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, The Bank of New York Mellon Trust Company, N.A. ("Corporate Trustee"), 919 Congress Avenue, Austin, Texas 78701. The telephone number of the Corporate Trustee is 1-800-852-1422. The Bank of New York Mellon Trust Company, N.A. succeeded JPMorgan Chase Bank, N.A. as the Corporate Trustee effective October 2, 2006 pursuant to an agreement under which The Bank of New York Mellon Trust Company acquired substantially all of JPMorgan Chase's corporate trust business. JPMorgan Chase Bank was formerly known as The Chase Manhattan Bank and is the successor by mergers to the original corporate trustee, Texas Commerce Bank National Association. Daniel O. Conwill, IV, 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 Corporate 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 and at www.businesswire.com/cnn/tel-offshore.htm.
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, Tenneco Exploration Ltd. ("Exploration I") was dissolved and the oil and gas properties of Exploration I were distributed to Tenneco Oil Company ("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 in the Trust.
On November 18, 1988, Chevron acquired most of the Gulf of Mexico offshore oil and gas properties of Tenneco, including all of 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 such 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. As a result of such acquisitions, 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 such 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 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. The abandonment obligations for Eugene Island 348 have been assumed by Maritech Resources, Inc. effective January 1, 2005.
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. Effective May 9, 2005, ChevronTexaco Corporation changed its name to Chevron Corporation. Accordingly, the properties referred to herein by Chevron and Texaco are each now controlled by subsidiaries of Chevron Corporation.
On May 1, 2002, TEPI assigned all of its interests in West Cameron 643 and East Cameron 371 to Chevron. Chevron sold its interest in East Cameron 371 to Energy Resource Technology, Inc. effective July 1, 2007. On July 18, 2008, Chevron sold its interest in West Cameron 643 to Hilcorp Energy GOM, LLC ("Hilcorp"). Effective August 1, 2008, Hilcorp assumed operations, reporting and payment responsibilities for West Cameron 643.
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 such 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. Chevron, as the managing general partner of the Partnership, calculates the Net Proceeds from the Royalty Properties owned by Chevron and collects financial information relating to the other Royalty Properties from the Working Interest Owners other than Chevron for presentation to the Trust.
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 (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 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 on and after May 1, 2002 until August 1, 2008; Chevron with respect to East Cameron 371 on and after May 1, 2002 until July 1, 2007; Anadarko with respect to East Cameron 354 on and after July 1, 2003 until October 1, 2004, Apache with respect to East Cameron 354 after October 1, 2004; Energy Resource Technology, Inc. with respect to East Cameron 371 on and after July 1, 2007; and Hilcorp with respect to West Cameron 643 on and after August 1, 2008).
As of March 27, 2009, a total of 4,751,510 units of beneficial interest in the Trust ("Units") are issued and outstanding. The Units have been traded on the Nasdaq SmallCap Market since August 31, 2001. Previously the Units were traded on the OTC Bulletin Board. The Units were also traded on pink sheets. From inception of the Trust to December 31, 2008, distributions to Unit holders totaled approximately $138,742,000 or approximately $29.20 per Unit. See "Management's Discussion and Analysis of Financial Condition and Results of Operation-Liquidity and Capital Resources" in Item 7 of this Form 10-K and Note 4 to the Notes to Financial Statements under Item 8 of this Form 10-K for a discussion regarding certain uncertainties of distributions.
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 $24.2 million as of October 31, 2008 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 will 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 will 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 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. 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. 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 with and into 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. Accordingly, the properties referred to herein by Chevron and Texaco are each now controlled by subsidiaries of Chevron Corporation. Effective May 9, 2005, ChevronTexaco Corporation changed its name to Chevron Corporation. On May 1, 2002, TEPI assigned all of its interests in West Cameron 643 and East Cameron 371 to Chevron. Chevron sold its interest in East Cameron 371 to Energy Resource Technology, Inc. effective July 1, 2007. Chevron sold its interests in West Cameron 643 to Hilcorp effective August 1, 2008. 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 Trustees will 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 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.
Classification of the Trust
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.
The Trustees assume that some Units are held by a middleman as such term is broadly defined in applicable Treasury Regulations (and includes custodians, nominees, certain joint owners, and brokers holding an interest for a custodian in street name.) Therefore, the Trustees consider the Trust to be a widely held fixed investment trust ("WHFIT") for federal income tax purposes. The Corporate Trustee, 919 Congress Avenue, Austin, Texas 78701, telephone number 1-800-852-1422, is the representative of the Trust that will provide tax information in accordance with applicable Treasury Regulations governing the information reporting requirements of the Trust as a WHFIT.
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 less any amount allocable to his share of any cash reserve account. Transferees of Units transferred after October 11, 1990, may be eligible to use the percentage depletion deduction on oil and gas income thereafter attributable to such Units, if the percentage depletion deduction would exceed cost depletion. Unlike cost depletion, percentage depletion is not limited to a Unit holder's depletable tax basis in the Units. Rather, a Unit holder may be entitled to a percentage depletion deduction as long as the Royalty generates gross income.
Backup Withholding
Distributions from the Trust are generally subject to backup withholding at a rate of 28% of these distributions. Backup withholding generally will not apply to distributions to a Unit holder 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 Unit exceeds one year at the time of sale or exchange. 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. Long-term capital gain generally will be subject to a maximum U.S. federal income tax rate of 15%, which maximum tax rate currently is scheduled to increase to 20% for dispositions occurring during taxable years beginning on or after January 1, 2011. The deductibility of capital losses are subject to certain limitations.
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 (without taking into account any deductions, such as depletion) 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 taxable income is subject to withholding at the highest applicable tax rate, 35% for individual 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 any gain from 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 advisor with respect to its 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 is encouraged to consult its own tax advisor with respect to its ownership of Units and 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 are encouraged to consult their legal and tax advisors regarding the applicability of these considerations to their individual circumstances.
Texas does not impose an income tax. Therefore, no part of the income produced by the Trust is subject to an income tax in Texas. However, effective January 1, 2008, Texas imposes a margin tax at a rate of 1% on gross revenues less certain deductions, as specifically set forth in the Texas margin tax statute. The Texas margin tax is a significant change in Texas tax law. The tax generally will be imposed on gross revenues generated in 2007 and thereafter. Entities subject to tax generally include trusts unless otherwise exempt, and most other types of entities having limited liability protection. Trusts and partnerships that receive at least 90% of their federal gross income from designated passive sources, including royalties from mineral properties and other non-operated mineral interest income, and do not receive more than 10% of their income from operating an active trade or business, are generally exempt from the Texas margin tax as "passive entities." The Trust should be exempt from Texas margin tax as a "passive entity." Since the Trust should be exempt from Texas margin tax at the Trust level as a passive entity, each Unit holder that is considered a taxable entity under the Texas margin tax would generally be required to include its Texas portion of Trust revenues in its own Texas margin tax computation. Each unitholder is urged to consult its own tax advisor regarding its possible Texas state franchise tax liability.
TERMINATION OF THE TRUST
The terms of the TEL Offshore Trust Agreement provide that the Trust will terminate upon the first to occur of the following events: (1) total future net revenues attributable to the Partnership's interest in the Royalty, as determined by independent petroleum engineers, as of the end of any year, are less than $2 million or (2) a decision to terminate the Trust by the affirmative vote of Unit holders representing a majority of the Units. Total future net revenues attributable to the Partnership's interest in the Royalty were estimated at $24.2 million as of October 31, 2008, based on the reserve study of DeGolyer and MacNaughton, independent petroleum engineers, discussed herein. Such reserve study does not include any reserves or values attributable to Eugene Island 339, nor does it include the Trust's percentage share of the total plugging and abandonment costs related to Eugene Island 339, with costs for 2009 alone estimated to be approximately $61 million. Based on the DeGolyer and MacNaughton reserve study, as of October 31, 2008, in order to correspond with distributions to the Trust, it is estimated that approximately 40% 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 summary of the DeGolyer and MacNaughton reserve study included in Item 1 of this Form 10-K. 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 nor are any capital expenditures included for any redevelopment of Eugene Island 339. 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 Trustees 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, 2008, there were no wells in the process of being drilled.
(2)As of October 31, 2008, there were 75 producing completions (34 associated with Ship Shoal, 4 associated with South Timbalier 36 and 37 associated with South Timbalier 37). All Eugene Island 339 wells were destroyed by Hurricane Ike in September 2008.
(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 were plugged and abandoned in 2006. The platforms to which the wells were connected were abandoned in July 2008.
(6)West Cameron 643 was sold to Hilcorp Energy Company, effective August 1, 2008.
(7)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.
(8)This lease expired in 2004. Abandonment work was completed in May 2006.
(9)This lease expired in 1996.
(10)East Cameron 371 was sold to Energy Resource Technology, Inc., effective July 1, 2007.
(11)This lease (Vermillion 246 Block, OCS-G 1147) was terminated in 2002. Abandonment work was completed mid 2005.
(12)This lease expired in November 2002, and all wells on the lease had been abandoned as of November 2003.
(13)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 Chevron have an interest in OCS-G-19800.
(14)South Timbalier 36 well number 2 working interest owner's ownership interest is .013 percent.
During 2006, there was one development gas well drilled, which was completed at Ship Shoal 183. During 2007, there were three development oil wells drilled, all of which were completed and were associated with South Timbalier 37. During 2008, one development oil well was drilled, which was completed and was associated with South Timbalier 37, and there was one workover of a gas well at South Timbalier 36.
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, 2008. The following is a summary of 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.
On October 7, 2008, the Trust announced that production from the two most significant oil and gas properties associated with the Trust had ceased following damage inflicted by Hurricane Ike in September 2008. The platforms and wells on Eugene Island 339 were completely destroyed by the hurricane. In order to restore production at Eugene Island 339, Chevron expects that it would need to redevelop the facility and drill new wells. The Trust had expected Chevron to make a decision in the first quarter of 2009 whether to proceed with any such development; however, Chevron is still assessing its alternatives and the economic feasibility for restoring production at the property. See "Management's Discussion and Analysis of Financial Condition and Results of Operation-Operations." Chevron's decisions regarding Eugene Island 339 impact the treatment of Eugene Island for purposes of preparing a reserve report for the Partnership. Solely for purposes of being able to complete the reserve report so that the Trust could file this Form 10-K, DeGolyer and MacNaughton assumed that Eugene Island 339 will not be redeveloped. As such, the reserve study does not include any reserves or values attributable to Eugene Island 339, nor does it include the Trust's percentage share of the total plugging and abandonment costs related to Eugene Island 339, with costs for 2009 alone estimated to be approximately $61 million. At this point in time, there can be no assurance as to how or when, or if at all, production may be restored at Eugene Island 339. Based on the reserve study of DeGolyer and MacNaughton for the oil and gas reserves attributable to the Partnership as of October 31, 2007, Eugene Island 339 accounted for approximately 34% of the total future net revenues attributable to the Partnership's interest in the Royalty as of October 31, 2007.
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 study represent estimates only and should not be construed as being exact. The discounted present values shown by the DeGolyer and MacNaughton study 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. Estimates were prepared in accordance with guidelines established by the SEC and the Financial Accounting Standards Board. Accordingly, the estimates are based on existing economic and operating conditions in effect at October 31, 2008, with no provision for future increases or decreases except for periodic price redeterminations in accordance with existing gas contracts. Actual future prices and costs may be materially greater or less than the assumed amounts in the reserve study. 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 nor are any capital expenditures for any redevelopment of Eugene Island 339. 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.
Estimated net proved reserves attributable to the net profits interest owned by the Partnership, as of October 31, 2008 (excluding Eugene Island 339), 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, 2007, of the Partnership's net profits interest in net reserves to the net reserves associated with the Partnership's net profits interest and the interests retained in the Royalty Properties by the Working Interest Owners. This ratio was then applied to the production net to the combined interests of the Partnership and the Working Interest Owners for the period from November 1, 2007, through October 31, 2008.
(2)The revisions also take into account the assumption, solely for purposes of being able to complete the related reserve study, that no reserves are attributable to Eugene Island 339.
Information used in the preparation of the reserve study was obtained from the Working Interest Owners. All of the reserve estimates are classified as proved developed reserves.
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 $24.2 million as of October 31, 2008 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 and such quantities can 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 study 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 reserve study have not been reduced for future costs and expenses of the Trust, which are expected to approximate $883,000 annually, plus the Trust's percentage share of the total plugging and abandonment costs related to Eugene Island 339, with costs for 2009 alone estimated to be approximately $61 million. 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.
Revenue values in the reserve study were estimated using the initial costs provided by Chevron and prices as of October 31, 2008 of $67.81 per barrel of oil and $6.75 per Mcf of natural gas. The future net revenue value was calculated by deducting operating expenses and capital costs from future gross revenue of the combined interests of the Partnership and the Working Interest Owners in the Royalty Properties. Current estimates of operating expenses were used for the life of the properties with no increases in the future based on inflation. The values 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 2009. The future accrual or escrow amounts for the Royalty Properties were deducted from the 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 2.0% 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% to arrive at the future net revenue attributed to the Partnership's net profits interest. Interest was charged monthly on the net profits deficit balances (costs not recovered currently) at the rate of 2.0% per year as specified by Chevron. Future income tax expenses were not taken into account in estimating future net revenue.
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 nor are any capital expenditures for any redevelopment of Eugene Island 339. 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 Managing General Partner of the Partnership has advised the Trust that there have been no events (other than the treatment of Eugene Island, solely for purposes of preparing the reserve study) subsequent to October 31, 2008 that have caused a significant change in the estimated proved reserves referred to in the DeGolyer and MacNaughton study.
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.
Distributions
During 2005, Hurricane Katrina and Hurricane Rita caused significant damage to various platforms and third-party transportation systems, which resulted in oil and gas production delays in the Royalty Properties. During 2006, several of the platforms and facilities on the Royalty Properties were restored, and by the third quarter of 2007 all but one of the platforms and facilities had been restored. One of the platforms and facilities on Eugene Island was destroyed and has not been restored. Since those hurricanes, overall production slowly returned to normal production levels, until production ceased at Eugene Island 339 and Ship Shoal 182 and 183 following damages inflicted by Hurricane Ike in September 2008. Future Net Proceeds may take into account the Trust's share of project costs and other related expenditures that are not covered by insurance of the operator of the Royalty Properties. The extensive damage caused by hurricanes Katrina and Rita led to significant demand for services and supplies for repairs in the offshore Gulf of Mexico, which increased levels of expenditures. The reduced oil and gas production and increased costs reduced the cash income distributions to unitholders significantly during 2006 and affected the first and second quarters of 2007. During the fourth quarter 2006, the Trust resumed distributions. The fourth quarter distribution of $1.7 million was paid on January 11, 2007. On March 30, 2007, the Trust announced its first quarter distribution of approximately $1.2 million. On June 27, 2007, the Trust announced its second quarter distribution of approximately $2.1 million, which was paid on July 9, 2007. On September 27, 2007, the Trust announced its third quarter distribution of approximately $2.8 million, which was paid on October 9, 2007. On December 21, 2007, the Trust announced its fourth quarter distribution of approximately $3.3 million, which was paid on January 10, 2008. On March 26, 2008, the Trust announced its first quarter distribution of approximately $4.5 million, which was paid on April 10, 2008. On June 27, 2008, the Trust announced its second quarter distribution of approximately $2.6 million, which was paid on July 10, 2008. On September 26, 2008, the Trust announced its third quarter distribution of approximately $5.5 million, which was paid on October 10, 2008. On December 19, 2008, the Trust announced its fourth quarter distribution of approximately $0.7 million, which was paid on January 9, 2009. The funds available for the fourth quarter distribution were severely negatively impacted by Hurricane Ike. On March 25, 2009, the Trust announced that there would be no trust distribution for the first quarter of 2009. Future distributions by the Trust are expected to be severely negatively impacted because of both reduced production and increased expenditures required to remediate, repair and, perhaps, restore platforms and wells. See "Management's Discussion and Analysis of Financial Condition and Results of Operations-Operations."
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, 2006, 2007 and 2008, approximately 99% of Chevron's natural gas and natural gas liquids relative to the Trust's Royalty Properties were committed and sold to Chevron Natural Gas at spot market prices.
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 18% of the revenues from natural gas sales from the Royalty Properties in 2008. The average price received for natural gas from all of the Working Interest Owners' purchasers on West Cameron 643 during 2008 was $9.46 per Mcf.
East Cameron 371. East Cameron 371 contributed a little over 2% of the revenues from natural gas sales from the Royalty Properties in 2008. The average price received for natural gas from all of the Working Interest Owners' purchasers on East Cameron 371 during 2008 was $7.79 per Mcf.
Ship Shoal 182/183. Ship Shoal 182/183 contributed approximately 42% of the revenues from gas sales from the Royalty Properties in 2008. The average price received for natural gas from all of the Working Interest Owners' purchasers on Ship Shoal 182/183 during 2008 was $9.29 per Mcf, before prior period audit adjustments.
Eugene Island 339. Eugene Island 339 contributed approximately 37% of the revenues from natural gas sales from the Royalty Properties in 2008. The average price received for natural gas from all of the Working Interest Owners' purchasers on Eugene Island 339 during 2008 was $9.60 per Mcf, before prior period audit adjustments.
South Timbalier 36/37. South Timbalier 36/37 contributed approximately 1% of the revenues from natural gas sales from the Royalty Properties in 2008. The average price received for natural gas from all of the Working Interest Owners' purchasers on South Timbalier 36/37 during 2008 was $10.39 per Mcf, before prior period audit adjustments.
Oil Marketing
Crude oil purchases by Chevron accounted for approximately 99% of total crude oil revenues from the Royalty Properties during 2006, 2007 and 2008.
Chevron purchases the crude oil at prices based on a market index for the applicable grade of crude oil, as adjusted for gravity and transportation charges, if applicable. Average monthly prices for fiscal year 2008 ranged from $80.86 per barrel to $137.32 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 transportation of natural gas in interstate commerce by interstate pipelines. The FERC has adopted regulations resulting in a restructuring of the natural 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 determine whether further changes are needed. In addition to rulemaking proceedings, the FERC establishes new policies and regulations through policy statements and adjudications of individual pipeline matters. Further, additional changes to regulations may occur based on actions taken by the United States Congress and/or the courts. 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 terms of sale of natural 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). The Corporate Trustee has been 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 Managing General Partner of the Partnership has advised the Trust that the Working Interest Owners 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 Managing General Partner of the Partnership has 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.
Climate Change
A variety of regulatory developments, proposals or requirements have been introduced that are focused on restricting the emission of carbon dioxide, methane and other greenhouse bases. Among these developments is the Kyoto Protocol to the United Nations Framework Convention on Climate Change that became effective in February 2005. Under the Protocol, participating nations are required to implement programs to reduce emissions of certain gases, generally referred to as greenhouse gases, that are suspected of contributing to global warming. The United States is not currently participating in the Protocol though the Protocol may impact oil and gas markets generally. In addition, Congress has considered recent proposed legislation directed at reducing greenhouse gas emissions. There has been support in various regions of the country for legislation that requires reductions in greenhouse gas emissions, and some states have already adopted legislation addressing greenhouse gas emissions from various sources. In 2007, the U.S. Supreme Court held in Massachusetts, et al. v. EPA that greenhouse gases are an "air pollutant" under the federal Clean Air Act and, thus, subject to future regulation. The oil and natural gas industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact the future operations of the Royalty Properties. The operations of the Royalty Properties are not adversely impacted by the current state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact the operations of the properties.
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, and a material decrease in such prices could reduce the amount of Trust distributions. 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.
During recent months, there has been a substantial downturn in general business activity and in the worldwide credit and capital markets that has led to a worldwide economic recession. Recent oil prices have been low compared to historical prices. The current sustained decline in oil prices, particularly in combination with the constrained capital markets and overall economic downturn, has resulted in a decline in activity by participants in the oil and gas industry. The Trust cannot predict the timing or the duration of this or any other economic downturn in the economy and if the current conditions continue, the financial condition of the Trust could be materially adversely affected.
When natural gas and oil prices decline, the Trust is affected in two ways. First, net royalties are reduced. Second, exploration and development activities on the underlying properties may decline as some projects may become uneconomic and are either delayed or cancelled. The volatility of energy prices reduces the predictability of future cash distributions to Unit holders. Substantially all of the natural gas and natural gas liquids produced from the Royalty Properties is being sold to Chevron Natural Gas at spot market prices. Substantially all of the crude oil produced by the Royalty Properties is being sold to subsidiaries of Chevron Corporation based on pricing bulletins.
Production from Eugene Island 339 and Ship Shoal 182 and 183, the two most significant Royalty Properties, ceased following damage inflicted by Hurricane Ike in September 2008. At this point in time, there can be no assurance as to how or when, or if at all, production may be restored at either of the oil and gas properties. Based on the damage caused by Hurricane Ike, the Trust's scheduled distribution for the fourth quarter of 2008 was severely negatively impacted and there will be no distribution for the first quarter of 2009. Future distributions are also expected to be severely negatively impacted, and there may not be sufficient Net Proceeds from the Royalty Properties to make one or more future distributions.
The platforms and wells on Eugene Island 339 were destroyed by Hurricane Ike in September 2008. Chevron is assessing its alternatives and the economic feasibility for restoring production at the property. At this point in time, there can be no assurance as to how or when, or if at all, production may be restored at Eugene Island 339. While Hurricane Ike caused limited surface damage to the facilities at Ship Shoal 182/183, all of the wells at Ship Shoal 182/183 were shut-in following hurricane-related damage to a third-party transporter's natural gas pipeline. A limited volume of oil production was restored at Ship Shoal 182/183 in November 2008, with an average rate of daily oil production from November 20, 2008 through January 31, 2009 of approximately 831 barrels per day. The volume of oil production that can be produced is limited by the amount of gas that is also produced by the oil wells. Production is expected to remain limited until the natural gas pipeline is fully repaired and tested, which is anticipated to occur in the second quarter of 2009, but which is also in the control of the pipeline owner. There may also be related regulatory approval requirements that must be satisfied before gas transportation may commence. At this point in time, there can be no assurance as to when, or if at all, gas production may be restored at Ship Shoal 182/183. Based on the damage caused by Hurricane Ike, the Trust's scheduled distribution for the fourth quarter of 2008 was severely negatively impacted and there will be no distribution for the first quarter of 2009. Future distributions are also expected to be severely negatively impacted, and there may not be sufficient Net Proceeds from the Royalty Properties to make one or more future distributions. At this time, the ultimate outcome of these various matters cannot be determined.
In addition, production from West Cameron 643 and East Cameron 371 ceased following damage inflicted by Hurricane Ike in September 2008 to third-party transporters' pipelines. The Managing General Partner of the Partnership understands that the pipelines are in the process of being restored; however, the pipeline for West Cameron 643 is not expected to be able to take production until at least the end of 2009. At this point in time, there can be no assurance as to when, or if at all, production may be restored at West Cameron 643 or East Cameron 371. For additional information, see "Management's Discussion and Analysis of Financial Condition and Results of Operations-Operations."
Increased production and development costs for the Royalty will result in decreased or no Trust distributions.
Production and development costs attributable to the Royalty are deducted in the calculation of the Trust's share of net proceeds. Production and development costs are impacted by increases in commodity prices both directly and indirectly, through commodity-price dependent costs such as electricity, and indirectly, as a result of demand-driven increases in costs of oilfield goods and services. 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 led to significant demand for services and supplies for repairs in the offshore Gulf of Mexico. These incurred costs reduced Royalty income.
In September 2008, Hurricane Ike completely destroyed the platforms and wells on Eugene Island 339. Chevron is proceeding to plug and abandon the existing wells, to clear debris and otherwise to deal with the remaining infrastructure, with estimated costs relating thereto of approximately $61 million for 2009. In order to restore production, Chevron expects that it would need to redevelop the facility and drill new wells. There can be no assurance that production at Eugene Island 339 will be restored. For additional information, see "Management's Discussion and Analysis of Financial Condition and Results of Operations-Operations."
If development and production costs of the Royalty exceed the proceeds of production from the Royalty Properties, the Trust will not receive Net Proceeds until future proceeds from production exceed the total of the excess costs plus accrued interest, at a rate equal to one-fourth of (i) one-half of one percent plus (ii) the median between the prime interest rate at the end of a quarterly period in which there are excess costs and the prime interest rate at the end of the preceding quarterly period, during the deficit period. Development activities may not generate sufficient additional revenue to repay the costs. Accordingly, there may not be sufficient Net Proceeds to make a particular distribution.
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;
•assumptions about future commodity prices, production and development costs, severance and excise taxes, and capital expenditures;
•the availability of enhanced recovery techniques; and
•relationships with landowners, working interest partners, pipeline companies and others.
Changes in these factors and assumptions can materially change reserve estimates and future net revenue estimates.
The reserve quantities attributable to the Royalty and revenues are based on estimates of reserves and revenues for the Royal 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. Ultimately, actual production, revenues and expenditures for the Royalty Properties, and therefore actual net proceeds payable to the Trust, will vary from estimates and those variations could be material. Results of drilling, testing and production after the date of those estimates may require substantial downward revisions or write-downs of reserves.
The Trustees also rely entirely on reserve estimates and related information prepared by Chevron and the independent reserve engineer engaged by the Partnership. While the Trustees have 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.
There are operational risks and hazards associated with the production and transportation of natural gas, including without limitation natural disasters, blowouts, explosions, fires, leakage of natural gas, releases of other hazardous materials, mechanical failures, cratering and pollution. Any of these or similar occurrences could result in the interruption or cessation of operations, personal injury or loss of life, property damage, damage to productive formations or equipment, damage to the environment of natural resources, or cleanup obligations. 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. 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. All but one of the platforms and facilities on the Royalty Properties were restored during 2006 and 2007. As also described in the report, production from the two most significant oil and gas properties associated with the Trust ceased following damage inflicted by Hurricane Ike in September 2008. The platforms and wells on Eugene Island 339 were completely destroyed. While Hurricane Ike caused limited damage to the facilities at Ship Shoal 182 and 183, all of the wells at Ship Shoal 182 and 183 were shut-in following hurricane related damage to a third-party transporter's natural gas pipeline.
Terrorism and continued hostilities in the Middle East could decrease Trust distributions or the market price of the units of beneficial interest of the Trust.
Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign, as well as military or other actions taken in response, cause instability in the global financial and energy markets. Terrorism, the war in Iraq and other sustained military campaigns could adversely affect Trust distributions or the market price of the Units in unpredictable ways, including through the disruption of fuel supplies and markets, increased volatility in natural gas prices, or the possibility that the
infrastructure on which the operators developing the underlying properties rely could be a direct target or an indirect casualty of an act of terror.
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.
The Trustees and the Unit holders have no control over 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. The failure of an operator to conduct its operations, discharge its obligations, deal with regulatory agencies or comply with laws, rules and regulations, including environmental laws and regulations, in a proper manner could have an adverse effect on the net proceeds payable to the Trust. Neither the Trustees nor the Unit holders have the right to replace an operator.
The Trustees rely upon the Working Interest Owners and Managing General Partner for information regarding the Royalty Properties.
The Trustees rely on the Working Interest Owners and the Managing General Partner of the Partnership 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 Trustees request material information for use in periodic reports as part of its disclosure controls and procedures, the Trustees do not control this information and rely entirely on the Working Interest Owners to provide accurate and timely information when requested for use in the Trust's periodic reports. The Trustees also rely on the Managing General Partner of the Partnership to collect certain information from the Working Interest Owners and do not have any direct contact with the Working Interest Owners other than the Managing General Partner. Under the terms of the Trust Indenture, the Trustees are entitled to rely, and in fact rely, on certain experts in good faith. While the Trustees have no reason to believe their 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.
Generally, if production ceases from an outer continental shelf lease, like that for Eugene Island 339, production must be restored or drilling operations must commence within 180 days of the cessation (which was in early March 2009 with respect to Eugene Island 339 given the ceasing of production in September 2008 resulting from Hurricane Ike), or the lease will be terminated. A lease operator may seek approval from the regional supervisor of the Mineral Management Service to allow additional time to restore production. Chevron has submitted such a request with respect to Eugene Island 339. There can be no assurance that production at Eugene Island 339 will be restored, or that such requested extension will be granted.
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.
Because the net proceeds payable to the Trust are derived from the sale of depleting assets, the portion of distributions to Unit holders attributable to depletion may be considered a return of capital as opposed to a return on investment. Distributions that are a return of capital will ultimately diminish the depletion tax benefits available to the Unit holders, which could reduce the market value of the Units over time. Eventually, properties underlying the Trust's Royalty will cease to produce in
commercial quantities and the Trust will, therefore, cease to receive any distributions of net proceeds therefrom.
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. Additionally, Unit holders have no voting rights in the Working Interest Owners. 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, 2008.
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 to which the Trust is a party or of which any of its property is the subject.
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 2008.
PART II
Item 5.
Item 5. Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchasers of Equity Securities.
The Trust Units are traded on the Nasdaq SmallCap Market under the symbol "TELOZ". At March 26, 2009, the 4,751,510 Units outstanding were held by 1,931 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, 2008 and 2007, were as follows:
See "Management's Discussion and Analysis of Financial Condition and Results of Operations-Operations" and Note 4 to Notes to Financial Statements under Item 8 of this Form 10-K for a discussion regarding uncertainty of distributions.
Item 6.
Item 6. Selected Financial Data.
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation.
On the last business day of each calendar quarter, the Working Interest Owners pay to the Partnership 25% of the Net Proceeds for the immediately preceding Quarterly Period. A Quarterly Period is each period of three months commencing on the first day of February, May, August and November. In turn, the Partnership distributes funds to its partners on the last business day of each calendar quarter. Cash distributions from the Trust are made in January, April, July and October of each year, and are payable to Unit holders of record as of the last business day of each calendar quarter. Thus, the cash conveyed to the Trust from the Royalty during the quarter ended December 31, 2008 substantially represents the revenues and expenses from the Royalty Properties from August through October 2008. The financial and operating information included in this Form 10-K for the 12 months ended December 31, 2008 represents financial and operating information with respect to the Royalty Properties for the months of November 2007 through October 2008. As such, the impact of Hurricane Ike will not be fully reflected in the discussion of 2008 operations, as such discussion does not include a discussion of operations of the Royalty Properties in November or December 2008. Similarly, the financial and operating information included in this Form 10-K for the 12 months ended December 31, 2007 represents financial and operating information with respect to the Royalty
Properties for the months of November 2007 through October 2008. Income from the Royalty is recorded by the Trust on a cash basis, when it is received by the Trust from the Partnership.
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);
(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.
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 any of the Working Interest Owners.
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.
On October 7, 2008, the Trust announced that production from the two most significant oil and gas properties associated with the Trust had ceased following damage inflicted by Hurricane Ike in September 2008. The platforms and wells on Eugene Island 339 were completely destroyed by Hurricane Ike. Crude oil revenues from Eugene Island 339 represented approximately 48% of the crude oil and condensate revenues for the Royalty Properties in 2007. While Hurricane Ike caused limited surface damage to the facilities at Ship Shoal 182/183, all of the wells at Ship Shoal 182/183 were shut-in following hurricane-related damage to a third-party transporter's natural gas pipeline. The more productive wells on the properties produce both oil and gas, and there is currently no downstream transmission available for any gas produced from the wells. Crude oil revenues from Ship Shoal 182/183 represented approximately 50% of the crude oil and condensate revenues for the Royalty Properties in 2007. There can be no assurance that production at Eugene Island 339 will be restored. While production is expected to remain limited at Ship Shoal 182/183 until the natural gas pipeline is fully repaired and tested, which is anticipated to occur in the second quarter of 2009, there can be no assurance as to when, or if at all, meaningful production may be restored at Ship Shoal 182/183. See "-Operations."
In addition, production from West Cameron 643 and East Cameron 371 ceased following damage inflicted by Hurricane Ike in September 2008 to third-party transporters' pipelines. The Managing General Partner of the Partnership understands that the pipelines are in the process of being restored; however, the pipeline for West Cameron 643 is not expected to be able to take production until at least the end of 2009. At this point in time, there can be no assurance as to when, or if at all, production may be restored at West Cameron 643 or East Cameron 371. For additional information, see "-Operations."
On December 19, 2008, the Trust announced its fourth quarter distribution of approximately $0.7 million, which was paid on January 9, 2009. Based on the damage caused by Hurricane Ike, the Trust's scheduled distribution for the fourth quarter of 2008 was severely negatively impacted, although there were funds available for distribution given that there was some production from Eugene Island 339 and Ship Shoal 182/183 in August and September 2008. On March 25, 2009, the Trust announced that there would be no trust distribution for the first quarter of 2009. There are no Net Proceeds expected to be distributed to the Trust for the first quarter of 2009. Future distributions by the Trust are expected to be severely negatively impacted, and there may not be sufficient Net Proceeds from the Royalty Properties to make one or more future distributions. At this time, the ultimate outcome of these various matters cannot be determined.
Future Net Proceeds may take into account the Trust's share of project costs and other related expenditures that are not covered by insurance of the operator of the Royalty Properties. If development and production costs of the Royalty exceed the proceeds of production from the Royalty Properties, the Trust will not receive Net Proceeds until future proceeds from production exceed the total of the excess costs plus accrued interest, at a rate equal to one-fourth of (i) one-half of one percent plus (ii) the median between the prime interest rate at the end of a quarterly period in which there are excess costs and the prime interest rate at the end of the preceding quarterly period, during the deficit period. Development activities may not generate sufficient additional revenue to repay the costs. Accordingly, there may not be sufficient Net Proceeds to make a particular distribution.
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, economic conditions generally 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 then 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 such time to provide for future administrative expenses in connection with the winding up of the Trust.
The calculated reserve amount at December 31, 2008 and 2007 was $2,233,291 and $1,883,726, respectively.
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. The Trustees have no control over these operations or internal controls relating to this information.
During 2005, Hurricane Katrina and Hurricane Rita caused significant damage to various platforms and third-party transportation systems, which resulted in oil and gas production delays in the Royalty Properties. 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. During 2006, several of the platforms and facilities on the Royalty Properties were restored, and by the third quarter of 2007 all but one of the platforms and facilities had been restored. One of the platforms and facilities on Eugene Island was destroyed from hurricanes in the third quarter of 2005 and was never restored. Eugene Island 339 oil production increased during the second half of 2006 and the first quarter of 2007 as the B-5 well gas injection project, which allows the operator to increase oil production and to limit flaring of gas, was completed. On Ship Shoal 182/183, gas production and sales resumed in July 2006 following the hurricanes in the third quarter of 2005, and full production resumed in the fourth quarter of 2006. On West Cameron 643, production was shut in from September 2005 following Hurricane Rita's major damage to various platforms, but limited gas production resumed in late July 2006 before the wells loaded up and additional repairs were required thus requiring the well to be shut in again during the second quarter 2006. Production at West Cameron 643 resumed May 2007.
The platforms and wells on Eugene Island 339 were completely destroyed by Hurricane Ike in September 2008. Crude oil revenues from Eugene Island 339 represented approximately 48% of the crude oil and condensate revenues for the Royalty Properties in 2007 and approximately 47% of such revenues for the nine months ended September 30, 2008. Eugene Island 339 contributed approximately 12% of the revenues from natural gas sales from the Royalty Properties in 2007 and approximately 41% of such revenues for the nine months ended September 30, 2008. Based on a prior reserve study of DeGolyer and MacNaughton, independent petroleum engineering consultants, Eugene Island 339 accounted for approximately 34% of the total future net revenues attributable to the Partnership's interest in the royalty as of October 31, 2007. Chevron is proceeding to plug and abandon the existing wells, to clear debris and otherwise to deal with the remaining infrastructure, with estimated costs relating thereto for 2009 alone of approximately $61 million. In order to restore production, Chevron expects that it would need to redevelop the facility and drill new wells. Chevron is still assessing its alternatives and the economic feasibility for restoring production at the property. At this point in time, there can be no assurance as to how or when, or if at all, production may be restored at Eugene Island 339. Generally, if production ceases from an outer continental shelf lease, like that for Eugene Island 339, production must be restored or drilling operations must commence within 180 days of the cessation (which was in early March 2009), or the lease will be terminated. A lease operator may seek approval from the regional supervisor of the Mineral Management Service to allow additional time to restore production. Chevron has submitted such a request with respect to Eugene Island 339. There can be no assurance that production at Eugene Island 339 will be restored or that such requested extension will be granted.
Production at Ship Shoal 182/183 ceased following damage inflicted by Hurricane Ike in September 2008. While the hurricane caused limited surface damage to the facilities at Ship Shoal 182/183, all of the wells at Ship Shoal 182/183 were shut-in following hurricane-related damage to a third-party transporter's natural gas pipeline. The more productive wells on the properties produce both oil and gas, and there was no downstream transmission available for any gas produced from the wells. Crude oil revenues from Ship Shoal 182/183 represented approximately 50% of the crude oil and condensate revenues for the Royalty Properties in 2007 and approximately 51% of such revenues for the nine months ended September 30, 2008. Ship Shoal 182/183 contributed approximately 77% of the revenues from natural gas sales from the Royalty Properties in 2007 and approximately 42% of such revenues for the nine months ended September 30, 2008. A limited volume of oil production was restored in November 2008, with an average rate of daily oil production from November 20, 2008 through January 31, 2009 of approximately 831 barrels per day. The volume of oil production that can be produced is limited by the amount of gas that is also produced by the oil wells. Production is expected
to remain limited until the natural gas pipeline is fully repaired and tested, which is anticipated to occur in the second quarter of 2009, but which is also in the control of the pipeline owner. There may also be related regulatory approval requirements that must be satisfied before gas transportation may commence. At this point in time, there can be no assurance as to when, or if at all, gas production may be restored at Ship Shoal 182/183.
In addition, production from West Cameron 643 and East Cameron 371 ceased following damage inflicted by Hurricane Ike in September 2008 to third-party transporters' pipelines. The Managing General Partner of the Partnership understands that the pipelines are in the process of being restored; however, the pipeline for West Cameron 643 is not expected to be able to take production until at least the end of 2009. At this point in time, there can be no assurance as to when, or if at all, production may be restored at West Cameron 643 or East Cameron 371.
The Trust has engaged an outside auditor for the purpose of reviewing the books and records of certain Working Interest Owners with respect to the Royalty Properties and the related payments to the Trust. Based on the initial report of this auditor, the Trustees believe that certain errors have occurred and are involved in ongoing discussions with such Working Interest Owners to resolve these items. As part of this ongoing process, certain adjustments resulted in an additional cash distribution to the Trust during the first quarter of 2008. These amounts are comprised of a one-time increase of approximately $31,716 in gas revenues, a one-time increase of approximately $43,287 in oil revenues, and a one-time credit of approximately $123,900 in capital expenditures. An additional $127,973 related to the outside audit was included in the second quarter 2008 distribution. An additional $135,551 related to the outside audit was included in the third quarter 2008 distribution. An additional credit adjustment of $352,317 related to the outside audit was made in the fourth quarter of 2008. No assurance can be provided as to the ultimate outcome of the remaining items under discussion.
Years 2008 and 2007
Royalty income increased approximately 41% from $10,257,485 in 2007 to $14,451,252 in 2008 primarily due to an increase in gas revenues and crude oil and condensate revenues as discussed below.
For 2008, the Trust had a collection of prior undistributed net income of $33,169. For 2007, the Trust had undistributed net loss of $9,297. An increase in undistributed net income represents revenues generated during the respective period, but not distributed by the Working Interest Owners. Collection of undistributed net income is the subsequent receipt in future periods from the related Working Interest Owner(s) of revenues generated in prior periods but not yet distributed.
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 increased 21% from $11,820,973 in 2007 to $14,248,644 in 2008, partially offset by a slight decrease in natural gas and gas products volumes from 1,654,836 Mcf equivalents in 2007 to 1,625,408 Mcf equivalents in 2008. The average price received for natural gas increased 19% from $7.11 per Mcf in 2007 to $8.45 Mcf in 2008.
Crude Oil and Condensate
Crude oil and condensate revenues increased 12% from $37,732,678 in 2007 to $42,424,601 in 2008, due primarily to a 54% increase in the average price received for crude oil and condensate from $65.26 in 2007 to $100.54 in 2008. This increase was partially offset by a decrease of 27% in crude oil and condensate volumes from 578,159 barrels in 2007 to 421,958 barrels in 2008.
The decrease in crude oil and condensate volumes during 2008 was related in part to a three day field shut-in for repairs at Eugene Island 339 and to an entire production shut-in at Ship Shoal 182/183, platforms C and E, due to pipeline obstruction. Oil production ceased at Eugene Island 339 and Ship Shoal 182/183 in September 2008 after damages inflicted by Hurricane Ike.
Operating and Capital Expenditures
Operating expenses paid by the Working Interest Owners increased 6% from $6,598,909 in 2007 to $7,012,792 in 2008. The increase in operating expenses is primarily due to the increased production during 2008.
Capital expenditures paid by the Working Interest Owners decreased 87% from $1,716,676 in 2007 to $228,959 in 2008. The higher amount of capital expenditures during 2007 related primarily to damages caused by Hurricanes Rita and Katrina.
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, $155,152 and $255,443 in 2008 and 2007, 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 2008, the Working Interest Owners refunded a net amount to the Trust of $2,388,061 from the Special Cost Escrow Account. As of December 31, 2008, approximately $4,325,503 remained in the Special Cost Escrow Account. In 2007, the Working Interest Owners refunded a net amount to the Trust of $125,391 from the Special Cost Escrow Account. As of December 31, 2007, approximately $6,713,564 remained in the Special Cost Escrow Account. The net refund for 2008 compared to the net
refund for 2007 was primarily due to a revision to the Special Cost Escrow Account related to the outside audit commenced by the Trust as discussed above. See"-Operations".
Summary By Property
Listed below is a summary of 2008 operations as compared to 2007 of the five principal Royalty Properties based on gross revenues generated during these periods combined.
Eugene Island 339
Eugene Island 339 crude oil revenues increased $1,519,790, from $18,179,707 in 2007 to $19,699,497 in 2008, primarily due to an increase in average price of crude oil received. The average price of crude oil increased from $63.22 per barrel in 2007 to $104.60 per barrel in 2008. This increase was partially offset by a decrease in crude oil production from 287,539 barrels in 2007 to 188,337 barrels in 2008. Gas revenues increased $2,960,096, from $1,222,807 in 2007 to $4,182,903 in 2008, primarily due to an increase in gas production from 194,633 Mcf in 2007 to 435,583 Mcf in 2008 as a result of completion in July 2007 of the pipeline connection to the sales point on the Eugene Island 361 platform. The average price received for natural gas increased from $6.28 per Mcf in 2007 to $9.60 per Mcf in 2008. Capital expenditures increased from $190,093 in 2007 to $518,385 in 2008 due to the conversion to a water injector. Operating expenses increased from $2,214,130 in 2007 to $2,868,686 in 2008 primarily due to increased production.
Production from Eugene Island 339 ceased following damage inflicted by Hurricane Ike in September 2008, as the platforms and wells on Eugene Island 339 were completely destroyed. At this point in time, there can be no assurance that production will restored at Eugene Island 339. See "-Operations."
Ship Shoal 182/183
Ship Shoal 182/183 crude oil revenues increased from $18,924,236 in 2007 to $21,775,671 in 2008, due to an increase in crude oil prices from $67.35 per barrel in 2007 to $107.70 per barrel in 2008. This increase was partially offset by a decrease in crude oil production from 280,996 barrels in 2007 to 202,185 barrels in 2008. This production decline is related in part to a three day field shut-in for repairs at Ship Shoal 182/183. Gas revenues decreased from $8,013,970 in 2007 to $4,726,292 in 2008 due to a decrease in gas volumes from 1,089,709 Mcf in 2007 to 508,781 Mcf in 2008. The decrease in gas volumes was due to a shut-in as a result of an obstructed pipeline and the natural decline of production. The average natural gas sales price increased from $7.35 per Mcf in 2007 to $9.29 per Mcf in 2008. Capital expenditures decreased from $701,753 in 2007 to ($419,971) in 2008 primarily due to an audit credit adjustment for prior periods. Operating expenses decreased from $3,204,308 in 2007 to $2,471,185 in 2008 due to decreased production during 2008.
Production from Ship Shoal 182 and 183 ceased following damage inflicted by Hurricane Ike in September 2008. While Hurricane Ike caused limited surface damage to the facilities at Ship Shoal 182/183, all of the wells at Ship Shoal 182/183 were shut-in following hurricane-related damage to a third-party transporter's natural gas pipeline. A limited volume of oil production was restored in November 2008, with an average rate of daily oil production from November 20, 2008 through January 31, 2009 of approximately 831 barrels per day. The volume of oil production that can be produced is limited by the amount of gas that is also produced by the oil wells. Production is expected to remain limited until the natural gas pipeline is fully repaired and tested, which is anticipated to occur in the second quarter of 2009, but which is also in the control of the pipeline owner. At this point in time, there can be no assurance as to when, or if at all, production may be restored at Ship Shoal 182/183. See "-Operations."
West Cameron 643
West Cameron 643 gas revenues increased from $802,575 in 2007 to $2,024,841 in 2008 due primarily to an increase in gas volumes from 126,971 Mcf in 2007 to 214,130 Mcf in 2008. The increase in gas volumes resulted from increased production for the last three quarters of 2008, compared to the last three quarters of 2007. The average natural gas sales price increased from $6.32 per Mcf in 2007 to $9.46 per Mcf in 2008. Operating expenses decreased from $942,457 in 2007 to $1,233,887 in 2008. Capital expenditures increased from $0 in 2007 to $27,953 in 2008.
Production from West Cameron 643 ceased following damage inflicted by Hurricane Ike in September 2008 to a third-party transporter's pipeline. The Managing General Partner of the Partnership understands that the pipeline is in the process of being restored; however, the pipeline is not expected to be able to take production until at least the end of 2009. At this point in time, there can be no assurance as to when, or if at all, production may be restored at West Cameron 643.
East Cameron 371
East Cameron 371 gas revenues increased from $150,500 in 2007 to $252,992 in 2008. Oil revenues increased from $30,164 in 2007 to $47,962 in 2008. Capital expenditures were $0 in 2007 and 2008 and operating expenses increased from $174,559 in 2007 to $298,413 in 2008.
Production from East Cameron 371 ceased following damage inflicted by Hurricane Ike in September 2008 to a third-party transporter's pipeline. The Managing General Partner of the Partnership understands that the pipeline is in the process of being restored; however, there can be no assurance as to when, or if at all, production may be restored at East Cameron 371.
South Timbalier 36/37
South Timbalier 36/37 oil revenues decreased from $595,442 in 2007 to $592,068 in 2008, due to a decrease in production from 9,229 barrels in 2007 to 5,802 barrels in 2008, offset by an increase in crude oil prices from $64.52 per barrel in 2007 to $102.05 per barrel in 2008. Capital expenditures decreased from $109,901 in 2007 to $43,345 in 2008. Operating expenses increased $78,730 from $61,780 in 2007 to $140,510 in 2008.
Years 2007 and 2006
Royalty income increased approximately 309% from $2,510,936 in 2006 to $10,257,485 in 2007 primarily due to an increase in gas revenues and crude oil and condensate revenues as discussed below.
For 2007, the Trust had undistributed net loss of $9,297. For 2006, the Trust had undistributed net loss of $2,092. An increase in distributed net income represents revenues generated during the respective period but not distributed by the Working Interest Owners. Collection of undistributed net income is the subsequent receipt in future periods from the related Working Interest Owner(s) of revenues generated in prior periods but not yet distributed.
Volumes and dollar amounts discussed below represent amounts recorded by the Working Interest Owners unless otherwise specified.
Natural Gas and Gas Products
Natural gas and gas products revenues increased 195% from $4,003,561 in 2006 to $11,820,973 in 2007, primarily due to a 176% increase in natural gas and gas products volumes from 600,477 Mcf equivalents in 2006 to 1,654,836 Mcf equivalents in 2007. The average price received for natural gas increased 6% from $6.70 per Mcf in 2006 to $7.11 Mcf in 2007.
Crude Oil and Condensate
Crude oil and condensate revenues increased 40% from $26,869,007 in 2006 to $37,732,678 in 2007, due primarily to a 37% increase in crude oil and condensate volumes from 421,763 barrels in 2006 to 578,159 barrels in 2007. The average price received for crude oil and condensate increased by 2% from $63.71 in 2006 to $65.26 in 2007.
The increase in crude oil and condensate volume, as well as natural gas volumes and gas products production volumes, for 2007, compared to 2006, resulted primarily from repairs of certain damages caused by Hurricanes Rita and Katrina.
Operating and Capital Expenditures
Operating expenses paid by the Working Interest Owners increased 12% from $5,876,944 in 2006 to $6,598,909 in 2007. The increase in operating expenses is primarily due to the increased production during 2007.
Capital expenditures paid by the Working Interest Owners decreased 82% from $9,443,605 in 2006 to $1,716,676 in 2007. The higher amount of capital expenditures during 2006 related primarily to damages caused by Hurricanes Rita and Katrina.
Special Cost Escrow Account
In the first quarter of 2008, there was a net release of funds from the Special Cost Escrow Account of approximately $1,318,188.
In 2007, the Working Interest Owners refunded a net amount to the Trust of $125,391 from the Special Cost Escrow Account. As of December 31, 2007, approximately $6,713,564 remained in the Special Cost Escrow Account. In 2006, the Working Interest Owners deposited a net amount to the Trust of $1,188,000 from the Special Cost Escrow Account. As of December 31, 2006, approximately $6,839,000 remained in the Special Cost Escrow Account. The net refund for 2007 compared to net deposit for 2006 was primarily due to a decrease in the estimate of projected capital expenditures, production costs and abandonment costs of the Royalty Properties due to hurricane related damages.
Summary By Property
Listed below is a summary of 2007 operations as compared to 2006 of the five principal Royalty Properties based on gross revenues generated during these periods combined.
Eugene Island 339
Eugene Island 339 crude oil revenues increased $8,959,469, from $9,220,238 in 2006 to $18,179,707 in 2007, primarily due to an increase in production. Crude oil production increased from 149,887 barrels in 2006 to 287,539 barrels in 2007. The average price of crude oil increased from $61.51 per barrel in 2006 to $63.22 per barrel in 2007. Gas revenues increased $674,988, from $547,819 in 2006 to $1,222,807 in 2007, primarily due to an increase in gas production from 83,101 Mcf in 2006 to 194,633 Mcf in 2007 as a result of completion in July 2007 of the pipeline connection to the existing sales point on the Eugene Island 361 platform. The average price received for natural gas decreased from $6.59 per Mcf in 2006 to $6.28 per Mcf in 2007. Capital expenditures decreased from $3,524,145 in 2006 to $190,093 in 2007. The capital expenditures incurred during 2006 were due to hurricane-related damages. Operating expenses decreased from $2,584,319 in 2006 to $2,214,130 in 2007 primarily due to a decrease in workover expenses.
Ship Shoal 182/183
Ship Shoal 182/183 crude oil revenues increased from $17,107,346 in 2006 to $18,924,236 in 2007, due to an increase in crude oil prices from $64.93 per barrel in 2006 to $67.35 per barrel in 2007 and an increase in crude oil production from 263,486 barrels in 2006 to 280,996 barrels in 2007. Gas revenues increased from $3,044,766 in 2006 to $8,013,970 in 2007 due to an increase in gas volumes from 453,910 Mcf in 2006 to 1,089,709 Mcf in 2007. The increase in gas volumes resulted from no gas being produced until the third quarter of 2006 due to hurricane-related damages. The average natural gas sales price increased from $6.71 per Mcf in 2006 to $7.35 per Mcf in 2007. Capital expenditures decreased from $5,718,239 in 2006 to $701,753 in 2007 primarily due to hurricane-related repairs having been made in 2006. Operating expenses increased from $2,782,327 in 2006 to $3,204,308 in 2007 due to increased production during 2007.
West Cameron 643
West Cameron 643 gas revenues increased from $33,587 in 2006 to $802,575 in 2007 due primarily to an increase in gas volumes from 6,628 Mcf in 2006 to 126,971 Mcf in 2007. The increase in gas volumes resulted from no gas being produced until the third quarter of 2006 at which time only a limited amount of production had begun. The average natural gas sales price increased from $5.07 per Mcf in 2006 to $6.32 per Mcf in 2007. Operating expenses increased from $404,380 in 2006 to $942,457 in 2007 due to the increased production during 2007. Capital expenditures decreased from $46,156 in 2006 to $0 in 2007.
East Cameron 371
East Cameron 371 gas revenues were $770 in 2006 and $150,500 in 2007. Oil revenues were $0 in 2006 and $30,164 in 2007. Capital expenditures decreased from $315 in 2006 to $0 in 2007 and operating expenses increased from $31,917 in 2006 to $174,559 in 2007.
South Timbalier 36/37
South Timbalier 36/37 oil revenues increased from $527,183 in 2006 to $595,442 in 2007, due to an increase in crude oil production from 8,142 barrels in 2006 to 9,229 barrels in 2007, offset by a slight decrease in crude oil prices from $64.75 per barrel in 2006 to $64.52 per barrel in 2007. Capital expenditures increased from $34,316 in 2006 to $109,901 in 2007.
Production and Price Review
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 12-month period ended on October 31 of each year, respectively.
(2)An increase in undistributed net income represents revenues generated during the respective period but not distributed by the Working Interest Owners. Collection of undistributed net income is the subsequent receipt in future periods from the related Working Interest Owner(s) of revenues generated in prior periods but not yet distributed. For the twelve months ended December 31, 2008, the collection of prior undistributed net income was $132,688.
(3)See "Management's Discussion and Analysis of Financial Condition and Results of Operations-Operations" and Note 4 to the Notes to the Financial Statements under Item 8 of this Form 10-K for a discussion regarding uncertainty of distributions. Off-Balance Sheet Arrangements
The Trust has no off-balance sheet arrangements.
Contractual Obligations
As of December 31, 2008, the Trust had no obligations or commitments to make future contractual obligations except for administrative fees owed to the Trustee pursuant to the Trust Agreement. In 2008, the Trust paid the Trustee an administrative fee of $182,500.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures 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
Austin, Texas
We have audited the accompanying statements of assets, liabilities and trust corpus of TEL Offshore Trust (the "Trust") as of December 31, 2008 and 2007, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Corporate Trustee. Our responsibility is to express an opinion on the 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by the Corporate Trustee, 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, 2008 and 2007, and its distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2008, on the comprehensive basis of accounting described in Note 3 to the financial statements.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Trust's internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 31, 2009 expressed an unqualified opinion on the Trust's internal control over financial reporting.
Deloitte & Touche LLP
Houston, Texas
March 31, 2009
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 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. 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 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, 2008 the reserve amount was $2,233,291;
(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 approximately $24.2 million (unaudited) as of October 31, 2008. 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 The Bank of New York Mellon Trust Company, N.A., which succeeded JPMorgan Chase Bank, N.A. as the Corporate Trustee, effective October 2, 2006 pursuant to an agreement under which The Bank of New York acquired substantially all of the Corporate Trust business of JPMorgan Chase (formerly known as The Chase Manhattan Bank), 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
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS (Continued)
(2) Net Overriding Royalty Interest (Continued)
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 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 Texaco Exploration and Production Inc. ("TEPI") were assigned to Chevron U.S.A. Inc. ("Chevron") on May 1, 2002. Crude oil sales from the Chevron and TEPI properties added together accounted for approximately 99% for 2008, 2007 and 2006 of crude oil revenues from the Royalty Properties. Sales to Chevron Corporation accounted for approximately 99% of total gas revenues from the Royalty Properties during 2008, 2007 and 2006.
The Trust's share of Royalty income was reduced by approximately $481,561, $441,148 and $350,927 in 2008, 2007 and 2006, 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.
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS (Continued)
(3) Basis of Accounting (Continued)
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 interests 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 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 of assumptions concerning expected future conditions. There were no write downs taken in the periods presented.
The Special Cost Escrow account (see Note 5) 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 2005, Hurricane Katrina and Hurricane Rita caused significant damage to various platforms and third-party transportation systems, which resulted in oil and gas production delays in the Royalty Properties. During 2006, several of the platforms and facilities on the Royalty Properties were restored, and by the third quarter of 2007 all but one of the platforms and facilities had been restored. One of the platforms and facilities on Eugene Island was destroyed and has not been restored. Since
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS (Continued)
(4) Distributions to Unit Holders (Continued)
those hurricanes, overall production slowly returned to normal production levels, until production ceased at Eugene Island 339 and Ship Shoal 182 and 183 following damages inflicted by Hurricane Ike in September 2008. Future Net Proceeds may take into account the Trust's share of project costs and other related expenditures that are not covered by insurance of the operator of the Royalty Properties. The extensive damage caused by hurricanes Katrina and Rita led to significant demand for services and supplies for repairs in the offshore Gulf of Mexico, which increased levels of expenditures. The reduced oil and gas production and increased costs reduced the cash income distributions to unitholders significantly during 2006. During the fourth quarter 2006, the Trust resumed distributions.
Set forth below are the quarterly distributions made by the Trust for 2008 and 2007.
Future distributions are expected to be severely negatively impacted as a result of Hurricane Ike, and there may not be sufficient Net Proceeds to make one or more scheduled distributions.
(5) 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 $155,152, $255,443 and $150,109 for 2008, 2007 and 2006, respectively, serves to reduce the Trust's share of allocated production costs. As of December 31, 2008, 2007 and 2006, approximately $4,325,503, $6,714,000 and $6,839,000, 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 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.
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS (Continued)
(5) Special Cost Escrow Account (Continued)
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.
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 2008, the Working Interest Owners refunded a net amount of approximately $2,388,061 from the Special Cost Escrow Account. In 2007, the Working Interest Owners refunded a net amount of approximately $125,391 from the Special Cost Escrow Account. In 2006, the Working Interest Owners deposited a net amount of approximately $1,188,239 into the Special Cost Escrow Account. The net deposits were made primarily due to changes in the estimate of projected capital expenditures, production costs and abandonment costs of the Royalty Properties.
(6) Reserve For Future Trust Expenses
The Trust made a determination in 1998 to maintain a cash reserve equal to approximately three times the average expenses of the Trust during each of the past three years to provide for future administrative expenses in connection with the winding up of the Trust. During 2008, the Trust increased its reserve by $349,565 for a reserve balance of $2,233,291 as of December 31, 2008. The reserve amount at December 31, 2007 was $1,883,726.
(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
The Managing General Partner of the Partnership has advised the Trust that, although the Working Interest Owners 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.
(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, 2008, with no provision for future increases or decreases except for periodic price redeterminations in accordance with existing gas contracts.
On October 7, 2008, the Trust announced that production from the two most significant oil and gas properties associated with the Trust had ceased following damage inflicted by Hurricane Ike in
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS (Continued)
(9) Supplemental Reserve Information (Unaudited) (Continued)
September 2008. The platforms and wells on Eugene Island 339 were completely destroyed by the hurricane. In order to restore production at Eugene Island 339, Chevron expects that it would need to redevelop the facility and drill new wells. The Trust had expected Chevron to make a decision in the first quarter of 2009 whether to proceed with any such development; however, Chevron is still assessing its alternatives and the economic feasibility for restoring production at the property. Chevron's decisions regarding Eugene Island 339 impact the treatment of Eugene Island for purposes of preparing a reserve report for the Partnership. Solely for purposes of being able to complete the reserve report so that the Trust could file its Form 10-K for the year ended December 31, 2008, DeGolyer and MacNaughton assumed that Eugene Island 339 will not be redeveloped. As such, the reserve study does not include any reserves or values attributable to Eugene Island 339, nor does it include the Trust's percentage share of the total plugging and abandonment costs related to Eugene Island 339, with costs for 2009 alone estimated to be approximately $61 million. At this point in time, there can be no assurance as to how or when, or if at all, production may be restored at Eugene Island 339. Based on the reserve study of DeGolyer and MacNaughton for the oil and gas reserves attributable to the Partnership as of October 31, 2007, Eugene Island 339 accounted for approximately 34% of the total future net revenues attributable to the Partnership's interest in the Royalty as of October 31, 2007.
The reserve volumes and revenue values attributable to the Partnership's royalty interest were estimated from projections of reserves and revenue attributable to the combined interests consisting of the Partnership's royalty interest and the retained interest of the Working Interest Owners in the Royalty Properties. Net reserves attributable to the Partnership's royalty interest were estimated by allocating to the Partnership a portion of the estimated combined net reserves of the subject properties based on the ratio of the Partnership's interest in future net revenues to combined future gross revenues. Because the net reserve volumes attributable to the Partnership's royalty interest are estimated using an allocation of reserves based on estimates of future revenue, a change in prices or costs will result in changes in the estimated net reserves. Therefore, the estimated net reserves attributable to the Partnership's royalty interest will vary if different future price and cost assumptions are used. All reserves attributable to the Partnership's royalty interest are located in the United States. Total future net revenues attributable to the Partnership's interest in the Royalty were estimated at $24.2 million as of October 31, 2008 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.
Distributable income for the Partnership for the periods ended December 31, 2008, 2007 and 2006 included net proceeds relating to production of reserves from the Royalty Properties for the twelve months ended October 31, 2008, 2007 and 2006, respectively.
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS (Continued)
(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 5 above. See Note 4 for a discussion regarding uncertainty of distributions.
*****
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 Securities 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 The Bank of New York Mellon Trust Company, 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 "-The Trustees and the Unit holders have no control over the operation or development of the Royalty Properties and have little influence over operation or development" in the Trust's Form 10-K and "Management's Discussion and Analysis of Financial Condition and Results of Operation" included in this Form 10-K, for a description 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
In connection with the evaluation by the Corporate Trustee of changes in internal control over financial reporting of the Trust, no change in the Trust's internal control over financial reporting was identified that has materially affected, or is reasonably likely to materially affect, the Trust's internal control over financial reporting.
Trustee's Report on Internal Control over Financial Reporting
A registrant's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A registrant's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the registrant; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the registrant are being made
only in accordance with authorizations of management and directors of the registrant; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the registrants assets that could have a material effect on the financial statements.
The Corporate Trustee is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) promulgated under the Securities and Exchange Act of 1934, as amended. The Corporate Trustee conducted an evaluation of the effectiveness of the Trust's internal control over financial reporting based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Corporate Trustee's evaluation under the framework in Internal Control-Integrated Framework, the Corporate Trustee concluded that the Trust's internal control over financial reporting was effective as of December 31, 2008.
Deloitte & Touche, LLP, the Trust's independent registered public accounting firm that audited the financial statements included in this Form 10-K, has issued an attestation report on the effectiveness of the Trust's internal control over financial reporting.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
March 31,
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Trustees and Unit Holders of
TEL Offshore Trust
Austin, Texas
We have audited the internal control over financial reporting of TEL Offshore Trust (the "Trust") as of December 31, 2008 based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Corporate Trustee is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Trustee's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Trust's internal control over financial reporting based on our audit.
We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A trust's internal control over financial reporting is a process designed by, or under the supervision of, the trust's trustee, and effected by the trustees and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the comprehensive basis of accounting described in Note 3 to the financial statements. A trust's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the trust; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with the comprehensive basis of accounting described in Note 3 of the financial statements, and that receipts and expenditures of the trust are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the trust's assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper trustee override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the financial statements as of and for the year ended December 31, 2008 of the Trust and our report dated March 31, 2009 expressed an unqualified opinion on those financial statements.
Deloitte & Touche LLP
Houston, Texas
March 31, 2009
Item 9B.
Item 9B. Other Information.
None.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance.
There are no directors or executive officers of the Registrant. The Trustees consist of a Corporate Trustee and three Individual Trustees. The Bank of New York Mellon Trust Company, N.A. 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 principal executive officer, principal financial officer, principal accounting officer or controller and, therefore, has not adopted a code of ethics applicable to such persons. However, employees of the Corporate 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.
Section 16(a) Beneficial Ownership Reporting Compliance.
The Trust has no directors or officers. Accordingly, only holders of more than 10% of the Trust's Units are required to file with the SEC initial reports of ownership of Units and reports of changes in such ownership pursuant to Section 16 under the Securities Exchange Act of 1934. Based solely on a review of these reports, the Trust believes that the applicable reporting requirements of Section 16(a) of the Securities Exchange Act of 1934 were complied with for all transactions that occurred in 2008.
Item 11.
Item 11. Executive Compensation.
Not applicable.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
(a)Security Ownership of Certain Beneficial Owners.
The Trust has no officers or directors. Accordingly, only holders of more than 5% of the Trust's Units are required to file reports with the SEC on Schedule 13D or Schedule 13G and holders of 10% or more of the Trust's Units are required to file initial and other reports with the SEC pursuant to Section 16 of the Securities Exchange Act of 1934. Based solely on a review of reports, the Trust is not aware of such holders as of the date of this report.
(b)Security Ownership of Management.
Not applicable.
(c)Changes in Control.
The Trust knows of no arrangements, including the pledge of securities of the Trust, the operation of which may at a subsequent date result in a change in control of the Trust.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
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.
Crude oil sales to Chevron Corporation accounted for approximately 99% of total crude oil revenues from the Royalty Properties during 2008, 2007 and 2006. During such years, approximately 99% of Chevron's natural gas and natural gas liquids relative to the Royalty Properties were committed and sold to Chevron Texaco Natural Gas.
The Trust's share of Royalty income was reduced by approximately $482,000, $441,000 and $351,000 in 2008, 2007 and 2006, respectively, 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 2008, 2007 and 2006.
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 Trustees have appointed Deloitte & Touche, LLP, the member firm of Deloitte & Touche Tohmatsu, and their respective affiliates (collectively "Deloitte") as the independent registered public accounting firm to audit the trust's financial statements for the fiscal year ending December 31, 2009. During fiscal 2008, Deloitte served as the Trust's independent registered public accounting firm and also provided certain tax services.
The following table presents the aggregate fees billed to the Trust for the fiscal years ended December 31, 2008 and 2007 by Deloitte:
(1)Fees for audit services in 2008 and 2007 consisted of the audit of the Trust's annual financial statements and reviews of the Trust's quarterly financial statements. Services in 2008 also included the attestation on the effectiveness of the Trust's internal control over financial reporting.
(2)Fees for tax services billed in 2008 and 2007 consisted of tax compliance services.
PART IV
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. The Bank of New York Mellon Trust Company, N.A. succeeded JPMorgan Chase Bank as Corporate Trustee. JPMorgan Chase Bank is successor by mergers to the original corporate trustee, Texas Commerce Bank National Association.)
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, 2009.
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.