Trust's Supplemental Reserve Information, beginning in 1994.
TEL OFFSHORE TRUST NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(10) SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
- ------------
* Royalty income and distributable income were decreased or increased in certain quarters due to deposits to or releases from the Special Cost Escrow Account as discussed in Note 5 above.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
There are no directors or executive officers of the Registrant. The Trustees consist of a Corporate Trustee and three Individual Trustees. Any Trustee may be removed by the affirmative vote of two Individual Trustees or by the affirmative vote of a majority of the Units at a meeting of Unit holders of beneficial interest in the Trust at which a quorum is present.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
Not applicable.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
(A) SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS.
As of March 20, 1998, no person was known to be the beneficial owner of more than five percent of the Units of beneficial interest in the Trust.
(B) SECURITY OWNERSHIP OF MANAGEMENT.
Not applicable.
(C) CHANGES IN CONTROL.
Registrant knows of no arrangements, including the pledge of securities of the Registrant, the operation of which may at a subsequent date result in a change in control of the Registrant.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Each of the Working Interest Owners owns interests, for its own account, in leases which are in the same area as leases in which the Partnership has acquired or may acquire an interest. Such relationships may give rise to potential conflicts of interests in, among other things, the operation of such leases and in the acquisition and operation of any drainage leases acquired by a Working Interest Owner for its own account. Additionally, the Working Interest Owners and their affiliates are not prohibited from purchasing oil and gas produced from or attributable to any leases in which the Partnership has an interest. Prior to the sale to Chevron, Tenneco also owned interests, for its own account, in leases in the same area as leases in which the Partnership has an interest.
Crude oil sales to the Supply and Distribution Department of Texaco, Inc. and Chevron accounted for approximately 68% and 32%, respectively, of total crude oil revenues from the Royalty Properties during 1997.
The Trust's share of Royalty income was reduced by approximately $473,900 in 1997 for management fees paid to the Working Interest Owners as reimbursement for expenses incurred by them on behalf of the Trust. The aggregate amount of management fees paid to the Working Interest Owners was calculated as 3% of the Trust's share of the sum of revenues, production expenses and capital expenditures attributable to the Royalty Properties in 1997.
Effective August 31, 1996, Chevron's Natural Gas Business Unit and Warren Petroleum Company merged with NGC Corporation In connection with such merger, Chevron became one of three principal stockholders of NGC Corporation, and all of Chevron's natural gas and natural gas liquids relative to the Trust's Royalty Properties have been committed and are being sold to NGC Corporation.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(A) (1) FINANCIAL STATEMENTS The following financial statements are set forth under Part II, Item 8 of this Annual Report on Form 10-K on the pages as indicated:
PAGE IN THIS FORM 10-K Report of Independent Public Accountants...................... 33 Statements of Assets, Liabilities and Trust Corpus............ 34 Statements of Distributable Income............................ 34 Statements of Changes in Trust Corpus......................... 34 Notes to Financial Statements................................. 35
(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 (Asterisk indicates exhibit previously filed with the Securities and Exchange Commission and incorporated herein by reference).
(B) REPORTS ON FORM 8-K No reports on Form 8-K were filed with the Securities and Exchange Commission during the fourth quarter of 1997.
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED ON THIS DAY OF MARCH, 1998.
TEL OFFSHORE TRUST
By CHASE BANK OF TEXAS, NATIONAL ASSOCIATION, CORPORATE TRUSTEE
By /s/ PETE FOSTER PETE FOSTER SENIOR VICE PRESIDENT & TRUST OFFICER
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.
SIGNATURE DATE
CHASE BANK OF TEXAS, NATIONAL ASSOCIATION, Corporate Trustee
By/s/PETE FOSTER March , 1998 PETE FOSTER SENIOR VICE PRESIDENT & TRUST OFFICER
INDIVIDUAL TRUSTEES
/s/GEORGE ALLMAN, JR. March , 1998 GEORGE ALLMAN, JR., TRUSTEE
/s/W. LESLIE DUFFY March , 1998 W. LESLIE DUFFY, TRUSTEE
/s/RICHARD L. MELTON March , 1998 RICHARD L. MELTON, TRUSTEE
THIS ANNUAL REPORT ON FORM 10-K WAS DISTRIBUTED TO UNIT HOLDERS AS AN ANNUAL REPORT. ADDITIONAL COPIES OF THIS ANNUAL REPORT WILL BE PROVIDED, WITHOUT CHARGE, AND COPIES OF EXHIBITS HERETO WILL BE PROVIDED, UPON PAYMENT OF A REASONABLE FEE, UPON WRITTEN REQUEST FROM ANY HOLDER OF UNITS TO:
TEL Offshore Trust Chase Bank of Texas, National Association, Trustee Attention: Debbie Miller, Corporate Trust Department P.O. Box 4717 Houston, Texas 77210-4717
AUDITORS COUNSEL TRANSFER AGENT AND REGISTRAR Arthur Andersen LLP Andrews & Kurth L.L.P. American Stock Transfer Houston, Texas Houston, Texas & Trust Co. as agent for Chase Bank of Texas, N.A. Houston, Texas
TEL OFFSHORE TRUST P.O. Box 4717 Houston, Texas 77210-4717