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, JPMorgan Chase Bank (formerly known as The Chase Manhattan Bank) (“Corporate Trustee”), 700 Lavaca, Austin, Texas 78701. The telephone number of the Corporate Trustee is 1-800-852-1422. JPMorgan Chase Bank was formerly known as The Chase Manhattan Bank and is the successor by mergers to the original name of the Corporate Trustee, Texas Commerce Bank National Association. George Allman, Jr., Gary C. Evans and Jeffrey S. Swanson serve as individual trustees (“Individual Trustees”) of the Trust. The Individual Trustees and the Corporate Trustee may be referred to hereinafter collectively as the “Trustees.”
The Trustee does not maintain a website for filings by the Trust with the U.S. Securities and Exchange Commission (“SEC”). Electronic filings by the Trust with the SEC are available free of charge through the SEC’s website at www.sec.gov.
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 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 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 Conveyance.
On October 30, 1992, PennzEnergy Company (“PennzEnergy”) (which merged with and into Devon Energy Production Company L.P. effective January 1, 2000) acquired certain oil and gas producing properties from Chevron, including four of the Royalty Properties. The four Royalty Properties acquired by PennzEnergy were East Cameron 354, Eugene Island 348, Eugene Island 367 and Eugene Island 208. As a result of such acquisition, PennzEnergy replaced Chevron as the Working Interest Owner of these properties on October 30, 1992. PennzEnergy also assumed Chevron’s obligations under the Conveyance with respect to these properties.
On December 1, 1994, Texaco Exploration and Production Inc. (“TEPI”) acquired two of the Royalty Properties from Chevron. The Royalty Properties acquired by Texaco were West Cameron 643 and East Cameron 371/381. As a result of such acquisition, TEPI replaced Chevron as the Working Interest Owner of such properties on December 1, 1994. TEPI also assumed Chevron’s obligations under the Conveyance with respect to these properties.
On October 1, 1995, SONAT Exploration Company (“SONAT”) acquired the East Cameron 354 property from PennzEnergy. In addition, on October 1, 1995, Amoco Production Company (“Amoco”) acquired the Eugene Island 367 property from PennzEnergy. As a result of such acquisitions, SONAT and Amoco replaced PennzEnergy as the Working Interest Owners of the East Cameron 354 and Eugene
Island 367 properties, respectively, on October 1, 1995 and also assumed PennzEnergy’s obligations under the Conveyance with respect to these properties.
Effective January 1, 1998, Energy Resource Technology, Inc. (“ERT”) acquired the East Cameron 354 property from SONAT. As a result of this acquisition, ERT 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. In October 1998, Amerada Hess Corporation (“Amerada”) acquired the East Cameron 354 property from ERT effective January 1, 1998. As a result of such acquisition, Amerada replaced ERT as the Working Interest Owner of the East Cameron 354 property effective January 1, 1998, and also assumed ERT’s obligations under the Conveyance with respect to this property.
Effective January 1, 2000, PennzEnergy and Devon Energy Corporation (Nevada) merged into Devon Energy Production Company L.P. (“Devon”). As a result of this merger, Devon replaced PennzEnergy as the Working Interest Owner of Eugene Island 348 and Eugene Island 208 properties effective January 1, 2000, and also assumed PennzEnergy’s obligations under the Conveyance with respect to these properties.
On October 9, 2001, a wholly owned subsidiary of Chevron Corporation, a Delaware corporation, merged (the “Merger”) with and into Texaco Inc., a Delaware corporation (“Texaco”), pursuant to an Agreement and Plan of Merger, dated as of October 15, 2000. As a result of the Merger, Texaco Inc. became a wholly owned subsidiary of Chevron Corporation, and Chevron Corporation changed its name to “ChevronTexaco Corporation” in connection with the Merger (ChevronTexaco Corporation is referred to herein as “ChevronTexaco”). Accordingly, the properties referred to herein by Chevron and Texaco are each now controlled by subsidiaries of ChevronTexaco.
On May 1, 2002, TEPI assigned all of its interests in West Cameron 643 and East Cameron 371/381 to Chevron. Accordingly, pursuant to the Conveyance of the Royalty Properties, Net Proceeds will be calculated for the collective Royalty Properties owned by Chevron after this date.
On June 6, 2003, Anadarko Petroleum Corporation (“Anadarko”) acquired, among other interests, a 25% Working Interest in the East Cameron 354 field subject to the Royalty from Amerada effective April 1, 2003. As a result of this transaction, Anadarko replaced Amerada as the Working Interest Owner of East Cameron 354 effective July 1, 2003 and also assumed Amerada’s obligation under the Conveyance with respect to this property.
Effective October 1, 2004, Apache Corporation (“Apache”) acquired Anadarko’s interests in East Cameron 354 and assumed Anadarko’s obligation under the Conveyance with respect to this property.
All of the Royalty Properties continue to be subject to the Royalty, and it is anticipated that the Trust and Partnership, in general, will 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” generally refer to the owner or owners of the Royalty Properties (Tenneco 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 Cameron 643 thereafter; PennzEnergy/Devon with respect to East Cameron 354, Eugene Island 348, Eugene Island 367 and Eugene/Devon Island 208 for periods from October 30, 1992 until October 1, 1995, and with respect to Eugene Island 348 and Eugene Devon Island 208 thereafter; TEPI with respect to West Cameron 643 and East Cameron 371/381 for periods beginning on or after December 1, 1994 until May 1, 2002; SONAT with respect to East Cameron 354 for periods on or after October 1, 1995; Amoco with respect to Eugene Island 367 for
periods beginning on or after October 1, 1995; Amerada with respect to East Cameron 354 for periods beginning on or after January 1, 1998 until July 1, 2003; Chevron with respect to West Cameron 643 and East Cameron 371/381 on and after May 1, 2002; Anadarko with respect to East Cameron 354 on and after July 1, 2003 until October 1, 2004, and Apache with respect to East Cameron 354 after October 1, 2004).
A total of 4,751,510 units of beneficial interest in the Trust (“Units”) are issued and outstanding. The Trust Units have been traded on the Nasdaq SmallCap Market since August 31, 2001. Previously the Trust Units were traded on the OTC Bulletin Board. The Trust Units were also traded on pink sheets. From inception of the Trust to December 31, 2005, distributions to Unit holders totaled approximately $114,434,000 or approximately $24.08 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 therefore 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 $48.0 million as of October 31, 2005 based on the reserve study of DeGolyer and MacNaughton, independent petroleum engineers. (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: (1) December 31, 2030, (2) the election of the Trust to dissolve the Partnership, (3) the termination of the Trust, (4) the bankruptcy of the Managing General Partner of the Partnership, or (5) the dissolution of the Managing General Partner or its election to dissolve the Partnership; however, the Managing General Partner has agreed not to dissolve or to elect to dissolve the Partnership and shall be liable for all damages and costs to the Trust if it breaches this agreement.
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 (1) 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); (2) all applicable taxes (including severance and ad valorem taxes) excluding income taxes; (3) all operating charges directly associated with the Royalty Properties; (4) an allowance for costs, computed on a current basis at a rate equal to the prime rate of JPMorgan Chase Bank plus 0.5% 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; (5) applicable charges for certain overhead expenses as provided in the Conveyance; (6) the management fees and expense reimbursements owing the Working Interest Owners; and (7) 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 Managing General Partner on behalf of the Partnership 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 initially 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 holders of units of beneficial interest.
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, PennzEnergy acquired certain oil and gas producing properties from Chevron, including four of the Royalty Properties. The four Royalty Properties acquired by PennzEnergy were East Cameron 354, Eugene Island 348, Eugene Island 367 and Eugene Island 208. As a result of such acquisition, PennzEnergy 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, TEPI acquired two of the Royalty Properties from Chevron. The Royalty Property acquired by TEPI is West Cameron 643 and East Cameron 371/381. As a result of such acquisition, TEPI 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 PennzEnergy. As a result of such acquisitions, SONAT and Amoco replaced PennzEnergy as the Working Interest Owners of the East Cameron 354 and Eugene Island 367 properties, respectively, and also assumed PennzEnergy’s obligations under the Conveyance with respect to such properties on October 1, 1995. Effective January 1, 1998 ERT acquired the East Cameron 354 property from SONAT. As a result of such acquisition, ERT 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. In October 1998, Amerada acquired the East Cameron 354 property from ERT effective January 1, 1998. As a result of this acquisition, Amerada replaced ERT as the Working Interest Owner of the East Cameron 354 property effective January 1, 1998, and also assumed ERT’s obligations under the Conveyance with respect to this property. Effective January 1, 2000, PennzEnergy and Devon Energy Corporation (Nevada) merged into Devon Energy Production Company L.P. (“Devon”). As a result of such merger, Devon replaced PennzEnergy as the Working Interest Owner of Eugene Island 348 and Eugene Island 208 properties effective January 1, 2000, and also assumed PennzEnergy’s obligations under the Conveyance with respect to these properties. On October 9, 2001, a wholly owned subsidiary of Chevron Corporation, a Delaware corporation, merged (the “Merger”) with and into Texaco Inc., a Delaware corporation (“Texaco”), pursuant to an Agreement and Plan of Merger, dated as of October 15, 2000. As a result of the Merger, Texaco Inc. became a wholly owned subsidiary of Chevron Corporation, and Chevron Corporation changed its name to “ChevronTexaco Corporation” in connection with the Merger (ChevronTexaco Corporation is referred to herein as “ChevronTexaco”). Accordingly, the properties referred to herein by Chevron and Texaco are each now controlled by subsidiaries of ChevronTexaco. On May 1, 2002, TEPI assigned all of its interests in West Cameron 643 and East Cameron 371/381 to Chevron. Accordingly, pursuant to the Conveyance of the Royalty Properties, net proceeds will be calculated for the collective Royalty Properties owned by Chevron after this date. On June 6, 2003, Anadarko acquired, among other interests, a 25% Working Interest in the East Cameron 354 field subject to The Royalty from Amerada effective April 1, 2003. As a result of this transaction, Anadarko replaced Amerada as the Working Interest Owner of East Cameron 354 effective July 1, 2003 and also assumed Amerada’s obligation under the Conveyance with respect to this property. Effective
October 1, 2004, Apache acquired Anadarko’s interest in East Cameron 354 and assumed Anadarko’s obligations under the Conveyance with respect to this property.
DESCRIPTION OF THE UNITS
Each Unit is evidenced by a transferable certificate issued by the Corporate Trustee. Each unit ranks equally as to distributions, has one vote on any matter submitted to Unit holders and 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 calendar 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 the quarterly period plus any other cash receipts of the Trust, less the obligations of the Trust paid during the quarterly period, and adjusted for changes made by the Trust during the 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, bad faith or fraud.
Each Unit holder should consider, in weighing the possible exposure to liability in the event the Trust were not classified as an express trust, (1) the substantial value and passive nature of the Trust assets, (2) the restrictions on the power of the Trustees to incur liabilities on behalf of the Trust and (3) the limited activities to be conducted by the Trustees.
Federal Income Tax Matters
This section is a summary of federal income tax matters of general application which addresses the material tax consequences of the ownership and sale of the Units. Except where indicated, the discussion below describes general federal income tax considerations applicable to individuals who are citizens or residents of the United States. Accordingly, the following discussion has limited application to domestic corporations and persons subject to specialized federal income tax treatment, such as regulated investment companies and insurance companies. It is impractical to comment on all aspects of federal, state, local and foreign laws that may affect the tax consequences of the transactions contemplated hereby and of an investment in the units as they relate to the particular circumstances of every Unit holder. Each Unit holder is encouraged to consult his own tax advisor with respect to his particular circumstances.
This summary is based on current provisions of the Internal Revenue Code of 1986, as amended (the “Code”), existing and proposed Treasury regulations thereunder and current administrative rulings and court decisions, all of which are subject to changes that may or may not be retroactively applied. Some of the applicable provisions of the Code have not been interpreted by the courts or the Internal Revenue Service (“IRS”). No assurance can be provided that the statements set forth herein (which do not bind the IRS or the courts) will not be challenged by the IRS or will be sustained by a court if so challenged.
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 and each Unit holder will be treated as owning an interest in the Partnership.
Income and Depletion
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 that quarter. Royalty income is portfolio income. Since all income from the Partnership is royalty income, this amount, net of depletion and severance taxes, is portfolio income and, subject to certain exceptions and transitional rules, this royalty income cannot be offset by passive losses. Additionally, interest income is portfolio income. Administrative expense is an investment expense.
The IRS has also 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. 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 who acquired units after October 11, 1990, are entitled to percentage depletion on Royalty income attributable to those units.
Backup Withholding
Distributions from the Trust are generally subject to backup withholding at a rate of 28% of these distributions. Backup withholding will not normally apply to distributions to a Unit holder, however, unless the Unit holder fails to properly provide to the Trust his taxpayer identification number or the IRS notifies the Trust that the taxpayer identification number provided by the 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 tax basis in the unit and the amount realized.
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 the property to the extent it reduced the taxpayer’s basis in the property. Under this provision, depletion attributable to a unit acquired after 1986 will be subject to recapture as ordinary income upon disposition of the unit or upon disposition of the oil and gas property to which the depletion is attributable. The balance of any gain or any loss will be capital gain or loss if the unit was held by the Unit holder as a capital asset, either long-term or short-term depending on the holding period of the unit. This capital gain or loss will be long-term if a Unit holder’s holding period for the units exceeds one year at the time of sale or exchange. A long-term capital gains rate of 15% applies to most capital assets sold or exchanged with a holding period of more than one year. Capital gain or loss will be short-term if the unit has not been held for more than one year at the time of sale on exchange.
Non-U.S. Unit holders
In general, a Unit holder who is a nonresident alien individual or which is a foreign corporation, each a “non-U.S. Unit holder” for purposes of this discussion, will be subject to tax on the gross income produced by the Royalty at a rate equal to 30%, or if applicable, at a lower treaty rate. This tax will be withheld by the Trustees and remitted directly to the United States Treasury. A non-U.S. Unit holder may elect to treat the income from the Royalty as effectively connected with the conduct of a United States trade or business under provisions of the Code, or pursuant to any similar provisions of applicable treaties. Upon making this election a non-U.S. Unit holder is entitled to claim all deductions with respect to that income, but he must file a United States federal income tax return to claim those deductions. This election once made is irrevocable, unless an applicable treaty allows the election to be made annually. However, that effectively connected income is subjected to withholding equal to the highest applicable tax rate-35% for individual non-U.S. Unit holders and 35% for corporate non-U.S. Unit holders.
The Code and the Treasury Regulations thereunder treat the publicly traded Trust as if it were a United States real property holding corporation. Accordingly, non-U.S. Unit holders may be subject to United States federal income tax on the gain on the disposition of their units.
Federal income taxation of a non-U.S. Unit holder is a highly complex matter which may be affected by many other considerations. Therefore, each non-U.S. Unit holder is encouraged to consult its own tax adviser with respect to his ownership of units.
Tax-exempt Organizations
Investments in publicly traded grantor trusts are treated the same as investments in partnerships for purposes of the rules governing unrelated business taxable income. The Royalty and interest income should not be unrelated business taxable income so long as, generally, a 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 that 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 taxable income. Each tax-exempt Unit holder should consult its own tax advisor 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 these 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 $48.0 million as of October 31, 2005, 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, 2005 in order to correspond with distributions to the Trust, it is estimated that approximately 71% 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 (1) be distributed in kind ratably to the Trust and the Managing General Partner or (2) 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:
(1) As of October 31, 2005, there were 2 wells in the process of drilling. See “Operations” under Item 7 of this report for a discussion of drilling activity during 2005.
(2) As of October 31, 2005, there were 101 producing completions.
(3) Multiple completions are counted as one well. South Timbalier 37 has 5 multiple completion wells and Ship Shoal 182/183 has 2 multiple completion wells.
(4) These percentages represent the working interest owner’s interest subject to the Partnership’s net proceeds.
(5) Apache purchased this working interest from Anadarko effective October 1, 2004. This lease expired in 2005. Wells will be plugged and abandoned in 2006.
(6) Eugene Island 339 C-17 and C-18 wells are producing in this property but are not included here; they are not subject to the Partnership’s net proceeds until they pay out.
(7) This lease expired in 2004.
(8) This lease expired in 1996.
(9) This lease expired in November 2002, and all wells on the lease had been abandoned as of November 2003.
(10) This lease expired on May 30, 1996. It was leased again as OCS-G 19800 effective July 1, 1998. Neither Chevron nor any affiliates of ChevronTexaco have an interest in OCS-G-19800.
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, 2005. 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 2 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 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 or based on actual production. When revenues are reported on actual production, there is no gas imbalance created. Under the cash 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. Total future net revenues attributable to the Partnership’s interest in the Royalty were estimated at $48.0 million as of October 31, 2005 based on the reserve study of DeGolyer and MacNaughton. The Partnership’s Royalty income for a period reflects the actual gas sold during the period.
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 $600,000 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. These 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, 2005 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.
DEGOLYER AND MACNAUGHTON
4925 GREENVILLE AVENUE, SUITE 400
ONE ENERGY SOUARE
DALLAS, TEXAS 75206
LETTER REPORT
as of
OCTOBER 31, 2005
on
RESERVES and REVENUE
of
CERTAIN PROPERTIES
owned by the
TEL OFFSHORE TRUST PARTNERSHIP
SEC CASE
DEGOLYER AND MACNAUGHTON
4925 GREENVILLE AVENUE, SUITE 400
ONE ENERGY SOUARE
DALLAS, TEXAS 75206
January 31,
Chevron U.S.A. Inc.
Chevron Place
935 Gravier Street
New Orleans, Louisiana 70012
Gentlemen:
Pursuant to your request, we have prepared estimates, as of October 31, 2005, 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 U.S.A. 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 consisting 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. The SONAT property was subsequently acquired by Amerada Hess Corporation (Amerada Hess) effective January 1, 1998, which property was then acquired by Anadarko Petroleum Corporation (Anadarko) effective June 1, 2003 and subsequently acquired by Apache Corporation (Apache) effective October 1, 2004. Another of the Pennzoil Subject Properties was acquired by Devon Energy Production Co. (Devon) effective December 29, 1999. Chevron Corporation, of which Chevron is a wholly owned subsidiary, and Texaco Inc., of which Texaco is a wholly owned subsidiary, merged on October 9, 2001. As a result of the merger, Texaco became a wholly owned subsidiary of Chevron Corporation. Subsequent to the merger, Texaco assigned the interests in its properties to Chevron. These companies mentioned herein are hereinafter referred to as the Owners. The Managing Partner of the Trust Partnership is Chevron.
Information used in the preparation of this report was obtained from the Owners. During this investigation, we consulted freely with the officers and employees of the Owners 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 the Owners 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. Additionally, this information includes data supplied by Petroleum Information/Dwights LLC; Copyright 2005 Petroleum Information/Dwights LLC.
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, 2005. Combined net reserves are defined as those reserves remaining after deducting royalties and interests owned by others from gross reserves. Net reserves are defined as that portion of the combined net reserves attributable to the interests owned by the Trust Partnership. Gas volumes are expressed as sales-gas reserves at a temperature of 60 degrees Fahrenheit and at a legal pressure base 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 of delivery, after reduction for fuel usage, flare, and shrinkage resulting from field separation and processing. 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.
All of the proved reserves estimated herein are classified as proved developed. There are no proved undeveloped reserves for the properties evaluated in this report.
The properties evaluated consist of 17 leases located offshore from Louisiana. These 17 leases include 9 productive properties (including 2 leases covering separate portions of the south half of Ship Shoal Block 183) and 8 leases to which no reserves have been assigned. Devon, Pennzoil, Apache, and Amoco own an interest in one property each, none of which are productive. Chevron owns an interest in the remaining 13 properties, including 4 to which no reserves have been assigned.
The reserves volumes and revenue values shown in this report were estimated from projections of reserves and revenue attributable to the “Combined Interests,” defined herein as the Trust Partnership Interests and the interests retained in the Subject Properties by Chevron, Pennzoil, Apache, Amoco, or Devon. 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:
Trust Partnership Interest net reserves =
Trust Partnership Interest
future net revenue
´ Combined net reserves
Combined future gross revenue
This formula was applied separately to the Pennzoil, Apache, Amoco, and Devon groups of properties and then to the Chevron (remaining properties) group; the results were then added together to obtain the total reserves 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, Apache, Amoco, or Devon interests in the reservoir unit are used to estimate these Combined Interests net reserves.
Data available from wells drilled on the appraised properties through October 2005 were used in estimating gross ultimate recovery. Gross production through October 31, 2005, was deducted from the gross ultimate recovery to arrive at estimates of gross reserves. Production from some of the properties was halted in the third quarter of 2005 as a result of hurricanes. Production is expected to resume in the first quarter of 2006.
Estimated net proved reserves attributable to the Trust Partnership Interest, as of October 31, 2005, are summarized as follows, expressed in barrels (bbl) and thousands of cubic feet (Mcf):
(1) Production was estimated based on the ratio as of October 31, 2004, of the Trust Partnership Interest net reserves to the Combined Interests net reserves. This ratio was then applied to the production net to the Combined Interests for the period from November 1, 2004 through October 31, 2005.
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 Interests. These monthly values for the aggregate of the Combined Interests 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 2006. 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 1.98 percent per year as specified by Chevron was credited monthly. 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, Apache, Amoco, and Devon). Interest was charged monthly on the net profits deficit balances (costs not recovered currently) at the rate of 1.98 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 estimates 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 United States 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, 2005. The following assumptions were used for estimating future prices and costs:
Oil and Condensate Prices
Oil and condensate prices were furnished by Chevron and were the prices in effect on October 31, 2005. These prices were used as initial prices with no increases based on inflation.
Natural Gas Prices
Initial gas prices furnished by Chevron were prices in effect on October 31, 2005. These initial prices were held constant for the life of the properties.
Operating Expenses and Capital Costs
Current estimates of operating expenses were used for the life of the properties with no increases in the future based on inflation. Future capital expenditures were estimated using 2005 values and were not adjusted for inflation. Abandonment costs have been estimated as capital costs for all properties, including the eight leases which are considered depleted and to which no reserves have been assigned.
A summary of estimated revenue and costs attributable to the Combined Interests 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, 2005, 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.
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
Thomas A. Schob, P.E.
Senior Vice President
DeGolyer and MacNaughton
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.
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 the years ended December 31, 2004 and 2005, all of Chevron’s natural gas and natural gas liquids relative to the Trust’s Royalty Properties were committed and sold to Chevron Texaco Natural Gas at spot market prices. Prior to April 2003, all of Chevron’s natural gas and natural gas liquids relative to the Trust’s Royalty Properties had been committed and sold to Dynegy, Inc. (“Dynegy”) at spot market prices. See “Certain Relationships and Related Transactions” under Item 13 of this Form 10-K.
During 2003, Dynegy made a strategic decision to exit the natural gas marketing and trading business and requested Chevron to consider early termination of the existing contracts. In January 2003, Chevron and a subsidiary of Dynegy agreed to terminate those contracts which had been scheduled to run through August 2006. In April 2003, Chevron formed a new division, ChevronTexaco Natural Gas, to market its production to various third party purchasers under a mix of term and spot agreements.
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 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 21% of the revenues from natural gas sales from the Royalty Properties in 2005. The average price received for natural gas from all of the Working Interest Owner’s purchasers on West Cameron 643 during 2005 was $6.97 per Mcf.
East Cameron 371/381. East Cameron 371/381 has negative revenues from natural gas sales during 2005 as a result of adjustments made by the Working Interest Owner.
Ship Shoal 182/183. Ship Shoal 182/183 contributed approximately 39% of the revenues from gas sales from the Royalty Properties in 2005. The average price received for natural gas from all of the Working Interest Owner’s purchasers on Ship Shoal 182/183 during 2005 was $7.23 per Mcf.
Eugene Island 339. Eugene Island 339 contributed approximately 40% of the revenues from natural gas sales from the Royalty Properties in 2005. The average price received for natural gas from all of the Working Interest Owner’s purchasers on Eugene Island 339 during 2005 was $7.55 per Mcf.
Oil Marketing
Crude oil purchases by ChevronTexaco, accounted for approximately 99% of total crude oil revenues from the Royalty Properties during both 2004 and 2005.
During 2002 and through March 2003, Equiva Trading Company (Texaco’s crude marketing joint venture) purchased crude oil pursuant to TEPI’s tendering program based on the prices TEPI received from third parties under a competitive bidding procedure. Beginning in April 2003, Chevron began marketing the crude oil through its downstream company, Global Trading.
The Supply and Distribution Department of Chevron currently 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 year 2005 ranged from $44.58 per barrel to $59.92 per barrel.
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.
FERC Regulation
In general, the FERC regulates the tansportation of natural gas in interstate commerce by interstate pipelines. Over the course of approximately the previous decade, the FERC adopted regulations resulting in a restructuring of the natuni gas industry. The principal elements of this restructuring were the requirement that interstate pipelines separate, or “unbundle,” into individual components the various services offered on their systems, with all transportation services to be provided on a non-discriminatory basis, and the prohibition against an interstate pipeline providing gas sales services except through separately-organized affiliates. In various rulemaking proceedings following its initial unbundling requirement, the FERC has refined its regulatory program applicable to interstate pipelines in various respects, and it has announced that it will continue to monitor these regulations to detennine whether further changes are needed. As to these various developments, the working interest owners have advised the Trust that the on-going and evolving nature of these regulatory initiatives makes it impossible to predict their ultimate impact on the prices, markets or teims of sale of namral gas related to the Trust.
State and Other Regulation
State regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, non-discriminatory take requirements. Some states have implemented more stringent legislation in recent years to regulate gathering rates charged by gas gathering companies, but to date the effect on the Working Interests Owners in connection with the Trust has been minimal.
Natural gas pipeline facilities used for the transportation of natural gas in interstate commerce are subject to Federal minimum safety requirements. These requirements, however, are not applicable to, inter alia,: (1) onshore gathering facilities outside: (i) the limits of any incorporated or unincorporated city, town, or village; and (ii) any designated residential or commercial area; or (2) pipeline facilities on the Outer Continental Shelf (“OCS”) upstream of the point at which operating responsibility transfers from a producing operator to a transporting operator. See 49 C.F.R. § 192.1(b). We are informed that the Royalty Properties are located in Federal waters on the OCS. The standards governing pipeline safety have undergone recent changes and it is possible that future changes in the regulations and statutes may occur which may increase the stringency of the standards or expand the applicability of the standards to facilities not currently covered.
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. In 1998, the Minerals Management Service adopted regulations for establishing the amount of OSFR required for particular facilities. The amount of OSFR increases as the volume of a facility’s worst-case oil spill increases. Accordingly, for facilities with worst-case spills of less than 35,000 barrels, only $35 million in OSFR is required; for worst-case spills of over 35,000 barrels, $70 million is required; for worst-case spills of over 70,000 barrels, $105 million is required; and for worst-case spills of over 105,000 barrels, $150 million is required. In addition, all OSFR below $150 million remains subject to upward regulatory adjustment if warranted by the particular operational, environmental, human health or other risks involved with a facility. The Working Interest Owners are currently maintaining their required OSFR. 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, 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. The Working Interest Owners have advised the Trust that these costs have not had 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 capital expenditures 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 1A.
Item 1A. Risk Factors.
Although risk factors are described elsewhere in this Form 10-K together with specific forward-looking statements, the following is a summary of the principal risks associated with an investment in Units in the Trust.
Natural gas and oil prices fluctuate due to a number of factors, and lower prices will reduce net proceeds available to the Trust and distributions to Trust Unit holders.
The Trust’s quarterly distributions are highly dependent upon the prices realized from the sale of natural gas and oil. Natural gas and oil prices can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond the control of the Trust and the Working Interest Owners. Factors that contribute to price fluctuation include, among others:
· political conditions worldwide, in particular political disruption, war and other armed conflict in oil producing regions such as Iraq;
· worldwide economic conditions;
· weather conditions;
· the supply and price of foreign natural gas;
· the level of consumer demand;
· the price and availability of alternative fuels;
· the proximity to, and capacity of, transportation facilities; and
· the effect of worldwide energy conservation measures.
Moreover, government regulations, such as regulation of natural gas and oil transportation and price controls, can affect product prices in the long term.
Lower natural gas and oil prices may reduce the amount of natural gas and oil that is economic to produce and reduce net profits available to the Trust. The volatility of energy prices reduces the predictability of future cash distributions to Unit holders. A significant percentage of the natural gas and natural gas liquids produced from the Royalty Properties is currently being sold to various third party purchasers under a mix of term and spot agreements by ChevronTexaco Natural Gas. A majority of crude oil produced by the Royalty Properties is being sold to subsidiaries of ChevronTexaco in competitive bidding or based on pricing bulletins.
Increased production and development costs for the Royalty will result in decreased Trust distributions.
Production and development costs attributable to the Royalty are deducted in the calculation of the Trust’s share of net proceeds. Accordingly, higher or lower production and development costs, without concurrent increases in revenues, directly decrease or increase the amount received by the Trust for the Royalty.
During 2005, Hurricane Katrina and Hurricane Rita caused significant damage to various platforms and third-party transportation systems. The extensive damage caused by these hurricanes has led to significant demand for services and supplies for repairs in the offshore Gulf of Mexico. These incurred costs may reduce Royalty income.
If development and production costs of the Royalty exceed the proceeds of production from the Royalty Properties, the Trust will not receive net proceeds for those properties until future proceeds from production exceed the total of the excess costs plus accrued interest during the deficit period. Development activities may not generate sufficient additional revenue to repay the costs.
Trust reserve estimates depend on many assumptions that may prove to be inaccurate, which could cause both estimates of reserves and estimated future revenues to be too high or too low.
The value of the Units depends upon, among other things, the amount of reserves attributable to the Royalty and the estimated future value of the reserves. Estimating reserves is inherently uncertain. Ultimately, actual production, revenues and expenditures for the underlying properties will vary from estimates and those variations could be material. Petroleum engineers consider many factors and make assumptions in estimating reserves. Those factors and assumptions include:
· historical production from the area compared with production rates from similar producing areas;
· the assumed effect of governmental regulation; and
· assumptions about future commodity prices, production and development costs, severance and excise taxes, and capital expenditures.
Changes in these assumptions can materially change reserve estimates.
The reserve quantities attributable to the Royalty and revenues are based on estimates of reserves and revenues for the underlying properties. The method of allocating a portion of those reserves to the Trust is complicated because the Trust, indirectly through the Partnership, holds an interest in the Royalty and does not own a specific percentage of the natural gas reserves.
The Trustee also relies entirely on reserve estimates and related information prepared by Chevron and the independent reserve engineer engaged by the Trust. While the Trustee has no reason to believe the reserve estimates included in this report are not accurate, to the extent additional information exists that could affect their reserve estimates, the estimated reserves in these reports could also be too low.
Operating risks for the Working Interest Owners’ interests in the Royalty Properties can adversely affect Trust distributions.
The occurrence of drilling, production or transportation accidents and other natural disasters at any of the Royalty Properties will reduce Trust distributions by the amount of uninsured costs. These occurrences include blowouts, cratering, explosions and other environmental damage. Offshore activities are also subject to a variety of additional operating risks, such as hurricanes and other weather disturbances. These accidents may result in personal injuries, property damage, damage to productive formations or equipment and environmental damages. Any uninsured costs would be deducted as a production cost in calculating net proceeds payable to the Trust.
As described in this report, Hurricanes Katrina and Rita caused significant damage during 2005. Even if platforms and facilities on the Royalty Properties are restored in a timely manner during 2006, delays in repairs on third-party transportation systems may continue to limit production and Royalty income from the Royalty Properties.
The operators of the working interests are subject to extensive governmental regulation.
Offshore oil and gas operations have been, and in the future will be, affected by federal, state and local laws and regulations and other political developments, such as price or gathering rate controls and environmental protection regulations. These regulations and changes in regulations could have a material adverse effect on Royalty income payable to the Trust.
None of the Trustees, the Trust nor its Unit holders control the operation or development of the Royalty Properties and have little influence over operation or development.
Neither the Trustees nor the Unit holders can influence or control the operation or future development of the underlying properties. The Royalty Properties are owned by independent Working Interest Owners. The Working Interest Owners manage the underlying properties and handle receipt and payment of funds relating to the Royalty Properties and payments to the Trust for the Royalty.
Information regarding operations provided by the Working Interest Owners has been subject to errors and adjustments, some of which have been significant. Accordingly, the Trustees cannot assure Unit holders that other errors or adjustments by Working Interest Owners, whether historical or future, will not affect future Royalty income and distributions by the Trust.
The current Working Interest Owners are under no obligation to continue operating the properties. Neither the Trustees nor the Unit holders have the right to replace an operator.
The Trustee relies upon the working interests owners and managing general partner for information regarding the Royalty Properties.
The Trustee relies on the working interest owners and managing general partner for information regarding the Royalty Properties. The working interest owners alone control (i) historical operating data, including production volumes, marketing of products, operating and capital expenditures, environmental and other liabilities, effects of regulatory changes and the number of producing wells and acreage, (ii) plans for future operating and capital expenditures, (iii) geological data relating to reserves, as well as related projections regarding production, operating expenses and capital expenses used in connection with the preparation of the reserve report, (iv) forward-looking information relating to production and drilling plans and (v) information regarding the Royalty Properties responsive to litigation claims. While the Trustee requests material information for use in periodic reports as part of its disclosure controls and procedures, the Trustee does not control this information and relies entirely on the working interest owners to provide accurate and timely information when requested for use in the Trust’s periodic reports. The Trustee also relies on the managing general partner of the Partnership to collect certain information
from the working interest owners and does not have any direct contact with the working interest owners other than the managing general partner. Under the terms of the Trust Indenture, the Trustee is entitled to rely, and in fact relies, on certain experts in good faith. While the Trustee has no reason to believe its reliance on experts is unreasonable, this reliance on experts and limited access to information may be viewed as a weakness as compared to the management and oversight to entity forms other than trusts.
The owner of any Royalty Property may abandon any property, terminating the related Royalty.
The Working Interest Owners may at any time transfer all or part of the Royalty Property to another unrelated third party. Unit holders are not entitled to vote on any transfer, and the Trust will not receive any proceeds of any such transfer. Following any transfer, the Royalty Properties will continue to be subject to the Royalty, but the net proceeds from the transferred property would be calculated separately and paid by the transferee. The transferee would be responsible for all of the obligations relating to calculating, reporting and paying to the Trust the Royalty on the transferred portion of the Royalty Properties, and the current owner of the Royalty Properties would have no continuing obligation to the Trust for those properties.
The current Working Interest Owners or any transferee may abandon any well or property if it reasonably believes that the well or property can no longer produce in commercially economic quantities. This could result in termination of the Royalty relating to the abandoned well.
The Royalty can be sold and the Trust can be terminated.
The Trust will be terminated and the Trustees must sell the Royalty if holders of a majority of the Units approve the sale or vote to terminate the Trust, or if the total future net revenues attributable to the Royalty, determined by the independent reserve engineer as of December 31 of the prior year, are less than $2 million. Following any such termination and liquidation, the net proceeds of any sale will be distributed to the Unit holders and Unit holders will receive no further distributions from the Trust. We cannot assure you that any such sale will be on terms acceptable to all Unit holders. For a more complete description of these matters, see “-Termination of the Trust” under Item 1 of this Form 10 K.
Trust assets are depleting assets and, if the Working Interest Owners or other operators of the Royalty Properties do not perform additional development projects, the assets may deplete faster than expected.
The net proceeds payable to the Trust are derived from the sale of depleting assets. Accordingly, the portion of the distributions to Unit holders attributable to depletion may be considered a return of capital. The reduction in proved reserve quantities is a common measure of depletion. Future maintenance and development projects on the Royalty Properties will affect the quantity of proved reserves. The timing and size of these projects will depend on the market prices of natural gas. If operators of the Royalty Properties do not implement additional maintenance and development projects, the future rate of production decline of proved reserves may be higher than the rate currently expected by the Trust. For federal income tax purposes, depletion is reflected as a deduction, which is dependent upon the purchase price of a Units. Please see the section entitled “-Description of the Units-Federal Income Tax Matters” under Item 1 of this Form 10-K.
Unit holders have limited voting rights
Voting rights as a Unit holder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of Unit holders or for an annual or other periodic re-election of the Trustees. Unlike corporations which are generally governed by boards of directors elected by their equity holders, the Trust is administered by a Corporate Trustee and three
Individual Trustees in accordance with the Trust Agreement and other organizational documents. The Trustees have extremely limited discretion in their administration of the Trust.
Unit holders have limited ability to enforce the Trust’s rights against the current or future owners of the Royalty Properties.
The Trust Agreement and related trust law permit the Trustees and the Trust to sue the Working Interest Owners to compel them to fulfill the terms of the Conveyance of the Royalty. If the Trustees do not take appropriate action to enforce provisions of the Conveyance, the recourse of a Unit holder would likely be limited to bringing a lawsuit against the Trustees to compel the Trustees to take specified actions. Unit holders probably would not be able to sue the Working Interest Owners directly.
Item 1B.
Item 1B. Unresolved Staff Comments.
There were no unresolved Securities and Exchange Commission comments as of December 31, 2005.
Item 2.
Item 2. Properties.
Reference is made to Item 1 of this Form 10-K.
Item 3.
Item 3. Legal Proceedings.
Currently, there are not any legal proceedings pending.
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 2005.
PART II
Item 5.
Item 5. Market for the Registrant’s Common Equity and Related Stockholder Matters
The Trust Units are traded on the Nasdaq SmallCap Market. At December 31, 2005, the 4,751,510 Units outstanding were held by 2,488 Unit Holders of record. The high and low sales price as reported by the Nasdaq SmallCap Market, and distributions for each quarter for the years ended December 31, 2005 and 2004, were as follows:
Item 6.
Item 6. Selected Financial Data.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Critical Accounting Policies
The financial statements of the Trust are prepared on the following basis:
(a) Royalty income is recorded when received, including the effect of overtaken or undertaken positions and negative or positive adjustments, by the Corporate Trustee on the last business day of each calendar quarter. In addition, Royalty income includes amounts related to funds deposited or released from the Special Cost Escrow account-see (c); and
(b) Trust general and administrative expenses are recorded when paid, except for the cash reserved for future general and administrative expenses.
(c) The funds deposited or released from the Special Cost Escrow account are recorded at the time of payment or receipt. The Special Cost Escrow account is an account of the Working Interest Owners and is not reflected in the financial statements of the Trust.
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 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 net overriding royalty interest, calculated on a units-of-production basis, is charged directly to Trust corpus since such amount does not affect distributable income.
The Trustees, including the Corporate Trustee, have no authority over, have not evaluated and make no statement concerning, the internal control over financial reporting of the Working Interest Owner.
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 of this Form 10-K, which contains certain unaudited supplemental reserve information, for an estimate of future Royalty income attributable to the Partnership, of which the Trust has a 99.99% interest.
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.
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. 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. In the first quarter of 1998, the Trust determined that the Trust’s cash reserve was currently sufficient to provide for future administrative expenses in connection with the winding up of the Trust. The Trust determined that a cash reserve equal to three times the average expenses of the Trust during each of the past three years was sufficient at this time to provide for future administrative expenses in connection with the winding up of the Trust.
The reserve amount at December 31, 2004 and 2005 was $1,341,014 and $1,364,203, respectively. During the first and second quarters of 2004, the Trust used $148,798 and $56,333, respectively, from the Trust’s cash reserve account to pay the Trust’s general and administrative expenses when insufficient Royalty income was received by the Trust.
Operations
The following operational information has been based on information provided to the Corporate Trustee by Chevron as the Managing General Partner of the Partnership and by the applicable Working Interest Owners. The Trustees have no control over these operations or internal controls relating to this information.
At the end of October 2005, approximately half of Chevron oil-equivalent production in the Gulf of Mexico remained shut in due to damages from hurricanes in the third quarter. The time it will take to resume this production is uncertain, and some of the volumes may not be sufficiently economic to restore. The impact to the Trust properties is estimated to be a 68% reduction in production. Eugene Island 339 remains shut-in, but production is currently expected to resume later in 2006 after a new sales platform is built by the operator to replace the Eugene Island 338 sales platform destroyed by Hurricane Rita, and assuming transportation availability is fully restored on a third-party transmission pipeline that incurred significant hurricane-related damages. The operator of this pipeline has advised that hurricane-related damages on their pipeline are more extensive than previously thought, and the Working Interest Owner has advised the Trustee that it is currently evaluating various alternatives for transportation as production is also restored. On Ship Shoal 182/183, gas production remains shut-in due to the Tennessee Gas pipeline being down. Major repairs are underway and gas production on Ship Shoal 182/183 is expected to resume in the second quarter of 2006. On West Cameron 643, production has remained shut-in since September 2005 following Hurricane Rita’s major damage to various platforms, but gas production on this field is expected to resume in mid-2006.
Years 2005 and 2004
Royalty income increased approximately 65% from $5,987,936 in 2004 to $9,854,531 in 2005 primarily due to an increase in gas revenues and crude oil and condensate revenues as discussed below.
For 2005 and 2004, the Trust had no undistributed net income or loss. Undistributed net income represents positive Net Proceeds generated during the period that were applied to an existing loss carryforward. Undistributed net loss represents negative Net Proceeds generated during the respective period. An undistributed net loss is carried forward and offset, in future periods, by positive Net Proceeds earned by the related Working Interest Owner(s).
Volumes and dollar amounts discussed below represent amounts recorded by the Working Interest Owners unless otherwise specified.
Natural Gas and Gas Products
Natural gas revenues and gas products decreased 4% from $17,002,431 in 2004 to $16,337,625 in 2005, partially offset by a 22% increase in the average price received for natural gas from $6.07 per Mcf in 2004 to $7.31 Mcf in 2005. Natural gas and gas products volumes decreased 21% from 2,907,514 Mcf in 2004 to 2,287,314 Mcf in 2005.
The Working Interest Owners of the East Cameron 371/381 property advised the Trust that, as of October 31, 2004, 26,891 Mcf had been overtaken by the Working Interest Owners from those properties. In addition, the Working Interest Owners of the East Cameron 353 and the West Cameron 643 properties advised the Trust that, as of October 31, 2004, 518 Mcf and 23,340 Mcf respectively, had been undertaken from these properties. 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. During 2005, all cumulative gas imbalances with the Trust were settled with the Working Interest Owner.
During the first quarter of 2004, Chevron informed the Trustees that it would make downward adjustments to revenues and production based on an improper credit to the Trust of revenues and production on Eugene Island 339. This improper credit relates to production credited from wells in which the Trust has no interest from as early as June 2002 through October 2003. The aggregate amount of these adjustments are expected to be approximately 236,650 barrels of oil or $6,449,000 for oil revenues, as well as 91,000 Mcf or $505,000 for gas revenues. Recovery by Chevron of these amounts, as well as certain capital expenditures discussed below, affected Royalty income and distributable income in the first and second quarters of 2004.
Crude Oil and Condensate
Crude oil and condensate revenues increased 44% from $22,332,005 in 2004 to $32,051,988 in 2005, due primarily to a 10% increase in crude oil and condensate volumes from 589,647 barrels in 2004 to 650,466 barrels in 2005. Additionally, average crude oil and condensate prices increased by 30% from $37.87 in 2004 to $49.28 in 2005.
Operating and Capital Expenditures
Operating expenses paid by the Working Interest Owners decreased 12% from $4,852,591 in 2004 to $4,257,481 in 2005.
Capital expenditures paid by the Working Interest Owners decreased 88% from $21,673,290 in 2004 to $2,587,321 in 2005.
Special Cost Escrow Account
The special cost escrow account is an account of the Working Interest Owners, and it is described herein for information purposes only. The Conveyance provides for the reserve of 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, $115,520 and $66,700 in 2005 and 2004, respectively serves to reduce the Trust’s share of allocated production costs. Special Cost Escrow 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 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 estimated 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.
Chevron, in its capacity as Managing General Partner of the Partnership, has advised the Trust that 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 on the estimates and factors described above. Such deposits could result in a significant reduction on Royalty
income on the periods in which such deposits are made, including the possibility that no Royalty income would be received in such periods.
In the first quarter of 2006, there was a net deposit of funds to the Special Cost Escrow Account of approximately $876,000.
In 2005, the Working Interest Owners deposited a net amount to the Trust of $239,000 from the Special Cost Escrow Account. The lower net deposits compared to 2003 were primarily due to a continued decrease in the estimate of projected capital expenditures, production costs and abandonment costs of the Royalty Properties. As of December 31, 2005, approximately $5,616,000 remained in the Special Cost Escrow Account.
In 2004, the Working Interest Owners released a net amount to the Trust of $3,268,000 from the Special Cost Escrow Account. The release was made primarily due to a decrease in the estimate of projected capital expenditures, production costs and abandonment costs of the Royalty Properties. As of December 31, 2004, approximately $5,376,000 remained in the Special Cost Escrow Account.
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.
Summary By Property
Listed below is a summary of 2005 operations as compared to 2004 of the four principal Royalty Properties based on gross revenues generated during these periods combined.
Eugene Island 339
Eugene Island 339 crude oil revenues increased $7,828,063, from $6,864,643 in 2004 to $14,692,706 in 2005 primarily due to an increase in production. Crude oil production increased from 163,131 barrels in 2004 to 312,252 barrels in 2005. The average price of crude oil increased from $42.08 per barrel in 2004 to $47.05 per barrel in 2005. Gas revenues increased $2,740,898, from $4,303,452 in 2004 to $7,044,350 in 2005 primarily due to an increase in the average price received for natural gas from $6.36 per Mcf in 2004 to $7.55 per Mcf in 2005. Gas production increased from 764,093 Mcf in 2004 to 974,036 Mcf in 2005. Capital expenditures decreased from $11,290,421 in 2004 to $931,625 in 2005. Operating expenses decreased from $1,560,278 in 2004 to $1,388,428 in 2005.
Chevron has advised the Trust that the foregoing comparison does not give effect to an improper credit of revenues and production and a miscalculation of capital expenditures that was allocated during the first quarter of 2004 and recovered by Chevron during that period and in the second quarter. The aggregate amount of these adjustments for improper credits of production and revenues from as early as June 2002 through October 2003 were approximately 236,650 barrels of oil or $6,449,000 for oil revenues, as well as 91,000 Mcf or $505,000 for gas revenues. The comparison above is included without adjustment as Royalty income for these periods was calculated and paid based on these amounts.
Ship Shoal 182/183
Ship Shoal 182/183 crude oil revenues increased from $15,408,655 in 2004 to $16,962,280 in 2005, partially offset by a decrease in crude oil production from 426,449 barrels in 2004 to 330,512 barrels in 2005. The average crude oil price increased from $36.13 per barrel in 2004 to $51.32 per barrel in 2005. Gas revenues decreased from $11,179,380 in 2004 to $6,095,350 in 2005 due to a decrease in gas volumes from 1,872,307 Mcf in 2004 to 859,925 Mcf in 2005. The average natural gas sales price increased from
$6.05 per Mcf in 2004 to $7.23 per Mcf in 2005. Capital expenditures decreased from $10,292,460 in 2004 to $1,525,562 in 2005. Operating expenses decreased from $2,565,505 in 2004 to $1,507,792 in 2005.
West Cameron 643
West Cameron 643 gas revenues increased from $1,100,793 in 2004 to $3,163,457 in 2005 due primarily to an increase in gas volumes from 193,978 Mcf in 2004 to 453,674 Mcf in 2005. The average natural gas sales price increased from $5.67 per Mcf in 2004 to $6.97 per Mcf in 2005. Operating expenses increased from $592,357 in 2004 to $1,324,101 in 2005, capital expenditures increased from $19,680 in 2004 to $86,286 in 2005.
East Cameron 371/381
East Cameron 371/381 gas revenues decreased from $119,196 in 2004 to ($99,126) in 2005 due primarily to a decrease in gas volumes from 24,665 Mcf in 2004 to (20,463) Mcf in 2005. Partially offset by a decrease in the average price for natural gas from $5.49 in 2004 to $4.47 in 2005. Crude oil revenues decreased from $36,215 in 2004 to ($42,171) in 2005 due primarily to a decrease in crude oil and condensate volumes. Capital expenditures decreased from $1,497 in 2004 to ($1,560) in 2005 and operating expenses decreased from $58,638 in 2004 to ($11,116) in 2005. East Cameron 371/381 has negative revenues, capital expenditures and operating expenses during 2005 as a result of adjustments made by the Working Interest Owner.
Years 2004 and 2003
Royalty income increased approximately 43% from $4,174,682 in 2003 to $5,987,936 in 2004 primarily due to an increase in gas revenues and crude oil and condensate revenues as discussed below.
For 2004, the Trust had no undistributed net income or loss, compared to undistributed net income of $43,468 in 2003.
Volumes and dollar amounts discussed below represent amounts recorded by the Working Interest Owners unless otherwise specified.
Natural Gas and Gas Products
Gas revenues increased 92% from $8,854,319 in 2003 to $17,002,431 in 2004, partially due to a 9% increase in the average price received for natural gas from $5.44 per Mcf in 2003 to $6.07 per Mcf in 2004. The increase in gas revenue was also due to a 76% increase in gas volumes from 1,650,603 Mcf in 2003 to 2,907,514 Mcf in 2004. The increase in gas volumes were primarily due to a new well on Ship Shoal 182/183 that came online in January 2004 partially offset by wells sanding upon West Cameron 643.
During the first quarter of 2004, Chevron informed the Trustees that it would make downward adjustments to revenues and production based on an improper credit to the Trust of revenues and production on Eugene Island 339. This improper credit relates to production credited from wells in which the Trust has no interest from as early as June 2002 through October 2003. The aggregate amount of these adjustments are expected to be approximately 236,650 barrels of oil or $6,449,000 for oil revenues, as well as 91,000 Mcf or $505,000 for gas revenues. Recovery by Chevron of these amounts, as well as certain capital expenditures discussed below, affected Royalty income and distributable income in the first and second quarters of 2004.
The Working Interest Owners of the East Cameron 371/381 property have advised the Trust that, as of October 31, 2004, 26,891 Mcf had been overtaken by the Working Interest Owners from those properties. In addition, the Working Interest Owners of the East Cameron 353 and the West Cameron 643 properties have advised the Trust that, as of October 31, 2004, 518 Mcf and 23,340 Mcf respectively, had
been undertaken from these properties. 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. Chevron has advised the Trust that it believes sufficient gas reserves exist on East Cameron 353 and West Cameron 643 for underproduced parties to recoup their share of the gas imbalance on these properties.
Crude Oil and Condensate
Crude oil and condensate revenues decreased 37% from $35,660,352 in 2003 to $22,332,005 in 2004, due primarily to a 52% decrease in crude oil and condensate volumes from 1,231,268 barrels in 2003 to 589,647 barrels in 2004. Additionally, average crude oil and condensate prices increased by 31% from $28.96 in 2003 to $37.87 in 2004.
Operating and Capital Expenditures
Operating expenses paid by the Working Interest Owners increased 90% from $2,550,959 in 2003 to $4,852,591 in 2004.
Capital expenditures paid by the Working Interest Owners increased 157% from 8,417,420 in 2003 to $21,673,290 in 2004, due primarily to costs associated with drilling the new well on Ship Shoal 182/183 in the first quarter, and drilling costs on the C-20 and C-21 wells on Eugene Island 339 in the first quarter.
Special Cost Escrow Account
The special cost escrow account is an account of the Working Interest Owners, and it is described herein for information purposes only. The Conveyance provides for the reserve 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, $66,700 and $55,800 in 2004 and 2003, respectively serves to reduce the Trust’s share of allocated production costs. 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 paid. 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 2005, there was a net deposit of funds to the Special Cost Escrow Account of approximately $1,922,788.
In 2004, the Working Interest Owners released a net amount to the Trust of $3,267,975 from the Special Cost Escrow Account. The release was made primarily due to a decrease in the estimate of projected capital expenditures, production costs and abandonment costs of the Royalty Properties. As of December 31, 2004, approximately $5,376,000 remained in the Special Cost Escrow Account.
In 2003, the Working Interest Owners deposited a net amount of $3,812,816 into the Special Cost Escrow Account. The deposit was made primarily due to an increase in the estimate of projected capital expenditures, production costs and abandonment costs of the Royalty Properties. As of December 31, 2003, approximately $8,573,000 remained in the Special Cost Escrow Account.
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.
Summary By Property
Listed below is a summary of 2004 operations as compared to 2003 of the four principal Royalty Properties based on gross revenues generated during these periods combined.
Eugene Island 339
Eugene Island 339 crude oil revenues decreased $9,777,942, from $16,642,585 in 2003 to $6,864,643 in 2004 primarily due to a decrease in production. Crude oil production decreased from 583,943 barrels in 2003 to 163,131 barrels in 2004. The average price of crude oil increased from $28.50 per barrel in 2003 to $42.08 per barrel in 2004. Gas revenues increased $1,245,226, from $3,058,226 in 2003 to $4,303,452 in 2004 primarily due to an increase in the average price received for natural gas from $5.22 per Mcf in 2003 to $6.36 in 2004. Gas production increased from 597,596 Mcf in 2003 to 764,093 Mcf in 2004. Capital expenditures increased from $2,866,910 in 2003 to $11,290,421 in 2004 primarily due to costs associated with drilling the new C-20 and C-21 wells in the first quarter. Operating expenses increased from $493,984 in 2003 to $1,560,278 in 2004 due to an increase in production volumes as well as the October 2003 facility charge that was not allocated in the fourth quarter of 2003.
Chevron has advised the Trust that the foregoing comparison does not give effect to an improper credit of revenues and production and a miscalculation of capital expenditures that was allocated during the first quarter of 2004 and recovered by Chevron during that period and in the second quarter. The aggregate amount of these adjustments for improper credits of production and revenues from as early as June 2002 through October 2003 were approximately 236,650 barrels of oil or $6,449,000 for oil revenues, as well as 91,000 Mcf or $505,000 for gas revenues. The comparison above is included without adjustment as Royalty income for these periods was calculated and paid based on these amounts.
Ship Shoal 182/183
Ship Shoal 182/183 crude oil revenues decreased from $18,011,043 in 2003 to $15,408,655 in 2004, due to a decrease in crude oil production from 614,412 barrels in 2003 to 426,449 barrels in 2004. The average crude oil price increased from $29.31 per barrel in 2003 to $36.13 per barrel in 2004. Gas revenues increased from $1,720,257 in 2003 to $11,179,380 in 2004 due to an increase in gas volumes from 319,431 Mcf in 2003 to 1,872,307 Mcf in 2004. Additionally, the average natural gas sales price increased from $5.53 per Mcf in 2003 to $6.05 in 2004. Capital expenditures increased from $5,206,517 in 2003 to $10,292,460 in 2004 due to drilling costs on the well in the first quarter of 2004. Operating expenses increased from $1,233,467 in 2003 to $2,565,505 in 2004 due to higher allocated volumetric charges.
West Cameron 643
West Cameron 643 gas revenues decreased from $3,047,851 in 2003 to $1,100,793 in 2004 due primarily to a decrease in gas volumes from 543,552 Mcf in 2003 to 193,978 Mcf in 2004. The average natural gas sales price increased from $5.61 per Mcf in 2003 to $5.67 per Mcf in 2004. Operating expenses
decreased from $634,994 in 2003 to $592,357 in 2004, capital expenditures decreased from $1,077,578 in 2003 to $19,680 in 2004.
East Cameron 371/381
East Cameron 371/381 gas revenues decreased from $170,419 in 2003 to $119,196 in 2004 due primarily to a decrease in gas volumes from 38,654 Mcf in 2003 to 24,665 Mcf in 2004 offset by an increase in the average price for natural gas during 2004. Crude oil revenues decreased from $72,174 in 2003 to $36,215 in 2004 due primarily to a decrease in crude oil and condensate volumes. Capital expenditures decreased from $6,136 in 2003 to $1,497 in 2004 and operating expenses increased from $34,478 in 2003 to $58,638 in 2004.
The following schedule provides a summary of the volumes and weighted average prices for crude oil and condensate and natural gas recorded by the Working Interest Owners for the Royalty Properties, as well as the Working Interest Owners’ calculations of the net proceeds and royalties paid to the Trust during the periods indicated. Net proceeds due to the Trust are calculated for each three month period commencing on the first day of February, May, August and November.
(1) Amounts represent actual production for the twelve-month period ended on October 31 of each year, respectively.
(2) Undistributed net loss represents negative Net Proceeds generated during the respective period. An undistributed net loss is carried forward and offset, in future periods, by positive Net Proceeds, earned by the related Working Interest Owner(s). Undistributed net income represents positive Net Proceeds, generated during the respective period, that were applied to an existing loss carryforward. As of December 31, 2005, the loss carryforward was $0.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosure About Market Risk
Reference is made to Item 1 of this Form 10-K.
Item 8.
Item 8. Financial Statements and Supplementary Data
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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 (the “Trust”) as of December 31, 2005 and 2004, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2005. 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 the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Trust is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Trust’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by the Trustees, 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 to the financial statements, these financial statements were prepared on a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.
In our opinion, such financial statements present fairly, in all material respects, the assets, liabilities and trust corpus of TEL Offshore Trust as of December 31, 2005 and 2004, and its distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2005, on the comprehensive basis of accounting described in Note 3.
DELOITTE & TOUCHE LLP
Houston, Texas
March 31, 2006
TEL OFFSHORE TRUST
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
STATEMENTS OF DISTRIBUTABLE INCOME
STATEMENTS OF CHANGES IN 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”) initially 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 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, PennzEnergy Company (“PennzEnergy”) (which merged with and into Devon Energy Production Company L.P. effective January 1, 2000) acquired certain oil and gas producing properties from Chevron, including four of the Royalty Properties. The four Royalty Properties acquired by PennzEnergy were East Cameron 354, Eugene Island 348, Eugene Island 367 and Eugene Island 208. As a result of such acquisition, PennzEnergy replaced Chevron as the Working Interest Owner of these properties on October 30, 1992. PennzEnergy also assumed Chevron’s obligations under the Conveyance with respect to these properties.
On December 1, 1994, Texaco Exploration and Production Inc. (“TEPI”) acquired two of the Royalty Properties from Chevron. The Royalty Properties acquired by Texaco were West Cameron 643 and East Cameron 371/381. As a result of such acquisition, TEPI replaced Chevron as the Working Interest Owner of such properties on December 1, 1994. TEPI also assumed Chevron’s obligations under the Conveyance with respect to these properties.
On October 1, 1995, SONAT Exploration Company (“SONAT”) acquired the East Cameron 354 property from PennzEnergy. In addition, on October 1, 1995, Amoco Production Company (“Amoco”) acquired the Eugene Island 367 property from PennzEnergy. As a result of such acquisitions, SONAT and Amoco replaced PennzEnergy as the Working Interest Owner of the East Cameron 354 and Eugene Island 367 properties, respectively, on October 1, 1995, and also assumed PennzEnergy’s obligations under the Conveyance with respect to these properties.
Effective January 1, 1998 Energy Resource Technology, Inc. (“ERT”) acquired the East Cameron 354 property from SONAT. As a result of this acquisition, ERT 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. In October 1998, Amerada Hess Corporation (“Amerada”) acquired the East Cameron 354 property from ERT effective January 1, 1998.
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS (Continued)
As a result of such acquisition, Amerada replaced ERT as the Working Interest Owner of the East Cameron 354 property effective January 1, 1998, and also assumed Energy’s obligations under the Conveyance with respect to this property.
Effective January 1, 2000, PennzEnergy and Devon Energy Corporation (Nevada) merged into Devon Energy Production Company L.P. (“Devon”). As a result of this merger, Devon replaced PennzEnergy as the Working Interest Owner of Eugene Island 348 and Eugene Island 208 properties effective January 1, 2000, and also assumed PennzEnergy’s obligations under the Conveyance with respect to these properties.
On October 9, 2001, a wholly owned subsidiary of Chevron Corporation, a Delaware corporation, merged (the “Merger”) with and into Texaco Inc., a Delaware corporation (“Texaco”), pursuant to an Agreement and Plan of Merger, dated as of October 15, 2000. As a result of the Merger, Texaco Inc. became a wholly owned subsidiary of Chevron Corporation, and Chevron Corporation changed its name to “ChevronTexaco Corporation” in connection with the Merger (ChevronTexaco Corporation is referred to herein as “ChevronTexaco”). Accordingly, references herein to Chevron and Texaco are properties or entities each now controlled by subsidiaries of ChevronTexaco.
On May 1, 2002, TEPI assigned all of its interests in West Cameron 643 and East Cameron 371/381 to Chevron. Accordingly, pursuant to the Conveyance of the Royalty Properties, Net Proceeds will be calculated for the collective Royalty Properties owned by Chevron after this date.
On June 6, 2003 Anadarko Petroleum Corporation (“Anadarko”) acquired, among other interests, a 25% Working Interest in the East Cameron 354 field subject to The Royalty from Amerada effective April 1, 2003. As a result of this transaction, Anadarko replaced Amerada as the Working Interest Owner of East Cameron 354 effective July 1, 2003 and also assumed Amerada’s obligations under the Conveyance with respect to this property.
Effective October 1, 2004, Apache Corporation (“Apache”) acquired Anadarko’s interest in East Cameron 354 and assumed Anadarko’s obligations under the Conveyance with respect to this property.
All of the Royalty Properties continue to be subject to the Royalty, and it is anticipated that the Trust and Partnership, in general, will 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, 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 (Tenneco 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 Cameron 643 thereafter; PennzEnergy/Devon with respect to East Cameron 354, Eugene Island 348, Eugene Island 367 and Eugene/Devon Island 208 for periods from October 30, 1992 until October 1, 1995, and with respect to Eugene Island 348 and Eugene Island 208 thereafter; TEPI with respect to West Cameron 643 and East Cameron 371/381 for periods beginning on or after December 1, 1994 until May 1, 2002; 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; Amerada with respect to East Cameron 354 for periods beginning on or after January 1, 1998; Chevron with respect to West Cameron 643 and East Cameron 371/381 on and after May 1, 2002; Anadarko with respect to East
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS (Continued)
Cameron 354 on and after July 1, 2003) until October 1, 2004; and Apache with respect to East Cameron 354 after October 1, 2004.
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, 2005 the reserve amount was $1,364,203. During the first and second quarters of 2004, the Trust used $148,798 and $56,333, respectively, from the Trust’s cash reserve account to pay the Trust’s general and administrative expenses, when insufficient Royalty income was received by the Trust. At December 31, 2004 the reserve amount was $1,341,014 .
(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 revenues attributable to the Royalty were estimated at $48 million (unaudited) as of October 31, 2005. 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 currently administered by JPMorgan Chase Bank (formerly known as The Chase Manhattan Bank) (“Corporate Trustee”) and Daniel O. Conwill, IV, Gary C. Evans and Jeffrey S. Swanson (“Individual Trustees”), as trustees (“Trustees”).
(2) Net 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 their oil and gas properties for the period. Generally, “Net Proceeds” means the amounts received by the Working Interest Owners from the sale of minerals from the Royalty Properties less operating and capital costs incurred, management fees and expense reimbursements owing to the Managing General Partner of the Partnership, applicable taxes other than income taxes, and the Special Cost Escrow account. The Special Cost Escrow account is established 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
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS (Continued)
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.
As of October 9, 2001, Chevron Corporation merged with Texaco, and the Royalty Properties owned by TEPI were assigned to Chevron on May 1, 2002. Crude oil sales from the Chevron and TEPI properties added together accounted for approximately 99%, for 2005, 2004 and 2003 of crude oil revenues from the Royalty Properties. Sales to ChevronTexaco accounted for approximately 99%, 94% and 93% of total gas revenues from the Royalty Properties during 2005, 2004 and 2003, respectively.
The Trust’s share of Royalty income was reduced by approximately $418,000, $496,000 and $417,000 in 2005, 2004 and 2003, 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, including the effect of overtaken or undertaken positions and negative or positive adjustments, by the Corporate Trustee on the last business day of each calendar quarter. In addition, Royalty Income includes amounts related to funds deposited or released from the Special Cost Escrow account-see (c);
(b) Trust general and administrative expenses are recorded when paid, except for the cash reserved for future general and administrative expenses; and
(c) The funds deposited or released from the Special Cost Escrow account are recorded at the time of payment or receipt. The Special Cost Escrow account is an account of the Working Interest Owners and is not reflected in the financial statements of the Trust.
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 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 net 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.
The changes in reserve for future Trust expenses includes both changes of amounts deemed necessary by the Trustees and related distributions, as well as amounts paid from the reserve during periods when the Trust has insufficient income to pay Trust expenses.
The Trust reviews net overriding royalty interest in oil and gas properties for possible impairment whenever events or circumstances indicate the carrying amount of the asset may not be recoverable. If there is an indication of impairment, the Trust prepares an estimate of future cash flows (undiscounted and without interest charges) expected to result from the use of the asset and its eventual disposition. If
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS (Continued)
these cash flows are less than the carrying amount of the asset, an impairment loss is recognized to write down the asset to its estimated fair value. Preparation of estimated expected future cash flows is inherently subjective and is based on the Corporate Trustee’s best estimate (based on advice and information provided by the Managing General Partner and working interest owners) of assumptions concerning expected future conditions. There were no write downs taken in the periods presented.
The Special Cost Escrow account (see Note 6) is established for 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. The funds held in the Special Cost Escrow account are not reflected in the financial statements of the Trust. However, funds deposited to or released from the Special Cost Escrow account are included in Royalty income.
The preparation of financial statements requires the Trustees to make use of estimates and assumptions that affect amounts reported in the financial statements as well as certain disclosures. Actual results could differ from those estimates.
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. 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. The Trust does not enter into any hedging transactions on future production.
(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. These distributions are referred to as “distributable income”. 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.
During the quarter ended March 31, 2004, a Working Interest Owner made certain negative adjustments to previously reported Net Proceeds (See Note 5). As a result of these negative adjustments, the Trust at March 31, 2004 had a loss carryforward of $3,307,628. In the second quarter of 2004, Net Proceeds were offset by the loss carryforward of $3,307,628 with a resulting loss carryforward balance of $0 at June 30, 2004. No distributable income was available to Unit holders in the second quarter since the Trust recoups expenses being paid from the reserve for Trust expense that the Trustees have established for anticipated future expenses. During the quarter ended September 30, 2004, the Trust resumed distributions as the reserve for trust expenses had been funded.
Gulf Coast hurricanes caused significant damage during 2005. Even if platforms and facilities on the Royalty Properties are restored in a timely manner during 2006, delays in repairs on third-party transportation systems may continue to limit production and Royalty income from the Royalty Properties.
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS (Continued)
(5) Negative Adjustments
During the quarter ended March 31, 2004, a Working Interest Owner informed the Trust that it had made errors in prior periods which resulted in prior period Net Proceeds being overstated. This Working Interest Owner, Chevron, which is also the Managing General Partner, of the Partnership, has advised the Trust that these errors consisted of:
· Eugene Island 339-a $6,953,982 gross revenue adjustment to reverse revenues previously credited to the Trust for interest in wells that the Trust does not hold an interest, a $98,797 gross operating expense adjustment and a $573,382 adjustment to increase previous capital expenditures.
· Ship Shoal 182/183-a $1,336,287 gross adjustment to reverse revenues previously credited to the Trust primarily for double-counted production and a $1,855,976 adjustment to correct previously recorded adjustments to capital expenditures.
· South Timbalier 36/37 (Royalty Properties associated with Chevron Texaco)-a $495,425 gross adjustment to reverse the effects of clerical errors.
The Trust recorded the adjustments during the first quarter of 2004, which resulted in a loss carryforward of $3,307,628 as of March 31, 2004. In the second quarter of 2004, Net Proceeds were sufficient to fully offset the loss carryforward of $3,307,628, resulting in no further loss carryforward.
(6) Special Cost Escrow Account
The Special Cost Escrow is an account of the Working Interest Owners and it is described herein for informational purposes only. 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 certain 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 $115,520, $66,700 and $56,000 for 2005, 2004 and 2003, respectively, serves to reduce the Trust’s share of allocated production costs. As of December 31, 2005, 2004 and 2003, approximately $5,616,000, $5,376,000 and $8,573,000 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 estimated 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.
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS (Continued)
In the first quarter of 2006, there was a net deposit of funds to the Special Cost Escrow Account of approximately $876,000. 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 2005, the Working Interest Owners deposited a net amount of approximately $239,000 into the Special Cost Escrow Account. In 2004, the Working Interest Owners released a net amount of approximately $3,268,000 into the Special Cost Escrow Account. The deposit and releases were made primarily due to changes in the estimate of projected capital expenditures, production costs and abandonment costs of the Royalty Properties.
(7) Federal Income Tax Matters
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 and each Unit holder will be treated as owning an interest in the Partnership.
(8) Commitments and Contingencies
During 1994, 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. The balance of this amount was recovered from the Trust by the Working Interest Owner during 2003.
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.
On September 21, 2001, the Trust gave written demand to, and on October 11, 2001, the Trust filed suit against TEPI as the then-current Working Interest Owner of the East Cameron 371 lease to account for its payment of the Trust’s overriding royalty interest in this lease. In connection with the foregoing litigation, TEPI had asserted a counterclaim in 2003. During 2003, the Trust entered into a Settlement Agreement and Mutual Release with TEPI pursuant to which TEPI agreed to pay the Trust $75,000. Both of the parties filed a joint motion to dismiss all claims and counterclaims relating to the lawsuit and each party released the other party from all claims and counterclaims relating to the lawsuit.
(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 existing economic and operating conditions in effect at October 31, 2005, 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
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS (Continued)
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. Total future net revenues attributable to the Partnership’s interest in the Royalty were estimated at $48.0 million as of October 31, 2005 based on the reserve study of Degolyer and MacNaughton.
The Partnership’s share of gas sales can be recorded by the Working Interest Owner on the cash method of accounting or based on actual production. When revenues are reported based on actual production, there is no gas imbalance created. Under the cash 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. The Working Interest Owners of the East Cameron 371/381 property advised the Trust that, as of October 31, 2004, 26,891 Mcf had been overtaken by the Working Interest Owners from this property. In addition, the Working Interest Owners of the East Cameron 353 and West Cameron 643 properties advised the Trust that, as of October 31, 2004, 518 Mcf and 23,340 Mcf respectively, had been undertaken by the Working Interest Owners from these properties. 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. During 2005, all cumulative gas imbalances with the Trust were settled with the Working Interest Owner.
Distributable income for the Partnership for the periods ended December 31, 2005, 2004 and 2003 included net proceeds relating to production of reserves from the Royalty Properties for the twelve months ended October 31, 2005, 2004 and 2003, respectively.
(10) Selected Quarterly Financial Data (Unaudited)
Summarized quarterly financial data is as follows:
* 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 6 above.
*****
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
Item 9A. Controls and Procedures.
Evaluation of disclosure controls and procedures. The Corporate Trustee maintains disclosure controls and procedures designed to ensure that information to be disclosed by the Trust in the reports that it files or submits under the Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and regulations. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by the Trust is accumulated and communicated by Chevron as the managing general partner of the Partnership, and the working interest owners to JPMorgan Chase Bank, N.A., as Corporate Trustee of the Trust, and its employees who participate in the preparation of the Trust’s periodic reports as appropriate to allow timely decisions regarding required disclosure.
As of the end of the period covered by this report, the Corporate Trustee carried out an evaluation of the Trust’s disclosure controls and procedures. Mike Ulrich, as Trust Officer and Corporate Trustee, has concluded that the disclosure controls and procedures of the Trust are effective.
Due to the contractual arrangements of (i) the Trust Agreement, (ii) the Partnership Agreement and (iii) the rights of the Partnership under the Conveyance regarding information furnished by the working interest owners, the Trustees rely on (A) information provided by the Working Interest Owners, including historical operating data, plans for future operating and capital expenditures, reserve information and information relating to projected production, (B) information from the managing general partner of the Partnership, including information that is collected from the Working Interest Owners, and (C) conclusions and reports regarding reserves by the Trust’s independent reserve engineers. See Item 1A. Risk Factors “-None of the Trustees, the Trust nor its Unit holders control the operation or development of the Royalty Properties and have little influence over operation or development” in the Trust’s Form 10-K, and “Note 5-Negative Adjustments” of the financial statements and “Management’s Discussion and Analysis of Financial Condition and Results of Operating” relating to operating information on East Cameron 371/381 included in this Form 10-K, for a decription of certain risks relating to these arrangements and reliance and applicable adjustments to operating information when reported by the Working Interest Owners to the Corporate Trustee and recorded in the Trust’s results of operation.
Changes in Internal Control Over Financial Reporting. During the year ended December 31, 2005, there has been no change in the Corporate Trustee’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Corporate Trustee’s internal control over financial reporting relating to the Trust. The Corporate Trustee notes for purposes of clarification that it has no authority over, and makes no statement concerning, the internal control over financial reporting of the Working Interest Owners or the managing general partner of the Partnership.
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. JPMorgan Chase Bank serves as the Corporate Trustee, and Daniel O. Conwill, IV, Gary C. Evans and Jeffrey S. Swanson serve as the 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.
The Trust does not have a principle executive officer, principle financial officer, principle accounting officer or controller and, therefore, has not adopted a code of ethics applicable to such persons. However, employees of the Trustee must comply with the bank’s code of ethics.
The Trust does not have a board of directors, and therefore does not have an audit committee, an audit committee financial expert, or a nominating committee.
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.
None.
(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 ChevronTexaco accounted for approximately 99% of total crude oil revenues from the Royalty Properties during 2005 and 2004.
The Trust’s share of Royalty income was reduced by approximately $418,000 in 2005 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 2005.
Effective August 31, 1996, Chevron U.S.A. Inc.’s Natural Gas Business Unit and Warren Petroleum Company merged with Dynegy (formerly named NGC Corporation). As of February 28, 2002, Chevron Texaco owned approximately 26% of the voting stock of Dynegy and Chevron was obligated to sell substantially all of its natural gas produced and owned or controlled by it in the lower 48 states to Dynegy. In January 2003, Chevron terminated all of its natural gas contracts with Dynegy. In April 2003, ChevronTexaco formed a new division called “ChevronTexaco Natural Gas” to market most of its production to various third party purchasers under a mix of term and spot agreements.
On October 9, 2001, the stockholders of Chevron Corporation and Texaco approved the merger of the two companies to form ChevronTexaco Corporation. ChevronTexaco has advised that as of May 1, 2002, the oil and gas leases of TEPI on West Cameron 643 and Ship Shoal 371/381 were assigned to Chevron.
PART IV
Item 14.
Item 14. Principal Accountant Fees and Services.
The Trust does not have an audit committee. Any pre-approval and approval of all services performed by the principal auditor or any other professional service firms and related fees are granted by the Trustees.
The following table presents fees for professional audit services rendered by Deloitte & Touche LLP for the audit of Tel Offshore Trust financial statements for 2005 and 2004 and fees billed for other services rendered by Deloitte & Touche LLP.
Item 15.
Item 15. Exhibits, Financial Statement Schedules
(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:
(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, JPMorgan Chase Bank is successor by mergers to the original name of the Trustee, Texas Commerce Bank National Association).
SEC File or
Registration
Number
Exhibit
Number
(a)*
Trust Agreement dated as of January 1, 1983, among Tenneco Offshore Company, Inc., Texas Commerce Bank National Association, as corporate trustee, and Horace C. Bailey, Joseph C. Broadus and F. Arnold Daum, as individual trustees (Exhibit 4(a) to Form 10-K for year ended December 31, 1992 of TEL Offshore Trust)
0-6910
4(a)
(b)*
Agreement of General Partnership of TEL Offshore Trust Partnership between Tenneco Oil Company and the TEL Offshore Trust, dated January 1, 1983 (Exhibit 4(b) to Form 10-K for year ended December 31, 1992 of TEL Offshore Trust)
0-6910
4(b)
(c)*
Conveyance of Overriding Royalty Interests from Exploration I to the Partnership (Exhibit 4(c) to Form 10-K for year ended December 31, 1992 of TEL Offshore Trust)
0-6910
4(c)
(d)*
Amendments to TEL Offshore Trust Trust Agreement, dated December 7, 1984 (Exhibit 4(d) to Form 10-K for year ended December 31, 1992 of TEL Offshore Trust)
0-6910
4(d)
(e)*
Amendment to the Agreement of General Partnership of TEL Offshore Trust Partnership, effective as of January 1, 1983 (Exhibit 4(e) to Form 10-K for year ended December 31, 1992 of TEL Offshore Trust)
0-6910
4(e)
(a)*
Purchase Agreement, dated as of December 7, 1984 by and between Tenneco Oil Company and Tenneco Offshore II Company (Exhibit 10(a) to Form 10-K for year ended December 31, 1992 of TEL Offshore Trust)
0-6910
10(a)
(b)*
Consent Agreement, dated November 16, 1988, between TEL Offshore Trust and Tenneco Oil Company (Exhibit 10(b) to Form 10-K for year ended December 31, 1988 of TEL Offshore Trust)
0-6910
10(b)
(c)*
Assignment and Assumption Agreement, dated November 17, 1988, between Tenneco Oil Company and TOC-Gulf of Mexico Inc. (Exhibit 10(c) to Form 10-K for year ended December 31, 1988 of TEL Offshore Trust)
0-6910
10(c)
(d)*
Gas Purchase and Sales Agreement Effective September 1, 1993 between Tennessee Gas Pipeline Company and Chevron U.S.A. Production Company (Exhibit 10(d) to Form 10-K for year ended December 31, 1993 of TEL Offshore Trust)
0-6910
10(d)
Certification furnished pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
Certification furnished pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
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 31st day of March, 2006.
The Registrant, TEL Offshore Trust, has no principal executive officer, principal financial officer, board of directors or persons performing similar functions. Accordingly, no additional signatures are available and none have been provided. In signing the report above, neither the Corporate Trustee nor the Individual Trustees imply that they perform any such function or that such function exists pursuant to the terms of the Trust Agreement under which they serve.