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TABLE OF CONTENTS
PART IV

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K


(Mark One)
ý		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934
for the fiscal year ended December 31, 2016
or
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934
for the transition period from to

Commission File Number 000-6910

TEL OFFSHORE TRUST
(Exact name of registrant as specified in its charter)


Texas (State or other jurisdiction of incorporation or organization)		76-6004064 (I.R.S. Employer Identification No.)
The Bank of New York Mellon Trust Company, N.A., Trustee 919 Congress Avenue, Suite 500 Austin, Texas (Address of principal executive offices)		78701 (Zip Code)

Registrant's telephone number, including area code: (512) 236-6599

Securities registered pursuant to Section 12(b) of the Act:

Title of each class		Name of each exchange on which registered

None		None

Securities registered pursuant to Section 12(g) of the Act:

Units of Beneficial Interest
(Title of class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No ý.

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No ý.

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.


Large accelerated filer o		Accelerated filer o		Non-accelerated filer ý (Do not check if a smaller reporting company)		Smaller reporting company o		Emerging growth company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No ý

The aggregate market value of the 4,751,510 Units of Beneficial Interest in TEL Offshore Trust held by non-affiliates as of the last business day of the registrant's most recently completed second fiscal quarter was $712,726.50 based on a June 30, 2016 closing sales price of $0.15.

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.

As of March 30, 2017, there were 4,751,510 Units of Beneficial Interest in TEL Offshore Trust outstanding.

Documents Incorporated By Reference: None

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TABLE OF CONTENTS

		Page

PART I
Item 1.	Business	4
Item 1A.	Risk Factors	15
Item 1B.	Unresolved Staff Comments	16
Item 2.	Properties	16
Item 3.	Legal Proceedings	16
Item 4.	Mine Safety Disclosures	18
PART II
Item 5.	Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchasers of Equity Securities	19
Item 6.	Selected Financial Data	19
Item 7.	Trustee's Discussion and Analysis of Financial Condition and Results of Operation	19
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	29
Item 8.	Financial Statements and Supplementary Data	30
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	46
Item 9A.	Controls and Procedures	46
Item 9B.	Other Information	47
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	48
Item 11.	Executive Compensation	48
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unit holder Matters	48
Item 13.	Certain Relationships and Related Transactions, and Director Independence	49
Item 14.	Principal Accountant Fees and Services	49
PART IV
Item 15.	Exhibits, Financial Statement Schedules	51
Item 16.	Form 10-K Summary	53
SIGNATURES		54

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Note Regarding Forward-Looking Statements

This Annual Report on Form 10-K (this "Form 10-K") includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included in this Form 10-K, including, without limitation, statements under "Trustee's Discussion and Analysis of Financial Condition and Results of Operation" in Item 7 of Part II and elsewhere herein regarding the financial position and other plans and objectives are forward-looking statements. Forward-looking statements are generally accompanied by words such as "estimate," "project," "predict," "believe," "expect," "anticipate," "could," "may," "should," "intend" or other words that convey the uncertainty of future events or outcomes. These forward-looking statements are based on current expectations and assumptions about future events. Although Chevron USA, Inc., the Managing General Partner of the Partnership (as defined below) has advised the Trust that the Managing General Partner believes that the expectations reflected in the forward-looking statements contained herein are reasonable, no assurance can be given that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from expectations are disclosed in this Form 10-K, including without limitation in conjunction with the forward- looking statements included in this Form 10-K. Risks factors that may affect actual results and Trust distributions include, without limitation:

•: the outcome of the Probate Proceeding (as defined in "Legal Proceedings—Probate Proceeding") and the possibility that the Trust may be terminated;
•: the Trust's utilization of its cash reserves to pay expenses and potential inability to pay future expenses due to lack of net proceeds or additional advances from the Corporate Trustee, received by the Trust;
•: the Trust's ability to obtain loans or other funding for the payment of future expenses since the royalty interest has been sold and the Trust has no other source of income.

Should any event or circumstances contemplated by the risks or uncertainties described above or elsewhere in this Form 10-K occur, or should any material underlying assumptions prove incorrect, actual results may differ materially from future results expressed or implied by the forward-looking statements. All subsequent written and oral forward-looking statements attributable to the Managing General Partner or the Trust or persons acting on behalf of the Managing General Partner or the Trust are expressly qualified in their entirety by such forward-looking statements. See "Item 1A—Risk Factors" below in this Form 10-K for a summary description of principal risk factors.

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PART I

Item 1. Business.

DESCRIPTION OF THE TRUST

General

The TEL Offshore Trust, which we refer to herein as the "Trust," was created under the laws of the State of Texas in 1983 and maintains its offices at the office of The Bank of New York Mellon Trust Company, N.A., whom we refer to as the "Corporate Trustee," 919 Congress Avenue, Suite 500, Austin, Texas 78701. The telephone number of the Corporate Trustee is 1 (512) 236-6599. Gary C. Evans, Thomas H. Owen, Jr. and Jeffrey S. Swanson currently serve as individual trustees of the Trust and are referred to herein as the "Individual Trustees." The Individual Trustees tendered their resignations on January 17, 2017 and such resignations will become effective on September 1, 2017, a date more than one hundred twenty days after the date upon which this Form 10-K is mailed to the Trust's Unit holders. 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, which we refer to herein as the "SEC." Electronic filings by the Trust with the SEC are available free of charge through the SEC's website at www.sec.gov. The Trust will also provide paper copies of its recent filing free upon request to 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 of beneficial interest in the Trust, which we refer to herein as "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 TEL Offshore Trust Partnership, which we refer to herein as 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 (as defined below), 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, which we refer to herein as the "Managing General Partner," of the Partnership in accordance with their interests. The Plan was effected by transferring the Original Royalty (as defined below) to the Partnership, contributing the common stock of Tenneco Offshore II Company to the Trust, and issuing certificates evidencing Units in liquidation and cancellation of Tenneco Offshore's common stock.

The principal asset of the Trust consists of a 99.99% interest in the Partnership. Chevron U.S.A., Inc., or "Chevron," owns the remaining 0.01% interest in the Partnership and is the current Managing General Partner. Until October 27, 2011, the Partnership owned 100% of an overriding royalty interest equivalent to a 25% net profits interest (the "Original Royalty"), in certain oil and gas properties, which we refer to herein as the "Royalty Properties," located offshore Louisiana. The term "Original Royalty" shall refer to the initial 25% net profits interest in the Royalty Properties and the term "Royalty" shall refer to the applicable net profits interest held from time to time by the Partnership following the Royalty Sales (as defined below).

On October 27, 2011, the Trust issued a press release announcing that the Partnership had consummated the sale (the "2011 Royalty Sale") of 20% of the Original Royalty (or 5% of 8/8ths) to RNR Production, Land and Cattle Company, Inc. ("RNR Production"), though the assignment was effective as of August 1, 2011.

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On October 31, 2013, the Trust issued a press release announcing that the Partnership had consummated the sale (the "2013 Royalty Sale") of 25% of its remaining interest in the Original Royalty (or 5% of 8/8ths), to RNR Production, though the assignment was effective as of August 1, 2013.

On June 27, 2016, the Trust issued a press release announcing that the Partnership had, pursuant to the Probate Proceeding (as herein defined), consummated the sale of all of its remaining interest in the Original Royalty (60% or 15% of 8/8ths) (the "2016 Royalty Sale," and together with the 2011 Royalty Sale and the 2013 Royalty Sale, the "Royalty Sales"). The 2016 Royalty Sale was made to Arena Energy, LP and closed on June 24, 2016, but was effective as of February 1, 2016. The 2016 Royalty Sale generated $1,830,000 in gross proceeds and occurred as part of the previously announced formal auction process for the overriding royalty interest. The Trust received a distribution of approximately $1,756.624, representing 99.99% of the net proceeds from the Royalty Sale of $1,756,800.

As a result of the 2016 Royalty Sale, the Trust no longer owns any interest in the Royalty and therefore will not receive any further distributions of Net Proceeds (as herein defined) realized from any sale of oil, gas and associated hydrocarbons from the Royalty Properties. Because of the Remaining Matters (as defined in "Legal Proceedings—Probate Proceeding") in the Probate Proceeding (as defined in "Legal Proceedings—Probate Proceeding"), the Trust must hold the net proceeds from the 2016 Royalty Sale in a segregated account until the final resolution of the Remaining Matters. In addition, the Trust has set aside the distribution received from Cox Oil Offshore, L.L.C. ("Cox Oil") until the final resolution of the Remaining Matters. Distributions may be made from such segregated account for the payment of Trust expenses, which may include the payment of the Ad Litem's (as defined in "Legal Proceedings—Probate Proceeding") expenses, with the approval of the court. Any final disposition of the remaining net proceeds to Unit holders will be made in accordance with the final resolution of the Remaining Matters. For additional information about the Probate Proceeding, the Remaining Matters and the Ad Litem please see "Legal Proceedings—Probate Proceeding."

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. For a list of Working Interest Owners see "—Termination of the Trust—Description of Royalty Properties Sold—Properties and Wells."

The Trust Agreement; the Partnership Agreement and the Conveyance

The terms of the TEL Offshore Trust Agreement, which we refer to herein as 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 or if necessary to provide for the payment of liabilities of the Trust; (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 $2.0 million (without considering any sales of the Royalty) or (ii) a decision to terminate the Trust by the affirmative vote of Unit holders representing a majority of the Units; however, as a result of the Probate Proceeding and Remaining Matters, no termination of the Trust will occur until approved by the Court (as defined in "Legal Proceedings—Probate Proceeding").

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The terms of the Agreement of General Partnership of the Partnership, which we refer to herein as 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 will be liable for all damages and costs to the Trust if it breaches such agreement.

Prior to the 2016 Royalty Sale, the Conveyance and the Partnership Agreement entitled the Trust to its share (99.99%) of the Partnership's interest in 25% of the Net Proceeds (as defined herein) realized from the sale of the oil, gas and associated hydrocarbons produced from the Royalty Properties. Portions of the Partnership's interest in 25% of the Net Proceeds were sold in each of the Royalty Sales and as of February 1, 2016, the effective date of the 2016 Royalty Sale, the Partnership no longer held any interest in the Net Proceeds. See "—Termination of the Trust—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 their oil and gas properties for the period. "Net Proceeds" means for each quarterly period, the excess, if any, of the Gross Proceeds (as defined herein) for such period over Production Costs (as defined herein) 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 were not obligated to return any Royalty income received during periods where Royalty income was being generated, however, future subsequent amounts otherwise payable were reduced by the amount of any prior overpayments of such Royalty income. Prior to the 2016 Royalty Sale, the Working Interest Owners were required to maintain books and records sufficient to determine amounts payable under the Original Royalty. The Working Interest Owners were 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.

While the Trust had not received Net Proceeds from Chevron, as the operator of the Royalty Properties since December 2008, the Trust received payments in the aggregate amount of $1,316 from the operator of Eugene Island 342 during the fourth quarter of 2015. In addition, on April 15, 2016, but effective as of August 1, 2015, Chevron conveyed certain oil and gas properties to Cox Oil, including Chevron's interest in Ship Shoal 182/183 that was subject to the Royalty (the "Cox Oil Sale").

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All Net Proceeds from Cox Oil attributable to Ship Shoal 182/183 were not subject to offset by Chevron against the undistributed net loss carry forward attributable to the Royalty Properties held by Chevron. As a result of the August 1, 2015 effective time and the Ship Shoal 182/183 properties not being subject to the undistributed net loss carry forward, the Trust received a distribution from Cox Oil of $116,429 in May 2016. Despite the receipt of such funds, no distributions may be made by the Trust to the Unit holders until resolution of the Probate Proceeding.

Prior to the Royalty Sales, the Trust's primary source of liquidity and capital had been the Royalty income received from its share of the Net Proceeds from the Royalty Properties. As a result of the 2016 Royalty Sale, the Trust will not receive any further Net Proceeds from the Royalty Properties.

Because of the lack of Net Proceeds, the Trust has in the past not had sufficient cash flow to pay expenses on a current basis and has been required to borrow funds and to cause the Partnership to sell part of the Original Royalty in order to pay Trust expenses. As of December 31, 2016, the Trust had no unrestricted cash. The Trustees will endeavor to cause the Trust to pay the administrative costs of the Trust in accordance with the Trust Agreement. There are no assurances that the Trust will be able to continue to pay its administrative expenses.

Pursuant to the terms of the Trust Agreement, the Trustees, on behalf of the Trust, are authorized to borrow funds, and pledge the assets of the Trust to secure payments of such borrowings, in the event that cash on hand is not sufficient to pay the liabilities of the Trust. In the event that the Trustees borrow additional funds to pay the liabilities of the Trust, no distributions will be made to the Unit holders until the indebtedness created by such borrowings, in addition to outstanding amounts from prior borrowings, have been paid in full. As discussed below, the Corporate Trustee has previously loaned funds to the Trust for the payment of the Trust's liabilities.

On October 1, 2014, The Bank of New York Mellon Trust Company, N.A. made an advance to the Trust in the amount of $363,000, and the Corporate Trustee, on behalf of the Trust as the borrower, executed a Demand Promissory Note (the "2014 Note") relating to the unsecured $363,000 advance, which evidenced an extension of credit for borrowed money authorized under Section 6.08 of the Trust Agreement. The 2014 Note was mistakenly made payable to the Bank of New York Mellon ("BONYM"). In addition to the advances evidenced by the 2014 Note, The Bank of New York Mellon Trust Company, N.A. made additional cash advances in the amount of $209,885 to the Trust for the payment of its liabilities and expenses, primarily in connection with the Probate Proceeding. On September 25, 2015, The Bank of New York Mellon Trust Company, N.A. made an additional advance to the Trust in the amount of $484,000 and the Corporate Trustee, on behalf of the Trust as the borrower, executed a Renewal Demand Promissory Note (the "2015 Note") relating to (i) the unsecured $484,000 advance, (ii) the renewal and extension of the indebtedness originally evidenced by the 2014 Note in the original principal amount of $363,000, and (iii) previous advances in the amount of $209,885 made by The Bank of New York Mellon Trust Company, N.A. on behalf of the Trust. The 2015 Note provides for interest at the rate of one-half percent (0.5%) per annum. The 2015 Note became due and payable on December 31, 2016 and remains outstanding. The 2015 Note was also mistakenly made payable to BONYM. The 2015 Note has been assigned to The Bank of New York Mellon Trust Company, N.A., the party that has made the advances to the Trust. In addition to the indebtedness owing under the 2015 Note, the Trust has received through December 31, 2016 advances from The Bank of New York Mellon Trust Company, N.A. in the amount of $68,224 and on March 31, 2017, the Trust received an additional unsecured advance of $184,751.55 from The Bank of New York Mellon Trust Company, N.A. During the year ended December 31, 2016, a portion of the proceeds from the 2015 Note were used to pay Trust expenses. In addition, the Corporate Trustee has used the additional advances received in 2016 for the payment of its liabilities and expenses, primarily in connection with the Probate Proceeding. Although The Bank of New York Mellon Trust Company, N.A. has no obligation to do so, it is anticipated that The Bank of New York Mellon Trust Company, N.A. will continue to advance funds to the Trust for the payment of such expenses.

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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 incorporated by reference into 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.

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.

As of March 30, 2017, a total of 4,751,510 Units were issued and outstanding. The Units traded on the Nasdaq Capital Market, or "NASDAQ," from August 31, 2001 through January 2, 2011. On January 3, 2011, the Units were suspended from trading by the NASDAQ and the Trust filed a Form 25 with the SEC to announce the voluntary delisting of the Units. In an effort to reduce expenses, the Trustees determined that it was in the best interest of the Trust to voluntarily delist the Units and to cause the Units to no longer be traded on the NASDAQ. Since January 3, 2011, the Units have been quoted on the OTCQB™ Marketplace, which is an electronic quotation service operated by Pink OTC Markets Inc. for securities traded over-the-counter.

Distributions

The Trust has not received a distribution of Net Proceeds from Chevron, as the operator of the Royalty Properties, since December 2008 and has not made a distribution to Unit holders since January 9, 2009. As a result of the 2016 Royalty Sale, the Trust no longer owns any interest in the Royalty and therefore will not receive any further distributions of Net Proceeds for distributions to Unit holders. Because of the Remaining Matters in the Probate Proceeding, the Trust must hold the remaining proceeds from the 2016 Royalty Sale in a segregated account until the final resolution of the Remaining Matters at which time the Trust will distribute, in accordance with the final resolution of the Remaining Matters, any funds then held by the Trust. See "—Description of the Trust—History of the Trust" above and "Trustee's Discussion and Analysis of Financial Condition and Results of Operation—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 that 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

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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.

With respect to sales certificates issued by the Federal Energy Regulatory Commission, which we refer to herein as the "FERC," although the FERC has the power to compel refunds, it has not compelled 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 payable only out of the

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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 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 non-mortgage widely held fixed investment trust ("WHFIT") for federal income tax purposes. The Corporate Trustee, 919 Congress Avenue, Suite 500, Austin, Texas 78701, telephone number (512) 236-6599, 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. Notwithstanding the foregoing, the middlemen holding Units on behalf of Unit holders, and not the Trustees of the Trust, are solely responsible for complying with the information reporting requirements under the Treasury Regulations with respect to such Units, including the issuance of IRS Forms 1099 and certain written tax statements. Unit holders whose Units are held by middlemen should consult with such middlemen regarding the information that will be reported to them by the middlemen with respect to the Units.

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Income and Depletion

Each Unit holder of record as of the last business day of each quarter (the "Quarterly Record Date") 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.

Amounts available for distribution for each quarterly period as determined by the Trustees are distributed to Unit holders of record on each Quarterly Record Date. See "Description of the Units—Distributions" above. The terms of the Trust Agreement provide that taxable income attributable to such distributions will be reported to the Unit holder who receives such distributions, assuming that such holder is the holder of record on the Quarterly Record Date. In certain circumstances, however, a Unit holder may be required to report taxable income attributable to his or her Units but the Unit holder will not receive the distribution attributable to such income. For example, if the Trustees establish a reserve or borrow money to satisfy debts and liabilities of the Trust, income used to establish such reserve or to repay such loan will be reported by the Unit holder, even though such income is not distributed to the Unit holder.

Backup Withholding

Distributions from the Trust are generally subject to backup withholding at a rate of 28%. 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

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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 or exchange. Under current law, the highest marginal U.S. federal income tax rate applicable to long-term capital gains of individuals is 20%. This rate is subject to change by new legislation at any time. The deductibility of capital losses are subject to certain limitations.

Additional Tax on Net Investment Income

A 3.8% tax applies to certain net investment income earned by individuals, estates, and trusts with income above certain thresholds. For these purposes, investment income would generally include certain income derived from investments such as the Units and gain realized by a Unit holder from a sale of Units. In the case of an individual, the tax will be imposed on the lesser of (i) the Unit holder's net investment income or (ii) the amount by which the Unit holder's modified adjusted gross income exceeds $250,000 (if the Unit holder is married and filing jointly or a surviving spouse), $125,000 (if the Unit holder is married and filing separately) or $200,000 (in any other case).

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, currently 39.6% for individual non-U.S. Unit holders.

The Code and the Treasury Regulations thereunder treat the Trust as if it were a United States real property holding corporation. Accordingly, a non-U.S. Unit holder may be subject to United States federal income tax on any gain from the disposition of his Units if he meets certain ownership thresholds.

In addition, if a foreign corporation elects under provisions of the Code to treat the income from the Royalty as effectively connected with the conduct of a United States trade or business, the corporation may also be subject to the U.S. branch profits tax at a rate of 30%. This tax is imposed on U.S. branch profits of a foreign corporation that are not reinvested in the U.S. trade or business. This tax is in addition to the tax on effectively connected income. The branch profits tax may be either reduced or eliminated by treaty.

Pursuant to the Foreign Account Tax Compliance Act (commonly referred to as "FATCA"), distributions from the Trust to "foreign financial institutions" and certain other "non-financial foreign entities" may be subject to U.S. withholding taxes. Specifically, certain "withholdable payments" (including certain royalties, interest and other gains or income from U.S. sources) made to a foreign financial institution or non-financial foreign entity will generally be subject to the withholding tax unless the foreign financial institution or non-financial foreign entity complies with certain information reporting, withholding, identification, certification and related requirements imposed by FATCA. Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United States governing FATCA may be subject to different rules.

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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. Royalty income 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, Texas imposes a tax on gross revenues less certain deductions, as specifically set forth in the Texas franchise tax statute. 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 franchise tax as "passive entities." The Trust should be exempt from Texas franchise tax as a "passive entity." Since the Trust should be exempt from Texas franchise tax at the Trust level as a passive entity, each Unit holder that is considered a taxable entity under the Texas franchise tax would generally be required to include its Texas portion of Trust revenues in its own Texas franchise tax computation. Each Unit holder is urged to consult its own tax advisor regarding its possible Texas franchise tax liability.

STATUS OF THE TRUST

As described in more detail in "Legal Proceedings—Probate Proceeding" in Item 3 of this Form 10-K, the Petition for Modification and Termination of the Trust (the "Petition") filed by the Trustees with the Probate Court of Travis County, Texas (the "Court") requested that the Court modify the Trust Agreement to (1) allow for the termination of the Trust by a court order, and (2) allow the Trustees, as necessary to fulfill the purposes of the Trust and without Unit holder approval to (a) sell all or any portion of the Trust's interests in the Partnership or any other assets of the Trust, (b) exercise their rights to dissolve the Partnership, or (c) cause the Partnership to sell the Royalty. The goals in filing such probate proceeding (the "Probate Proceeding") were to permit the Trustees to direct the

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Partnership to sell the Royalty; to distribute the net proceeds resulting from such sale, after payment of the Trust's liabilities, to the Unit holders; and, to, thereafter terminate the Partnership and the Trust. The 2016 Royalty Sale was made pursuant to the Probate Proceeding. It is anticipated that once the Remaining Matters are resolved the Trust will be terminated. Upon termination of the Trust, the Trust will make a final distribution to Unit holders of any funds held by the Trust in accordance with the final resolution of the Probate Proceeding.

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

Properties and Wells

As of December 31, 2016, the Trust no longer held any interest in the Royalty or the Royalty Properties. As disclosed elsewhere in this Form 10-K, the Royalty in which the Trust had an interest was sold effective February 1, 2016.

Reserves

COMPETITION AND REGULATION

As disclosed elsewhere in this Form 10-K, the Royalty in which the Trust had an interest was sold effective February 1, 2016. As a result of this sale, the competition experienced by the Working Interest Owners and the regulations to which the Working Interest Owners and the Royalty Properties are subject is no longer considered to be material to the Trust.

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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.

The Trust is utilizing proceeds from borrowed funds and advances to pay expenses, and, as a result of the 2016 Royalty Sale, the Trustee will not receive any further Net Proceeds from the Royalty Properties to enable the Trust to pay expenses on a current basis. The Trustees have taken certain actions on behalf of the Trust as permitted under the Trust Agreement, which could materially impact the Unit holders.

Prior to the 2016 Royalty Sale, the Trust's primary source of liquidity and capital was the Royalty income received from its share of the Net Proceeds from the Royalty Properties. Although the Trust received payments in the aggregate amount of $1,316 from the operator of Eugene Island 342 during the fourth quarter of 2015, the Trust has not received a distribution of Net Proceeds from Chevron, as the operator of the Royalty Properties, since December 2008. The Trust has previously utilized its cash reserves from the 2011 Royalty Sale and the 2013 Royalty Sale to pay expenses. As of December 31, 2016, the Trust had no unrestricted cash. Most recently, the Trust has been utilizing funds loaned to the Trust by The Bank of New York Mellon Trust Company, N.A. to pay its ongoing expenses.

The Trust Agreement provides that, if necessary to provide for the payment of specific liabilities of the Trust then due, the Trustees may without a vote of the Unit holders (a) sell all or a portion of the Trust's interest in the Partnership or any other assets of the Trust for such cash consideration as the Trustees shall deem appropriate, (b) exercise their rights under the Partnership Agreement to dissolve the Partnership, or (c) cause a sale by the Partnership of the overriding royalty interest owned by the Partnership. Pursuant to these terms of the Trust Agreement, the Trustee's authorized the 2011 Royalty Sale and 2013 Royalty Sale to pay for expenses of the Trust. The 2016 Royalty Sale was made pursuant to the Probate Proceeding.

Pursuant to the terms of the Trust Agreement, the Trustees, on behalf of the Trust, are authorized to borrow funds, and pledge the assets of the Trust to secure payments of such borrowings, in the event that cash on hand is not sufficient to pay the liabilities of the Trust. In accordance with these provisions of the Trust Agreement, the Corporate Trustee, on behalf of the Trust as the borrower, has previously received loans and advances from The Bank of New York Mellon Trust Company, N.A. to the Trust for the payment of Trust expenses. The Trust Agreement provides that in the event that the Trustees borrow funds to pay the liabilities of the Trust, no distributions will be made to the Unit holders until the indebtedness created by such borrowings has been paid in full.

Although the Trustees caused the Partnership to sell the remaining Royalty, there is no assurance that there will be any funds available for distribution to Unit holders.

Due to the Remaining Matters in the Probate Proceeding, the Trust must hold the remaining proceeds from the 2016 Royalty Sale in a segregated account until the final resolution of the Remaining Matters. Distributions may be made from such segregated account for the payment of Trust expenses, which may include the payment of the Ad Litem's expenses, with the approval of the Court. Through the date of this Form 10-K, the Court has approved the payment of $772,842 in expenses from the segregated account. In addition, as a result of the Settlement Agreement as described in "Legal Proceedings—Probate Proceeding," the amount of $2.0 million was paid into a qualified settlement fund. These funds are also available, subject to Court approval, for the payment of attorneys' fees and expenses of the ad litem and other plaintiffs in the Remaining Matters. Any final disposition of the remaining net proceeds from the 2016 Royalty Sale and the settlement to Unit holders will be made in accordance with the final resolution of the Remaining Matters. Accordingly,

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there can be no assurances as to the amount, if any, of the proceeds that will be available for distribution to Unit holders.

The price and liquidity of the Trust's Units may be further affected by the Probate Proceeding.

The price of the Trust's Units has been volatile since the filing of the Probate Proceeding was announced. As developments occur in the Probate Proceeding, these developments may continue to affect the price of the Trust's units and increase the volatility of the price fluctuations. In addition, the Units have historically been thinly traded on the OTCQB Market. The over the counter market typically offers less liquidity than other trading markets, meaning that the number of investors interested in purchasing the Trust's Units at any time may be relatively small or non-existent. The Probate Proceeding may further limit the liquidity of the Trust's Units and Unit holders may not be able to sell their Units at or near asking prices or even at all if they desire to liquidate their Units in the Trust.

Unit holders have limited voting rights.

Voting rights as a Unit holder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of Unit holders or for an annual or other periodic re-election of the Trustees. Unlike corporations, which are generally governed by boards of directors elected by their equity holders, the Trust is currently administered by a Corporate Trustee and three Individual Trustees in accordance with the Trust Agreement and other organizational documents. The Individual Trustees tendered their resignations on January 17, 2017 and such resignations will become effective on September 1, 2017, a date more than one hundred twenty days after the date upon which this Form 10-K is mailed to the Trust's Unit holders. The Trustees have extremely limited discretion in their administration of the Trust.

Item 1B. Unresolved Staff Comments.

There were no unresolved Securities and Exchange Commission comments as of December 31, 2016.

Item 2. Properties.

Information regarding the Royalty Properties is included in Item 1 of this Form 10-K.

Item 3. Legal Proceedings.

Probate Proceeding

As a result of the ongoing costs and expenses of the Trust and the lack of any distributions or assurances of future distributions, on July 10, 2014, the Trustees filed a Petition for Modification and Termination of the Trust (the "Petition") with the Probate Court of Travis County, Texas (the "Court"). The Petition requested that the Court modify the Trust Agreement to (1) allow for the termination of the Trust by a court order, and (2) allow the Trustees, as necessary to fulfill the purposes of the Trust and without Unit holder approval to (a) sell all or any portion of the Trust's interests in the Partnership or any other assets of the Trust, (b) exercise their rights to dissolve the Partnership, or (c) cause the Partnership to sell the Royalty. The goals in filing such probate proceeding (the "Probate Proceeding") were to permit the Trustees to direct the Partnership to sell the Royalty; to distribute the net proceeds resulting from such sale, after payment of the Trust's liabilities, to the Unit holders; and, to, thereafter terminate the Partnership and the Trust. The Trust has completed the process of serving the Petition on the Trust's Unit holders. The Court appointed Glenn M. Karisch, attorney ad litem for certain unit holders of the Trust (the "Ad Litem") to represent any Unit holders that were not personally served. The Ad Litem filed a Counterclaim against the Trust on November 16, 2015 requesting (1) an order to

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sell all of the Royalty, and (2) an accounting of the general and administrative expenses of the Trust from 2008 through the present.

The Probate Proceeding was set for trial on January 15, 2016. Prior to trial, the Ad Litem filed a Motion to Sever asking the Court to sever all matters related to the requested modification of the Trust and the sale of Trust assets, as plead for, in part, in the petition originally filed by the Trustees and in the Ad Litem's Counterclaim, into a separate cause to proceed to trial. The Ad Litem also filed a Motion for Continuance requesting that the Court continue the trial of all remaining matters, including the Ad Litem's request for an accounting and the issues concerning the termination of the Trust, to a later date (the "Remaining Matters"). Prior to calling the case to trial, the Court granted the Ad Litem's Motion to Sever and Motion for Continuance, severed the matters related to the modification of the Trust and the sale of Trust assets ("Severed Proceeding"), and continued the Remaining Matters to a later date. The Severed Proceeding has been assigned Cause No. C-1-PB-16-000096 and is styled In re: TEL Offshore Trust.

The Severed Proceeding proceeded to trial before the Court on January 15, 2016. At trial, the Court entered a Final Judgment and Order (the "Order") granting the Trustees' request that the Trust Agreement be modified to permit the Trustees to direct the Partnership to sell the remaining overriding royalty interest held by the Partnership as soon as reasonably possible and granting the Ad Litem's request to sell all of the Royalty, notwithstanding any requirements of the Trust Agreement to the contrary. Thereafter, the Court ordered that the Trustees direct the Partnership to sell all of the Royalty owned by the Partnership through a sale to be conducted by EnergyNet.com, Inc. on or before May 1, 2016. On April 25, 2016, the Court approved an extension of the May 1, 2016 deadline to June 30, 2016.

On August 17, 2016, the Ad Litem filed a Second Amended Answer and First Amended Counterclaim seeking an accounting and asserting, among other causes of action, breach of fiduciary duties; negligence; gross negligence; intentional conduct and bad faith; and forfeiture of fees and punitive damages. The Ad Litem has also asserted other allegations against the Trustees. The Remaining Matters were originally set for trial on November 7, 2016. Trustees filed a motion for continuance of the Remaining Matters and a hearing for such continuance occurred on September 14, 2016. At the hearing, the Court granted the Trustees' motion for continuance of the Remaining Matters and scheduled the trial for June 12, 2017.

On October 3, 2016, the trial judge realigned the parties, such that the Ad Litem is now the plaintiff and the Trustees are the defendants. The Ad Litem then filed an Original Petition as Realigned Plaintiff ("Realigned Petition") on October 10, 2016, and a First Amended Petition as Realigned Plaintiff ("Amended Realigned Petition") on October 28, 2016, which continued to assert claims for breach of fiduciary duties and other claims against the Trustees on behalf of the beneficiaries. RNR Production Land and Cattle ("RNR") also filed its own petition on October 28, 2016, which asserted similar claims against the Trustees as the Ad Litem had asserted. Two other unitholders, Albert and Joyce Speisman ("Speismans" and, together with the Ad Litem and RNR, the "Plaintiffs") also filed a counterclaim on November 15, 2016, adopting the claims of the Realigned Petition.

On December 13, 2016, all parties in the Remaining Matters attended a mediation. As a result of the mediation, and without admitting any liability or wrongdoing, the Individual Trustees agreed to a settlement of all claims asserted against the Individual Trustees in the Remaining Matters (the "Settled Claims") pursuant to a Settlement Agreement (the "Settlement Agreement") that was signed effective January 17, 2017, among the Individual Trustees, the Ad Litem, RNR, and the Speismans. The Corporate Trustee was not a party to the Settlement Agreement, and remains as a party in the litigation of the Remaining Matters. A hearing was set for January 20, 2017 before the Court to consider all pending motions for Court approval of the Settlement Agreement, the entry of a proposed

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final judgment dismissing with prejudice all claims against the Individual Trustees as discussed more fully below (the "Final Judgment"), and other related matters.

On December 30, 2016, the Court entered an order (the "Order") that the Corporate Trustee had breached its fiduciary duties by paying itself compensation in violation of the Trust Agreement. The Court further found that the breach was intentional and a clear and serious breach. The Corporate Trustee believes that such ruling is legally improper, and plans to challenge and/or appeal such ruling at the appropriate time. It is expected that a determination of a remedy, if any, will be determined in connection with the outcome of the Remaining Matters.

At the January 20, 2017 hearing, the Court approved the Settlement Agreement. The Court also signed the Final Judgment as to the Individual Trustees, along with an order severing the Final Judgment as to Individual Trustees, into a separate cause number. The Court also granted the Ad Litem's Motion to Establish the TEL Offshore Trust Qualified Settlement Fund (the "QSF") and to Appoint Trustee and Administrator. According to the terms of the Settlement Agreement, the Individual Trustees (funded by an existing director and officer insurance policy) paid $2.0 million into the QSF. The QSF will be used as the Court orders and approves, including the payment of the Plaintiffs' attorneys' fees and expenses, the fees and expenses of the administrator of the QSF, and the remainder, if any, distributed to unitholders and/or former unitholders of the Trust according to a procedure to be determined by the Court.

On March 20, 2017, the Court granted the Ad Litem's motion on the measure of damages and denied motions by the Corporate Trustee challenging the standing of RNR and the Speismans. The Court also granted motions compelling the Corporate Trustee to assist in certain discovery matters. The Court also has approved fee applications from the Ad Litem for payment of certain expenses incurred by the Ad Litem.

Discovery is continuing in the Probate Proceeding. A pre-trail hearing is set for June 8, 2017 and the trial for the Remaining Matters is scheduled for June 12-30, 2017.

In connection with the previously disclosed Settlement Agreement, Gary C. Evans, Jeffrey S. Swanson and Thomas H. Owen, Jr. all submitted their resignations, as individual trustees of the Trust, by letter of January 17, 2017. Notice of the resignations was included in the Form 8-K filed January 17, 2017. This Form 10-K provides additional notice to all Unit holders that such resignations will be effective on September 1, 2017, a date more than 120 days after the filing and mailing of this Form 10-K. Pursuant to Section 8.03 of the Trust Agreement, with the consent of the Corporate Trustee, the Individual Trustees may resign and elect not to appoint successor individual trustees. The Corporate Trustee provided such consent and therefore, upon the effective date of the resignations, the Corporate Trustee will be the sole trustee under the Trust Agreement.

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

Item 5. Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchasers of Equity Securities.

Effective January 3, 2011, the Units have been quoted on the OTCQB™ Marketplace, which is an electronic quotation service operated by Pink OTC Markets Inc. for securities traded over-the-counter. Prior to January 3, 2011, the Trust Units were traded on the Nasdaq Capital Market under the symbol "TELOZ". At March 28, 2017, the 4,751,510 Units outstanding were held by 1,403 Unit holders of record. The high and low bid quotations obtained from data available on the Yahoo! Finance website, and distributions for each quarter for the years ended December 31, 2016 and 2015 were as follows. The over-the-counter quotations reflect inter-dealer prices, without retail mark-up, markdown or commissions, and may not represent actual transactions.

Quarter	High		Low		Distribution

2016:
Fourth	$	0.51	$	0.10	$	.000000
Third		0.75		0.10		.000000
Second		0.15		0.03		.000000
First		0.11		0.01		.000000
2015:
Fourth	$	0.16	$	0.01	$	.000000
Third		0.20		0.10		.000000
Second		0.34		0.12		.000000
First		0.35		0.11		.000000

See "Trustee's Discussion and Analysis of Financial Condition and Results of Operation—Operations" and "—Liquidity and Capital Resources" 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. Selected Financial Data.

	Year Ended December 31,

	2016(1)		2015		2014		2013		2012
Royalty income	$	117,353	$	1,316	$	0	$	0	$	0
Distributable income	$	0	$	0	$	0	$	0	$	0
Distributions per Unit	$	0.000000	$	0.000000	$	0.000000	$	0.000000	$	0.000000
Total assets	$	1,451,135	$	337,337	$	255,973	$	888,155	$	241,233

(1): Only includes selected financial data prior to February 1, 2016, the effective date of the 2016 Royalty Sale.

Item 7. Trustee's Discussion and Analysis of Financial Condition and Results of Operation.

On the last business day of each calendar quarter prior to August 1, 2011, the Working Interest Owners were to pay to the Partnership 25% of the Net Proceeds for the immediately preceding Quarterly Period; however, (i) as a result of the 2011 Royalty Sale, on the last business day of each calendar quarter after August 1, 2011 and prior to August 1, 2013, the Working Interest Owners were to pay to the Partnership 20% of the Net Proceeds for the immediately preceding Quarterly Period (ii) as a result of the 2013 Royalty Sale, on the last business day of each calendar quarter after August 1, 2013, the Working Interest Owners were to pay to the Partnership 15% of the Net Proceeds for the immediately preceding Quarterly Period and (iii) as a result of the 2016 Royalty Sale, from and after February 1, 2016, the Working Interest Owners are no longer required to pay to the Partnership

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any Net Proceeds. A Quarterly Period is each period of three months commencing on the first day of February, May, August and November. In turn, the Partnership distributed funds to its partners on the last business day of each calendar quarter. Cash distributions from the Trust, if any, were made in January, April, July and October of each year, and were payable to Unit holders of record as of the last business day of each calendar quarter. Thus, any cash conveyed to the Trust from the Royalty during the quarter ended December 31, 2016 would substantially represent the revenues and expenses from the Royalty Properties from August through October 2016. The financial and operating information included in this Form 10-K for the 12 months ended December 31, 2016, 2015 and 2014 primarily represents financial and operating information with respect to the Royalty Properties for the months of November 2015 through October 2016 and November 2014 through October 2015, and November 2013 through October 2014, respectively. Income from the Royalty is recorded by the Trust on a cash basis, when it is received by the Trust from the Partnership.

New Accounting Pronouncements

There were no accounting pronouncements issued during the year ended December 31, 2016 applicable to the Trust or its financial statements.

Critical Accounting Policies

Basis of Accounting: The Trust's financial statements are prepared on a modified cash basis, which is a comprehensive basis of accounting other than generally accepted accounting principles, or GAAP. This method of accounting is consistent with reporting of taxable income to the Unit holders. The most significant differences between the Trust's financial statements and those prepared in accordance with GAAP are:

(a): Royalty income from net profits interest was 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 included amounts related to funds deposited or released from the Special Cost Escrow account—see (c);
(b): Trust general and administrative expenses (which include the Trustee's fees as well as accounting, engineering, legal, and other professional fees) are recorded when paid by the Trust rather than when incurred;
(c): Cash reserves for Trust expenses may be established by the Trustee for certain expenditures that would not be recorded as contingent liabilities under GAAP;
(d): The funds deposited or released from the Special Cost Escrow account were 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; and
(e): Amortization of the investment in overriding royalty interest was calculated based on the units-of-production method. Such amortization was charged directly to Trust corpus and did not affect distributable income.
(f): Proceeds from loans used to pay for Trust expenses is charged directly to Trust corpus (deficit).

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, was charged directly to Trust corpus since such amount did not affect

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distributable income. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission, as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.

Liquidity and Capital Resources

Source of Liquidity and Capital

Prior to the 2016 Royalty Sale, the Trust's primary source of liquidity and capital had been the Royalty income received from its share of the Net Proceeds from the Royalty Properties. Due to the effective time of the 2016 Royalty Sale, the Trust no longer had any interest in, or any financial results attributable to, the Royalty or the Royalty Properties as of February 1, 2016.

During the first quarter of 2016, the Trust received Royalty income of $713 attributable to Eugene Island 342 and in the fourth quarter of 2015, the Trust received $1,316 of Royalty income attributable to Eugene Island 342. The Trust had not received any distributions of Net Proceeds from Chevron, as operator of the Royalty Properties, since December 2008. On April 15, 2016, but effective as of August 1, 2015, Chevron completed the Cox Oil Sale pursuant to which it conveyed certain oil and gas properties to Cox Oil, including Chevron's interest in Ship Shoal 182/183 that was subject to the Royalty. The Net Proceeds from Cox Oil attributable to Ship Shoal 182/183 were not subject to offset by Chevron against the undistributed net loss carry forward attributable to the Royalty Properties held by Chevron. As a result of the August 1, 2015 effective time and the Ship Shoal 182/183 properties not being subject to the undistributed net loss carry forward, the Trust received a distribution from Cox Oil of $116,429 in May 2016. The Trust has set aside the distribution received from Cox Oil pending the final resolution of the Remaining Matters. Distributions may be made from such segregated account for the payment of Trust expenses, which may include the payment of the Ad Litem's expenses, with the approval of the Court. Any final disposition of the remaining net proceeds to Unit holders will be made in accordance with the final resolution of the Remaining Matters. As a result of the 2016 Royalty Sale, the Trust will not receive any further Net Proceeds from the Royalty Properties.

Because of the lack of Net Proceeds, the Trust has in the past not had sufficient cash flow to pay expenses on a current basis and as described below, the Trust has been required to borrow funds and to cause the Partnership to sell part of the Original Royalty in order to pay Trust expenses. As of December 31, 2016, the Trust had no unrestricted cash. The Trustees have endeavored to cause the Trust to pay the administrative costs of the Trust in accordance with the Trust Agreement. There are no assurances that the Trust will be able to continue to pay its administrative expenses.

The Trust Agreement provides that, if necessary to provide for the payment of specific liabilities of the Trust then due, the Trustees may without a vote of the Unit holders (a) sell all or a portion of the Trust's interest in the Partnership or any other assets of the Trust for such cash consideration as the Trustees shall deem appropriate, (b) exercise their rights under the Partnership Agreement to dissolve the Partnership, or (c) cause a sale by the Partnership of the overriding royalty interest owned by the Partnership. Additionally, the Trustees, on behalf of the Trust, are authorized to borrow funds, and pledge the assets of the Trust to secure payments of such borrowings, in the event that cash on hand is not sufficient to pay the liabilities of the Trust. In the event that the Trustees borrow funds to pay the liabilities of the Trust, no distributions will be made to the Unit holders until the indebtedness created by such borrowings has been paid in full.

On May 23, 2013, the Corporate Trustee, on behalf of the Trust as borrower, executed a promissory note (the "2013 Note") for $300,000, which evidenced an extension of credit for borrowed money authorized under Section 6.08 of the Trust Agreement. The proceeds from the 2013 Note were used to pay expenses of the Trust. The outstanding indebtedness evidenced by the 2013 Note was paid by the Trust in November 2013 from proceeds of the 2013 Royalty Sale.

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On October 1, 2014, The Bank of New York Mellon Trust Company, N.A. made an advance to the Trust in the amount of $363,000, and the Corporate Trustee, on behalf of the Trust as the borrower, executed a Demand Promissory Note (the "2014 Note") relating to the unsecured $363,000 advance, which evidenced an extension of credit for borrowed money authorized under Section 6.08 of the Trust Agreement. The 2014 Note was mistakenly made payable to The Bank of New York Mellon ("BONYM"). In addition to the advances evidenced by the 2014 Note, The Bank of New York Mellon Trust Company, N.A. made additional cash advances in the amount of $209,885 to the Trust for the payment of its liabilities and expenses, primarily in connection with the Probate Proceeding. On September 25, 2015, The Bank of New York Mellon Trust Company, N.A. made an additional advance to the Trust in the amount of $484,000 and the Corporate Trustee, on behalf of the Trust as the borrower, executed a Renewal Demand Promissory Note (the "2015 Note") relating to (i) the unsecured $484,000 advance, (ii) the renewal and extension of the indebtedness originally evidenced by the 2014 Note in the original principal amount of $363,000, and (iii) previous advances in the amount of $209,885 made by The Bank of New York Mellon Trust Company, N.A. on behalf of the Trust. The 2015 Note provides for interest at the rate of one-half percent (0.5%) per annum. The 2015 Note became due and payable on December 31, 2016 and remains outstanding. The 2015 Note was also mistakenly made payable to BONYM. The 2015 Note has been assigned to The Bank of New York Mellon Trust Company, N.A., the party that made the advances to the Trust. In addition to the indebtedness owing under the 2015 Note, the Trust has received through December 31, 2016 advances from The Bank of New York Mellon Trust Company, N.A. in the amount of $68,224 and on March 31, 2017, the Trust received an additional unsecured advance of $184,751.55 from The Bank of New York Mellon Trust Company, N.A. During the year ended December 31, 2016, a portion of the proceeds from the 2015 Note were used to pay Trust expenses. In addition, the Corporate Trustee has used the additional advances received in 2016 for the payment of its liabilities and expenses, primarily in connection with the Probate Proceeding. Although The Bank of New York Mellon Trust Company, N.A. has no obligation to do so, it is anticipated that The Bank of New York Mellon Trust Company, N.A. will continue to advance funds to the Trust for the payment of such expenses.

In September 2012, the Trustees unanimously determined to suspend future payments of fees to the Trustees effective as of the third quarter of 2012, until a date to be determined in the future by the Trustees. As of December 31, 2013, the amount of such fees was approximately $339,414. The suspended fees were paid in full by the Trust in January 2014 and are included within general and administrative expenses for the year ended December 31, 2014.

On October 31, 2013, the Trust issued a press release announcing that the Partnership had consummated the 2013 Royalty Sale, which generated $1,200,000 in gross proceeds and occurred as part of a formal auction process for the Partnership's remaining overriding royalty interest in the Royalty Properties. The Trust received from the Partnership a distribution of approximately $1,151,885, representing 99.99% of the net proceeds from the sale of $1,152,000. The Trust used approximately $300,000 of the net proceeds received in October 2013 to repay the Trust's indebtedness under the 2013 Note and used the remaining net proceeds solely for the payment of expenses of the Trust.

Following the 2013 Royalty Sale, the Partnership's remaining interest in the Original Royalty entitled the Trust to its share (99.99%) of 60% of 25% of the Net Proceeds attributable to the Royalty Properties. The Conveyance, dated January 1, 1983, provides that the Working Interest Owners will calculate, for each period of three months commencing the first day of February, May, August and November, an amount equal to 25% of the Net Proceeds from their oil and gas properties for the period. Generally, "Net Proceeds" means the amounts received by the Working Interest Owners from the sale of minerals from the Royalty Properties less operating and capital costs incurred, management fees and expense reimbursements owing to the Managing General Partner of the Partnership, applicable taxes other than income taxes, and the Special Cost Escrow account. The Special Cost Escrow account was established for the future costs to be incurred to plug and abandon wells, dismantle and remove platforms, pipelines and

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other production facilities, and for the estimated amount of future capital expenditures on the Royalty Properties. Net Proceeds did 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 were extinguished or repaid through the future delivery of gas.

In March 2014, the Trustees again unanimously determined to suspend future payments of fees to the Trustees effective as of January 1, 2014, until a date to be determined in the future by the Trustees. As of December 31, 2016, the accumulated amount of such suspended fees was approximately $622,075 in the aggregate. The cumulative suspended fees will be recorded as an expense of the Trust when invoiced by the Trustees and paid.

On May 13, 2015, Chevron conveyed certain oil and gas properties to Fieldwood Energy Offshore LLC ("Fieldwood"), including Chevron's interest in Eugene Island 342 that is subject to the Royalty. Any Net Proceeds from Fieldwood attributable to Eugene Island 342 were not subject to offset by Chevron against the undistributed net loss carry forward attributable to the Royalty Properties held by Chevron. Consequently, during the fourth quarter of 2015 the Trust received Royalty income of $1,316 attributable to Eugene Island 342.

On June 27, 2016, the Trust issued a press release announcing that the Partnership had, in connection with the Probate Proceeding, consummated the sale of all of its remaining interest in the Original Royalty (60% or 15% of 8/8ths) (the "2016 Royalty Sale," and together with the 2011 Royalty Sale and the 2013 Royalty Sale, the "Royalty Sales"). The 2016 Royalty Sale was made to Arena Energy, LP and closed on June 24, 2016, but was effective as of February 1, 2016. The 2016 Royalty Sale generated $1,830,000 in gross proceeds and occurred as part of the previously announced formal auction process for the overriding royalty interest. The Trust received a distribution of approximately $1,756.624, representing 99.99% of the net proceeds from the Royalty Sale of $1,756,800.

As a result of the 2016 Royalty Sale, the Trust no longer owns any interest in the Royalty and therefore will not receive any further distributions of Net Proceeds. Because of the Remaining Matters in the Probate Proceeding, the Trust must hold the remaining proceeds from the 2016 Royalty Sale in a segregated account until the final resolution of the Remaining Matters. In addition, the Trust has set aside the distributions received from Cox Oil described above until the final resolution of the Remaining Matters. Distributions may be made from such segregated account for the payment of Trust expenses, which may include the payment of the Ad Litem's expenses, with the approval of the Court. Any final disposition of the remaining net proceeds to Unit holders will be made in accordance with the final resolution of the Remaining Matters.

The accompanying financial statements have been prepared assuming that the Trust will continue as a going concern. Financial statements prepared on the going concern basis assume the realization of assets and the settlement of liabilities in the normal course of business. Because of the 2016 Royalty Sale, the Trust will not receive any further Net Proceeds from the Royalty Properties. Approximately $421,917 of the net proceeds from the 2016 Royalty have been used to pay certain expenses of the ad litem in the Probate Proceeding. The Trust currently holds the remaining proceeds from the 2016 Royalty Sale and remaining distributions received from Cox Oil, which continue to be available for the payment of certain expenses of the ad litem in the Probate Proceeding. The Trust will not make any distribution of these funds to Unit holders until it receives a subsequent order from the Court or the Remaining Matters are otherwise settled. The lack of Net Proceeds and the inability to maintain adequate cash reserves raise substantial doubt about the Trust's ability to continue as a going concern. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

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.

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Years 2016 and 2015

Royalty Trust Comparison

Royalty income was $1,316 in 2015 and $117,353 in 2016. Gross proceeds for the underlying Royalty Properties operated by Chevron exceeded development and production costs for the period from November 2015 through February 1, 2016 by $1,094,037, or $273,509 attributable to the entire Original Royalty and $164,105 attributable to the Trust. The Net Proceeds were applied to reduce the accumulated excess cost carry forward, which represent the amount by which the aggregate development and production costs for the Royalty Properties since November 2008 have exceeded the related proceeds of the production, and as a result these Net Proceeds were not included in royalty income from the year ended December 31, 2016. In comparison, gross proceeds for the underlying Royalty Properties operated by Chevron exceeded development and production costs for the period from November 2014 through October 2015 by $5,129,150, or $1,282,288 attributable to the entire Original Royalty and $769,372 attributable to the Trust.

General and administrative expenses for the Trust were $811,570 for 2016 compared to $504,012 for 2015. The increase is due, in part, to the costs associated with the Probate Proceeding.

The reserve for future Trust expenses was $0 as of December 31, 2016 and December 31, 2015.

There was no distributable income for 2016 and therefore no distributions to Unit holders.

For 2016, the Trust had undistributed net income of $164,105, representing the Trust's portion of the undistributed net income of $1,094,037 associated with the Royalty Properties for 2016. For 2015, the Trust had undistributed net income of $769,372, representing the Trust's portion of the undistributed net income of $5,129,150 associated with the Royalty Properties for 2015. The undistributed net income was applied to reduce the accumulated excess cost carry forward. Undistributed net loss represents the amount of development and production costs associated with the Royalty that exceed the proceeds of production from the Royalty Properties during the period. An undistributed net loss was carried forward and offset, in future periods, by positive proceeds earned by the related Working Interest Owner(s).

Underlying Properties Comparison

The following financial and operational information has been based on information provided to the Corporate Trustee by the Managing General Partner. The Trustees had no control over these operations or internal controls relating to this information. Decreases in revenues and production for the year ended December 31, 2016 are all primarily attributable to the February 1, 2016 effective time for the 2016 Royalty Sale.

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 decreased approximately 87% from $625,021 in 2015 to $81,116 in 2016. Natural gas volumes decreased approximately 77.2% from 192,612 Mcf in 2015 to 43,878 Mcf in 2016. Excluding the impact of prior period adjustments, the average price received for natural gas decreased approximately 51% from an average price of $3.18 per Mcf in 2015 to $1.50 per Mcf in 2016. Gas product revenues decreased $50,658 to $23,137 in 2016 from $73,795 in 2015. Gas product volumes decreased 135,307 gallons to 62,956 gallons in 2016 from 198,263 gallons in the prior year.

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Crude Oil and Condensate

Crude oil and condensate revenues decreased 78% from $8,211,404 in 2015 to $1,777,748 in 2016. Oil volumes decreased 68% from 141,396 barrels in 2015 to 45,320 barrels in 2016. Excluding the impact of prior period adjustments, the average price received for crude oil and condensate decreased 34% from $59.49 per barrel in 2015 to $39.23 per barrel in 2016.

Operating and Capital Expenditures

Operating expenses paid by the Working Interest Owners decreased 79% from $3,780,112 in 2015 to $779,572 in 2016. Reflected within the operating expenses are management fees to Chevron, as Managing General Partner of the Partnership, of $369,392 and $77,628 for 2015 and 2016, respectively.

Capital expenditures paid by the Working Interest Owners decreased 100% from $959 in 2015 to $0 in 2016.

Summary By Property

Listed below is a summary of 2016 operations as compared to 2015 of the principal Royalty Properties based on gross revenues generated during these periods combined. Decreases in revenues and production for the year ended December 31, 2016 are all primarily attributable to the February 1, 2016 effective time for the 2016 Royalty Sale.

Eugene Island 339

Eugene Island 339 crude oil revenues decreased from $2,230,343 in 2015 to $662,064 in 2016. The average crude oil price received decreased from $56.67 per barrel in 2015 to $36.83 per barrel in 2016. Gas revenues were $92,131 in 2015 and $58,949 in 2016. Gas production was 25,478 Mcf in 2015, compared to 27,145 Mcf in 2016. Capital expenditures were $0 in 2015 and 2016. Operating expenses decreased from $145,395 in 2015 to $23,078 in 2015 due primarily to decreased maintenance costs in 2016 as compared to 2015.

Ship Shoal 182/183

Ship Shoal 182/183 crude oil revenues decreased from $6,099,010 in 2015 to $1,090,667 in 2016. The average crude oil prices received also decreased from $60.07 per barrel in 2015 to $40.84 per barrel in 2016. Gas revenues decreased from $498,224 in 2015 to $20,547 in 2016. The average natural gas sales price decreased from $3.15 per Mcf in 2015 to $1.29 in 2016. Gas production decreased from 158,269 Mcf in 2015 to 15,895 Mcf in 2016. Capital expenditures decreased from a balance of $1,091 in 2015 to $0 in 2016. Operating expenses decreased from $2,407,955 in 2015 to $676,682 in 2016.

South Timbalier 36/37

South Timbalier 36/37 oil revenues decreased from $208,007 in 2015 to $20,407 in 2016. The average crude oil price received also decreased from $61.93 per barrel in 2015 compared to $39.58 per barrel in 2016. Gas revenues decreased from $12,181 in 2015 to $1,553 in 2016 due primarily to a decrease in natural gas volumes from 4,468 Mcf in 2015 to 783 Mcf in 2016. The average gas sales price realized also decreased from $2.73 per Mcf in 2015 to $1.98 per Mcf in 2016. Capital expenditures increased from a benefit of $131 in 2015 to $0 in 2016 due to the sale of some materials at South Timbalier 36/37 during 2015. Operating expenses decreased from $51,348 in 2015 to $10,577 in 2016.

Eugene Island 342

Net crude oil revenues attributable to Eugene Island 342 while operated by Chevron increased from a negative $325,956 in 2015 to $4,610 in 2016. This increase primarily due to prior period adjustments in net crude oil production from a negative 2,860 barrels in 2015 to 123 barrels in the first

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nine months of 2016. Gas revenues attributable to Eugene Island 342 while operated by Chevron were $66 and gas production was 56 Mcf in 2016 compared to gas revenues of $22,486 and gas production was 4,396 in 2015, including a prior period adjustment of 1,036 Mcf. As the underlying interest in Eugene Island 342 is an overriding royalty interest, there were no capital or operating expenses recorded in 2015 and 2016.

Years 2015 and 2014

Royalty Trust Comparison

Royalty income was $0 in 2014 and $1,316 in 2015. Gross proceeds for the underlying Royalty Properties operated by Chevron exceeded development and production costs for the months November 2014 through October 2015 by $5,129,150, or $1,282,288 attributable to the entire Original Royalty and $769,372 attributable to the Trust. The Net Proceeds were applied to reduce the accumulated excess cost carry forward, which represents the amount by which the aggregate development and production costs for the Royalty Properties since November 2008 have exceeded the related proceeds of the production, and as a result these Net Proceeds were not included in royalty income from the year ended December 31, 2015. In comparison, gross proceeds for the underlying Royalty Properties operated by Chevron exceeded development and production costs for the months November 2013 through October 2014 by $8,673,674, or $2,168,418 attributable to the entire Original Royalty, and $1,301,050 attributable to the Trust.

General and administrative expenses for the Trust were $504,012 for 2015 compared to $1,109,000 for 2014. The decrease is primarily due to the $339,414 payment of the suspended Trustees' fees paid in January 2014 and a decrease of $161,731 in the costs associated with the Probate Proceeding.

The reserve for future Trust expenses was $0 as of December 31, 2015 and December 31, 2014.

There was no distributable income for 2015 and therefore no distributions to Unit holders.

For 2015, the Trust had undistributed net income of $769,372, representing the Trust's portion of the undistributed net income of $5,129,150 associated with the Royalty Properties for 2015. For 2014, the Trust had undistributed net income of $1,301,050, representing the Trust's portion of the undistributed net income of $8,673,674 associated with the Royalty Properties for 2014. Undistributed net loss represents the amount of development and production costs associated with the Royalty that exceed the proceeds of production from the Royalty Properties during the period. An undistributed net loss was carried forward and offset, in future periods, by positive proceeds earned by the related Working Interest Owner(s).

As of December 31, 2015, the cumulative undistributed net loss for the Trust was $0.9 million, compared to $1.7 million as of December 31, 2014.

Underlying Properties Comparison

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 decreased approximately 30% from $897,491 in 2014 to $625,021 in 2015. The reduction is the result of a decline in production and a reduction in natural gas prices. Natural gas volumes decreased approximately 1.4% from 195,278 Mcf in 2014 to 192,612 Mcf in 2015. Excluding the impact of prior period adjustments, the average price received for natural gas decreased approximately 31% from an average price of $4.63 per Mcf in 2014 to $3.18 per Mcf in 2015. Gas product revenues decreased $145,912 to $73,795 in 2015 from $219,707 in 2014. Gas product volumes decreased 44,810 gallons to 198,263 gallons in 2015 from 243,073 gallons in the prior year.

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Crude Oil and Condensate

Crude oil and condensate revenues decreased 40% from $13,711,705 in 2014 to $8,211,404 in 2015. The reduction is primarily the result of a decrease in commodity prices. Oil volumes increased 3.7% from 136,138 barrels in 2014 to 141,396 barrels in 2015. The increase in volumes is due primarily to the increase in production for Eugene Island 339. Excluding the impact of prior period adjustments, the average price received for crude oil and condensate decreased 41% from $100.72 per barrel in 2014 to $59.49 per barrel in 2015.

Operating and Capital Expenditures

Operating expenses paid by the Working Interest Owners decreased 37% from $5,979,666 in 2014 to $3,780,112 in 2015, due primarily to a decrease in maintenance projects at Ship Shoal 182/183. Reflected within the operating expenses are management fees to Chevron, as Managing General Partner of the Partnership, of $611,188 and $ 369,392 for 2014 and 2015, respectively.

Capital expenditures paid by the Working Interest Owners decreased 99% from $175,564 in 2014 to $959 in 2015. The decrease was primarily related to reduced capital project activity in 2015, as compared to facility improvement projects at Ship Shoal 182/183 during 2014.

Summary By Property

Listed below is a summary of 2015 operations as compared to 2014 of the principal Royalty Properties based on gross revenues generated during these periods combined.

Eugene Island 339

Eugene Island 339 crude oil revenues decreased from $3,088,565 to $2,230,343 in 2015. The decrease in crude oil revenues was primarily due to a decrease in the average crude oil price received from $97.46 per barrel in 2014 to $56.67 per barrel in 2015. This decrease was partially offset by an increase in crude oil production from 31,689 barrels in 2014 to 39,360 barrels in 2015. Production at one well on Eugene Island 339 commenced in December 2012, a second well in March 2013 and a third well in May 2013. A fourth well was completed in 2014 and is also included in the results for 2014 and 2015. Gas revenues were $167,092 in 2014 and $92,131 in 2015. Gas production was 35,671 Mcf in 2014, compared to 25,478 Mcf in 2015. Capital expenditures were $0 in 2014 and 2015. Operating expenses increased from $107,832 in 2014 to $145,395 in 2015 due primarily to increased maintenance costs in 2015.

Ship Shoal 182/183

Ship Shoal 182/183 crude oil revenues decreased from $10,083,463 in 2014 to $6,099,010 in 2015, primarily due to a decrease in average crude oil prices received from $101.79 per barrel in 2014 to $60.07 per barrel in 2015. This decrease was partially offset by an increase in net crude oil production from 99,063 barrels in 2014 to 101,537 barrels in 2015. The increase in volumes was primarily due to multiple shut ins for facility improvement projects during 2014. Gas revenues decreased from $682,704 in 2014 to $498,224 in 2015. The average natural gas sales price decreased from $4.64 per Mcf in 2014 to $3.15 in 2015. Gas production increased from 147,039 Mcf in 2014 to 158,269 Mcf in 2015 partially due to multiple shut ins for facility improvement projects during 2014. Capital expenditures decreased from a balance of $171,767 in 2014 to $1,091 in 2015 as a result of the costs associated with the facility improvement projects in 2014. Operating expenses decreased from $5,192,296 in 2014 to $2,407,955 in 2015 primarily due to several maintenance projects during 2014.

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South Timbalier 36/37

South Timbalier 36/37 oil revenues decreased from $409,647 in 2014 to $208,007 in 2015 due to a decrease in average price received and a decrease in crude oil production. The average crude oil price was $99.77 per barrel in 2014 compared to $61.93 per barrel in 2015. Crude oil production decreased from 4,106 barrels in 2014 to 3,359 barrels in 2015. Gas revenues decreased from $29,226 in 2014 to $12,181 in 2015 due primarily to a decrease in natural gas volumes from 10,029 Mcf in 2014 to 4,468 Mcf in 2015. The average gas sales price realized also decreased from $2.91 per Mcf in 2014 to $2.73 per Mcf in 2015. Capital expenditures decreased from $3,797 in 2014 to a benefit of $131 in 2015 due primarily to the sale of some materials at South Timbalier 36/37 during 2015. Operating expenses decreased from $68,350 in 2014 to $51,348 in 2015 due to higher maintenance repairs conducted during 2014.

Eugene Island 342

Net crude oil revenues attributable to Eugene Island 342 while operated by Chevron decreased from $130,031 in 2014 to negative $325,956 in 2015. This decrease is primarily due to prior period adjustments in net crude oil production from 1,282 barrels in 2014 to negative 2,860 barrels in 2015. Gas revenues attributable to Eugene Island 342 while operated by Chevron were $22,486 and gas production was 4,396 in 2015, including a prior period adjustment of 1,036 Mcf, compared to gas revenues of $18,470 and gas production of 2,540 Mcf in 2014. As the underlying interest in Eugene Island 342 is an overriding royalty interest, there were no capital or operating expenses recorded in 2014 and 2015.

Production and Price Review

The following schedule provides a summary of the volumes and weighted average prices, excluding adjustments, 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.

	Royalty Properties Year Ended December 31,(1)

	2016			2015			2014
Crude oil and condensate (bbls)		45,320			141,396			136,141
Natural gas and gas products (Mcfe)		43,878			225,656			235,790
Crude oil and condensate average price, per bbl	$	39.23		$	58.07		$	100.72
Natural gas average price, per Mcf (excluding gas products)	$	1.85		$	3.25		$	4.63
Crude oil and condensate revenues	$	1,777,748		$	8,211,404		$	13,711,706
Natural gas and gas products revenues	$	81,116		$	698,816		$	1,117,198
Interest		0			0			0
Production expenses		(779,572	)		(3,780,112	)		(5,979,666	)
Capital expenditures		(—	)		(959	)		(175,564	)
Undistributed Net Loss (income)(2)	$	(1,094,037	)	$	(5,129,150	)	$	(8,673,674	)
Refund of/(Provision for) Special Cost Escrow	$	—		$	—		$	—
Net Proceeds	$	—		$	2,194		$	—
Royalty interest(3)		—			x15	%		x15	%
Partnership share	$	—		$	—		$	—
Trust interest		x99.99	%		x99.99	%		x99.99	%
Trust share of Royalty Income(4)	$	—		$	1,316		$	—

(1): Amounts for 2016 represent actual production for the 3-month period ended January 31, 2016. Amounts for 2015 and 2014 represent actual production for the 12-month period ended on October 31 of each year, respectively.

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(2): Undistributed net loss represented the amount of development and production costs associated with the Royalty that exceeded the proceeds of production from the Royalty Properties during the period. An undistributed net loss was carried forward and offset, in future periods, by positive proceeds earned by the related Working Interest Owner(s). Undistributed net income represented positive Net Proceeds, generated during the respective period, but not distributed by the Working Interest Owners.
(3): As a result of the 2016 Royalty Sale, the Royalty interest was reduced from 15% to zero.
(4): See "Trustee's Discussion and Analysis of Financial Condition and Results of Operation—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. The Trust has not guaranteed the debt of any other party, nor does the Trust have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt, losses or contingent obligations.

Contractual Obligations

As of December 31, 2016, the Trust had no obligations or commitments to make future contractual obligations except for (i) indebtedness of $1,125,109 owing for the previous advances made by The Bank of New York Mellon Trust Company, N.A., together with accrued and unpaid indebtedness, and (ii) annual administrative fees of approximately $622,075 owed to the Trustees pursuant to the Trust Agreement.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

The only assets of and sources of income to the Trust were cash and the Trust's interest in the Partnership, which was the holder of the Royalty prior to the effective time of the 2016 Royalty Sale. As a result, the Trust was exposed to market risk associated with the Royalty from fluctuations in oil and gas prices. Reference is also made to Item 1 of this Form 10-K.

The Trust has in the past borrowed, and is expected to continue to borrow, money to pay expenses of the Trust. As a result, the Trust is exposed to interest rate market risk associated with the money borrowed to pay expenses.

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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—modified cash basis of TEL Offshore Trust (the "Trust") as of December 31, 2016 and 2015, and the related statements of distributable income and changes in trust corpus—modified cash basis for each of the three years in the period ended December 31, 2016. 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. The Trust is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Trust's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by the 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 2 to the financial statements, these financial statements were prepared on the modified cash basis of accounting, which is a 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, 2016 and 2015, and its distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2016, on the basis of accounting described in Note 2 to the financial statements.

The accompanying financial statements have been prepared assuming that the Trust will continue as a going concern. As discussed in Note 2 to the financial statements, the Trust caused the TEL Offshore Trust Partnership to sell its remaining royalty in the underlying properties and the Trust will not be receiving further royalty income. The remaining available cash is restricted pending the outcome of the Probate Proceeding discussed in Notes 2 and 5. In addition, the Trust has an inability to maintain adequate cash reserves, which raises substantial doubt about its ability to continue as a going concern. The Trustees' plans concerning these matters are also discussed in Notes 5 and 9 to the financial statements. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ Deloitte & Touche LLP
Austin, Texas
April 17, 2017

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TEL OFFSHORE TRUST

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

	December 31,

	2016		2015
Assets
Cash and cash equivalents	$	0	$	328,040
Cash—Restricted		1,451,135		—
Net overriding royalty interest in oil and gas properties, net of accumulated amortization of $0 and $28,258,358 at December 31, 2016 and 2015, respectively		—		9,297

Total assets	$	1,451,135	$	337,337



Liabilities and Trust Corpus
Distribution payable to Unit holders	$	—	$	—
Cash advances	$	68,224	$	8,303
Account payable		—	$	878
Note payable		1,056,885		1,056,885
Reserve for future Trust expenses		—		—
Trust corpus (4,751,510 Units of beneficial interest authorized and outstanding at December 31, 2015 and 2014)		326,026		(728,729	)

Total liabilities and Trust corpus	$	1,451,135	$	337,337

STATEMENTS OF DISTRIBUTABLE INCOME

	Year Ended December 31,

	2016			2015			2014
Royalty income	$	117,353		$	1,316		$	—
Interest income		1,647			24			6
Proceeds from sale of overriding royalty interest		1,756,624			—			—

	$	1,875,624		$	1,340			6
Income withheld for future probate distribution		(1,874,698	)		—			—
Proceeds from Note and cash advances used for Trust expenses		388,727			502,672			235,354
Proceeds from sale used for Probate expenses		421,917			—			—
General and administrative expenses		(811,570	)		(504,012	)		(1,109,000	)
Decrease (Increase) in reserve for future Trust expenses		0			0			873,640

Distributable income	$	—		$	—		$	—



Distributions per Unit (4,751,510 Units)	$	0.000000		$	0.000000		$	0.000000

STATEMENTS OF CHANGES IN TRUST CORPUS

	Year Ended December 31,

	2016			2015			2014
Trust corpus, beginning of year	$	(728,729	)	$	(223,304	)	$	14,515
Distributable income		—			—			—
Distributions to Unit holders		—			—			—
Sales Proceeds		1,873,049			—			—
Proceeds from Note and cash advances used for Trust expenses		(388,727	)		(502,672	)		(235,354	)
Proceeds from sale used for Probate expenses		(421,917	)		—			—
Interest income		1,647			—			—
Amortization of net overriding royalty interest		(9,297	)		(2,753	)		(2,465	)

Trust corpus, end of year	$	326,026		$	(728,729	)	$	(223,304	)

The accompanying notes are an integral part of these financial statements.

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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 had initially owned a .01% interest. In general, the Plan was effected by transferring an overriding royalty interest equivalent to a 25% net profits interest (the "Original Royalty") 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 ("Units") in liquidation and cancellation of Tenneco Offshore's common stock. The term "Original Royalty" shall refer to the initial 25% net profits interest in the Royalty Properties and the term "Royalty" shall refer to the applicable net profits interest previously held from time to time by the Partnership following the Royalty Sales (as defined in Note 3 below).

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 (as amended, the "Trust Agreement"), 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, 2016 and 2015, the reserve amount was $0;

(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 (without considering any sales of the Royalty) or (ii) a decision to terminate the Trust by the affirmative vote of Unit holders representing a majority of the Units. However, as a result of the Probate Proceeding and the Remaining Matters (each as defined in Note 5), no termination of the Trust will occur until approved by the Court (as defined in Note 5).

On October 27, 2011, the Partnership sold 20% of the Royalty for gross proceeds of $1,600,000. See Note 3.

On October 31, 2013, the Partnership consummated the sale of 25% of its remaining interest in the Original Royalty (or 5% of 8/8ths) and following such sale now holds 60% of the Original Royalty interest (or 15% of 8/8ths). See Note 3.

On June 24, 2016, pursuant to the Probate Proceeding, the Partnership consummated the sale of all of its remaining interest in the Original Royalty (60% or 15% of 8/8ths). As a result of

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TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(1) Trust Organization and Provisions (Continued)

consummation of the sale, the Partnership no longer owns any overriding royalty interest in the Royalty Properties. See Note 3.

The Trust is currently administered by The Bank of New York Mellon Trust Company, N.A. (the "Corporate Trustee"), 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 Gary C. Evans, Thomas H. Owen, Jr. and Jeffrey S. Swanson ("Individual Trustees"), as trustees ("Trustees"). The Individual Trustees tendered their resignations on January 17, 2017 and such resignations will become effective on September 1, 2017, a date more than one hundred twenty days after the date upon which the Annual Report on Form 10-K for the year ended December 31, 2016 is mailed to the Trust's Unit holders.

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.

(2) Basis of Accounting and Going Concern

Overriding Royalty Interest—The Trust uses the modified cash basis of accounting to report Trust receipts from the overriding royalty and payments of expenses incurred. Actual cash distributions to the Trust were made based on the terms of the conveyance that created the Trust's overriding royalty interest. Prior to the Royalty Sales (as defined in Note 3), the overriding royalty interest entitled the Trust to receive revenues (oil, gas and natural gas liquid sales) less expenses (the amount by which all royalties, lease operating expenses including well workover costs, production and property taxes, post-production costs including plugging and abandonment, and producing overhead of the underlying properties) multiplied by the Partnership's interest in the Original Royalty. The Original Royalty initially represented a 25% net profits interest but after the Royalty Sales, the Partnership no longer owns any overriding royalty interest in the properties underlying the Royalty. Actual cash receipts would vary due to timing delays of cash receipts from the property operators or purchasers and due to wellhead and pipeline volume balancing agreements or practices.

Modified Cash Basis of Accounting—The financial statements of the Trust, as prepared on a modified cash basis, reflect the Trust's assets, liabilities, Trust corpus (deficit), earnings and distributions, as follows:

(a): Royalty income from the overriding royalty interest was 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 included amounts related to funds deposited or released from the Special Cost Escrow account—see (c);
(b): Trust general and administrative expenses (which include the Trustee's fees as well as accounting, engineering, legal, and other professional fees) are recorded when paid by the Trust rather than when incurred;

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TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(2) Basis of Accounting and Going Concern (Continued)

(c): Cash reserves for Trust expenses may be established by the Trustee for certain expenditures that would not be recorded as contingent liabilities under generally accepted accounting principles, or GAAP;
(d): The funds deposited or released from the Special Cost Escrow account were 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; and
(e): Amortization of the investment in overriding royalty interest was calculated based on the units-of-production method. Such amortization was charged directly to Trust corpus and did not affect distributable income.
(f): Proceeds from loans used to pay for Trust expenses is charged directly to Trust corpus (deficit).

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 GAAP, 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. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission, as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.

Oil and Gas Reserves. The proved oil and gas reserves for the underlying properties are estimated by independent petroleum engineers. Reserve engineering is a subjective process that is dependent upon the quality of available data and the interpretation thereof. Estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices and production costs, may justify revision of such estimates. Accordingly, oil and gas quantities ultimately recovered and the timing of production may be substantially different from estimates.

The standardized measure of discounted future net cash flows is prepared using assumptions made pursuant to FASB and SEC guidelines. Such assumptions include using average fiscal-year oil and gas prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month reporting period) and year-end costs for estimated future production expenditures. Discounted future net cash flows are calculated using a 10% discount rate. Changes in any of these assumptions could have a significant impact on the standardized measure. The standardized measure does not necessarily result in an estimate of the current fair market value of proved reserves.

Amortization of Overriding Royalty Interest. The Trust amortized the investment in overriding royalty interest using the units-of-production method. The Trust's rate of recording amortization was dependent upon the estimates of total proved reserves, which incorporated various assumptions and future projections. If the estimates of total proved reserves declined significantly, the rate at which the

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TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(2) Basis of Accounting and Going Concern (Continued)

Trust recorded amortization expense would have increased, reducing Trust corpus. As a result of the 2016 Royalty Sale, the Trust no longer holds any investment in the overriding royalty interest and there will be no further amortization.

Impairment of Investment in Overriding Royalty Interest. The Trust reviewed net overriding royalty interests in oil and gas properties for possible impairment whenever events or circumstances indicated the carrying amount of the asset may not be recoverable. If there was an indication of impairment, the Trust prepared 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 were less than the carrying amount of the asset, an impairment loss was 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.

Cash and Cash Equivalents: Cash and cash equivalents include all highly liquid short-term investments with original maturities of three months or less.

Restricted Cash. Restricted cash reported on the Statement of Assets, Liabilities and Trust Corpus consists of (i) proceeds received by the Trust from the 2016 Royalty Sale and (ii) the distribution received by the Trust as a result of the Cox Oil Sale (as defined below). The proceeds from the 2016 Royalty Sale are required to be held in a segregated account pending resolution of the Probate Proceeding (as defined in Note 5). The distribution received in connection with the Cox Oil Sale is also being withheld by the Trust pending resolution of the Probate Proceeding.

Reserve for future Trust expenses: Represents cash reserves for future Trust expenses established by Trustee. 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. See Note 5.

Proceeds from Sale of Overriding Royalty: The Trust recorded proceeds from the sale of overriding royalty interests when received.

Use of Estimates. 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.

Recent Accounting Pronouncements. There were no accounting pronouncements issued during the year ended December 31, 2016 applicable to the Trust or its financial statements.

Going Concern. The accompanying financial statements have been prepared assuming that the Trust will continue as a going concern. Financial statements prepared on the going concern basis assume the realization of assets and the settlement of liabilities in the normal course of business. During the first quarter of 2016, the Trust received $713 in Royalty income from Fieldwood Energy Offshore LLC ("Fieldwood"), the operator of Eugene Island 342. In addition, as a result of the sale by Chevron of its interest in Ship Shoal 182/183 effective August 1, 2015 to Cox Oil Offshore, L.L.C. ("Cox Oil"), the Trust received a distribution of $116,429 in May 2016. As a result of the Partnership's sale of the remaining Royalty in the 2016 Royalty Sale (as defined in Note 3 below), the Trust will not be receiving any further Royalty income. The proceeds from such sale are required to be held in a

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TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(2) Basis of Accounting and Going Concern (Continued)

segregated interest bearing account, which is presented as Cash-Restricted in the Statements of Assets, Liabilities and Trust Corpus, pending a subsequent court order from the Court. The proceeds from the 2016 Royalty Sale and distribution from Cox Oil are, subject to approval of the Court, available for costs and expenses of the Trust as well as to pay certain expenses of the Ad Litem in the Probate Proceeding. The Trust will not make any distribution of the remaining proceeds from the 2016 Royalty Sale to Unit holders until it receives a subsequent order from the Court or the Remaining Matters are otherwise settled. The lack of Net Proceeds and the inability to maintain adequate cash reserves raise substantial doubt about the Trust's ability to continue as a going concern within one year after the date the financial statements are issued. The financial statements do not include any adjustments that might result from the outcome of the Probate Proceeding.

(3) Net Overriding Royalty Interest

The Original Royalty entitled 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 quarterly period commencing the first day of February, May, August and November, an amount equal to 25% of the Net Proceeds from their oil and gas properties for the period. "Net Proceeds" means for each quarterly period, the amount 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 was 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 did 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 were extinguished or repaid through the future delivery of gas.

On October 27, 2011, the Trust issued a press release announcing that the Partnership had consummated the sale (the "2011 Royalty Sale") of 20% of the Original Royalty (or 5% of 8/8ths). The 2011 Royalty Sale was made to RNR Production on October 27, 2011, though the assignment was effective as of August 1, 2011.

On October 31, 2013, the Trust issued a press release announcing that the Partnership had consummated the sale (the "2013 Royalty Sale") of 25% of its remaining interest in the Original Royalty (or 5% of 8/8ths). The 2013 Royalty Sale to RNR Production closed on October 31, 2013, though the assignment was effective as of August 1, 2013.

On June 27, 2016, the Trust issued a press release announcing that the Partnership had, pursuant to the Probate Proceeding consummated the sale (the "2016 Royalty Sale" and, together with the 2011 Royalty Sale and the 2013 Royalty Sale, the "Royalty Sales") of all of its remaining interest in the Original Royalty (60% or 15% of 8/8ths). As a result of consummation of the 2016 Royalty Sale, the Partnership no longer owns any Royalty in the Royalty Properties. The 2016 Royalty Sale was made to Arena Energy, LP and closed on June 24, 2016, but was effective as of February 1, 2016. The 2016 Royalty Sale generated $1,830,000 in gross proceeds and occurred as part of the previously announced formal auction process for the overriding royalty interest. The Trust received a distribution of

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TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(3) Net Overriding Royalty Interest (Continued)

approximately $1,756,624, representing 99.99% of the net proceeds from the Royalty Sale of $1,756,800 in July 2016.

(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. A Quarterly Period is each period of three months commencing on the first day of February, May, August and November. Cash distributions from the Trust, if any, were made in January, April, July and October of each year, and were payable to Unit holders of record as of the last business day of each calendar quarter. Income received pursuant to the Partnership's overriding royalty interest was recorded by the Trust on a cash basis, when it was received by the Trust from the Partnership.

As a result of the 2016 Royalty Sale, the Trust no longer owns any interest in the Royalty and therefore will not receive any further distributions of Net Proceeds. Because of the Remaining Matters in the Probate Proceeding, the Trust must hold the remaining proceeds from the 2016 Royalty Sale in a segregated account until the final resolution of the Remaining Matters. In addition, the Trust has set aside the distribution received from Cox Oil until the final resolution of the Remaining Matters. Distributions may be made from such segregated account for the payment of Trust expenses, which may include the payment of the Ad Litem's expenses, with the approval of the Court. Any final disposition of the remaining net proceeds to Unit holders will be made in accordance with the final resolution of the Remaining Matters.

For 2015, the Trust had undistributed net income of $769,372, representing the Trust's portion of the undistributed net income of $5,129,150 associated with the Royalty Properties for 2015. Undistributed net income represents positive Net Proceeds, generated during the respective period, but not distributed by the Working Interest Owners.

For 2014, the Trust had undistributed net income of $1,301,050, representing the Trust's portion of the undistributed net income of $8,673,674 associated with the Royalty Properties for 2014. Undistributed net income represents positive Net Proceeds, generated during the respective period, but not distributed by the Working Interest Owners.

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TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(5) Reserve For Future Trust Expenses

Historically, the Trust generally maintained a cash reserve, equal to approximately three times the average annual expenses of the Trust during each of the then past three years, to provide for future administrative expenses in connection with the winding up of the Trust. However, as a result of the damage inflicted upon certain of the Royalty Properties by Hurricane Ike in September 2008, the Trust has not received sufficient Net Proceeds to maintain the reserve at such level. As of December 31, 2016 and December 31, 2015, the reserve amount was $0.

During the fourth quarter of 2015, the Trust received $1,316 in distributions from Fieldwood, the operator of Eugene Island 342, however, the Trust has not received a distribution of Net Proceeds from Chevron, as operator of the Royalty Properties, since December 2008. During the first quarter of 2016, the Trust received Royalty income of $713 attributable to Eugene Island 342. As a result of the sale of the Ship Shoal 182/183 properties to Cox Oil, the Trust received a distribution from Cox Oil of $116,429 in May 2016. The Trust also received net proceeds of $1,756,624 from the 2016 Royalty Sale; however, the net proceeds from the 2016 Royalty Sale are not available to the Trust, without Court approval, for the payment of costs and expenses pending the resolution of the Probate Proceeding. In addition, the remaining distribution from Cox Oil is also being separately withheld and is not available to the Trust, without Court approval, for the payment of costs and expenses pending the resolution of the Probable Proceeding. As a result of the 2016 Royalty Sale, the Trust will not receive any further Net Proceeds from the Royalty Properties. As of December 31, 2016, the Trust had no unrestricted cash. The Trustees will endeavor to cause the Trust to pay the administrative costs of the Trust in accordance with the Trust Agreement. There are no assurances that the Trust will be able to continue to pay its administrative expenses.

Pursuant to the terms of the Trust Agreement, the Trustees are authorized to borrow funds, and pledge the assets of the Trust to secure payments of such borrowings, in the event that cash on hand is not sufficient to pay the liabilities of the Trust. In the event that the Trustees borrow funds to pay the liabilities of the Trust, no distributions will be made to the Unit holders until the indebtedness created by such borrowings has been paid in full. As discussed in Note 9, the Trustees borrowed funds from which a portion of the proceeds were used to pay for Trust expenses.

The Trust Agreement further provides that, if necessary to provide for the payment of specific liabilities of the Trust then due, the Trustees may without a vote of the Unit holders (a) sell all or a portion of the Trust's interest in the Partnership or any other assets of the Trust for such cash consideration as the Trustees shall deem appropriate, (b) exercise their rights under the Partnership Agreement to dissolve the Partnership, or (c) cause a sale by the Partnership of the overriding royalty interest owned by the Partnership.

In March 2014, the Trustees unanimously determined to suspend future payments of fees to the Trustees effective as of January 1, 2014, until a date to be determined in the future by the Trustees. As of December 31, 2016, the amount of such fees was approximately $622,075 in the aggregate. Such suspended fees will be recorded as an expense of the Trust when invoiced by the Trustees and paid.

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TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(5) Reserve For Future Trust Expenses (Continued)

or any other assets of the Trust, (b) exercise their rights to dissolve the Partnership, or (c) cause the Partnership to sell the Royalty. The goals in filing such probate proceeding (the "Probate Proceeding") were to permit the Trustees to direct the Partnership to sell the Royalty; to distribute the net proceeds resulting from such sale, after payment of the Trust's liabilities, to the Unit holders; and, to, thereafter terminate the Partnership and the Trust. The Trust has completed the process of serving the Petition on the Trust's Unit holders. The Court appointed Glenn M. Karisch, attorney ad litem for certain unit holders of the Trust (the "Ad Litem") to represent any Unit holders that were not personally served. The Ad Litem filed a Counterclaim against the Trust on November 16, 2015 requesting (1) an order to sell all of the Royalty, and (2) an accounting of the general and administrative expenses of the Trust from 2008 through the present.

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TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(5) Reserve For Future Trust Expenses (Continued)

beneficiaries. RNR Production Land and Cattle ("RNR") also filed its own petition on October 28, 2016, which asserted similar claims against the Trustees as the Ad Litem had asserted. Two other unitholders, Albert and Joyce Speisman ("Speismans" and, together with the Ad Litem and RNR, the "Plaintiffs") also filed a counterclaim on November 15, 2016, adopting the claims of the Realigned Petition.

Discovery is continuing in the Probate Proceeding. A pre-trail hearing is set for June 8, 2017 and the trial for the Remaining Matters is scheduled for June 12-30, 2017.

(6) Federal Income Tax Matters

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TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(7) Supplemental Reserve Information (Unaudited)

As of December 31, 2016, the Trust no longer held any interest in the Royalty or in the Royalty Properties. As disclosed in Note 3, the Royalty in which the Trust had an interest was sold effective February 1, 2016.

Estimates of the proved oil and gas reserves attributable to the Partnership's royalty interest as of December 31, 2015 and 2014 are based on a reserve study prepared by DeGolyer and MacNaughton, independent petroleum engineering consultants. The reserve study prepared by DeGolyer and MacNaughton as of October 31, 2015 includes projected reserves attributable to the wells drilled by Arena Energy, LP but did not include any capital expenditures for the redevelopment of Eugene Island 339. Estimates were prepared in accordance with guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board. Accordingly, the estimates were based on existing economic and operating conditions in effect at October 31, 2015, with no provision for future increases or decreases except for periodic price redeterminations in accordance with existing gas contracts.

Estimated net proved reserves attributable to the net profits interest owned by the Partnership, as of October 31, 2015, are summarized as follows, expressed in barrels (bbl) and thousands of cubic feet (Mcf):



Proved Developed Reserves(1)
Estimates	5,508		(40,691	)
Reserves as of October 31, 2014	55,121		422,816

Revisions of Previous Estimates	(16,534	)	(143,275	)
Production(2)	(12,965	)	(26,814	)

Reserves as of October 31, 2015	25,622		252,727

Revisions of Previous Estimates	(16,534	)	(143,275	)
Production(2)	(12,965	)	(26,814	)

(1): There were no proved undeveloped reserves for the Royalty Properties subject to the prior report.
(2): Production was estimated based on the ratio 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.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves were prepared in accordance with the provisions of FASB ASC Topic 932, Extractive Activities—Oil and Gas. Future cash inflows as of October 31, 2015 and 2014 were computed by applying average fiscal-year prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period ended October 31, 2015 and

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TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(7) Supplemental Reserve Information (Unaudited) (Continued)

2014) to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year end, based on year-end costs and assuming the continuation of existing economic conditions.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves attributable to the Trust as of December 31, 2015 and 2014 is as follows (dollars in thousands):

	Twelve Months Ended October 31,

	2015			2014
Future cash inflows	$	9,613		$	17,556
Future production costs		(4,578	)		(7,318	)
Cost Escrow as of October 31		1			1
Future development costs		(2,853	)		(2,934	)

Future net cash flows		2,183			7,305
10% annual discount for estimated timing of cash flows		(594	)		(1,662	)

Standardized measure of discounted future net cash flows(1)	$	1,589		$	5,643

(1): No provision for federal or state income taxes has been provided because taxable income is passed through to the Unit holders of the Trust.

The changes in standardized measure of discounted future net cash flows relating to proved oil and gas reserves attributable to the Trust as of December 31, 2015 and 2014 are as follows (dollars in thousands):

	Twelve Months Ended October 31,

	2015			2014
Beginning of year	$	5,643		$	6,112
Sale of oil and gas produced, net of production costs		(784	)		(1,574	)
Sale of minerals in place		—			—
Net changes in prices and production costs		(1,464	)		(29	)
Changes in estimated future development costs, net		(80	)		860
Revisions of previous quantity estimates		(2,065	)		(92	)
Accretion of discount		339			366

End of year	$	1,589		$	5,643

Future cash inflows included in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves incorporate unweighted arithmetic average sales prices (inclusive of adjustments for quality and location) in effect at October 31, 2015 and 2014 as follows:

	2015		2014

Oil (per Bbl)	$	53.89	$	99.59
Gas (per Mcf)	$	4.36	$	4.33

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TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(7) Supplemental Reserve Information (Unaudited) (Continued)

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. Chevron has completed the work associated with the wells on Eugene Island 339 and informed the Trust that the aggregate cost to the Original Royalty to plug and abandon the wells, remove and abandon platforms and infrastructure and remediate the surface subject to the overriding royalty interest on Eugene Island 339 was approximately $19.8 million and that no further expenses of this nature relating to prior hurricane damage are expected to be incurred. In December 2009, Chevron and Arena entered into the Arena Agreement, pursuant to which Arena could earn an assignment of 65% of Chevron's working interests in Eugene Island 338 and Eugene Island 339 following completion of certain drilling and development operations. Following completion of the first well on Eugene Island 339 by Arena and other drilling and development operations in the fourth quarter of 2012, Chevron assigned 65% of Chevron's working interests in Eugene Island 338 and Eugene Island 339 to Arena, effective as of December 15, 2009, the effective date of the Arena Agreement. In accordance with the Arena Agreement, the working interest assigned to Arena is not burdened by the Original Royalty, and the Royalty held by the Partnership with respect to such properties was reduced proportionately. As a result of such assignment, the Royalty held by the Partnership on Eugene Island 339 was reduced by 65%.

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 were estimated using an allocation of reserves based on estimates of future revenue, changes in prices or costs could result in changes in the estimated net reserves. Therefore, the estimated net reserves attributable to the Partnership's royalty interest as of December 31, 2015 and 2014 will vary if different future price and cost assumptions were used. All reserves attributable to the Partnership's royalty interest were located in the United States. Total future net revenues attributable to the Partnership's interest in the Royalty were estimated at $2.2 million as of October 31, 2015 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.

(8) Related Party Transactions

Each of the Working Interest Owners owned interests, for its own account, in leases that were in the same area as leases in which the Partnership had previously held an interest. Such relationships may have given 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

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TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(8) Related Party Transactions (Continued)

Owner for its own account. Additionally, the Working Interest Owners and their affiliates were not prohibited from purchasing oil and gas produced from or attributable to any leases in which the Partnership had an interest.

Crude oil sales to Chevron Corporation accounted for approximately 100% of crude oil revenues from the Royalty Properties during each of the years ended December 31, 2016, 2015 and 2014. During the year ended December 31, 2016, 2015 and 2014, 100% 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.

The Trust's share of Royalty income was reduced by approximately $11,644, $55,409 and $91,678 in 2016, 2015 and 2014, 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 each of the periods above.

(9) Note Payable and Cash Advances

On October 1, 2014, The Bank of New York Mellon Trust Company, N.A. made an advance to the Trust in the amount of $363,000, and the Corporate Trustee, on behalf of the Trust as the borrower, executed a Demand Promissory Note (the "2014 Note") relating to the unsecured $363,000 advance, which evidenced an extension of credit for borrowed money authorized under Section 6.08 of the Trust Agreement. The 2014 Note was mistakenly made payable to The Bank of New York Mellon ("BONYM"). In addition to the advances evidenced by the 2014 Note, The Bank of New York Mellon Trust Company, N.A. made additional cash advances in the amount of $209,885 to the Trust for the payment of its liabilities and expenses, primarily in connection with the Probate Proceeding. On September 25, 2015, The Bank of New York Mellon Trust Company, N.A. made an additional advance to the Trust in the amount of $484,000 and the Corporate Trustee, on behalf of the Trust as the borrower, executed a Renewal Demand Promissory Note (the "2015 Note") relating to (i) the unsecured $484,000 advance, (ii) the renewal and extension of the indebtedness originally evidenced by the 2014 Note in the original principal amount of $363,000, and (iii) previous advances in the amount of $209,885 made by The Bank of New York Mellon Trust Company, N.A. on behalf of the Trust. The 2015 Note provides for interest at the rate of one-half percent (0.5%) per annum. The 2015 Note became due and payable on December 31, 2016 and remains outstanding. The 2015 Note was also mistakenly made payable to BONYM. The 2015 Note has been assigned to The Bank of New York Mellon Trust Company, N.A., the party that has made the advances to the Trust. In addition to the indebtedness owing under the 2015 Note, the Trust has received through December 31, 2016 advances from The Bank of New York Mellon Trust Company, N.A. in the amount of $68,224 and on March 31, 2017 the Trust received an additional unsecured advance of $184,751.55 from The Bank of New York Mellon Trust Company, N.A. During the year ended December 31, 2016, a portion of the proceeds from the 2015 Note, were used to pay Trust expenses. In addition to the 2015 Note, the Corporate Trustee used the additional advances received in 2016 for the payment of its liabilities and expenses, primarily in connection with the Probate Proceeding. Although The Bank of New York Mellon Trust Company, N.A. has no obligation to do so, it is anticipated that The Bank of New York Mellon Trust Company, N.A. will continue to advance funds to the Trust for the payment of such expenses.

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TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(10) Selected Quarterly Financial Data (Unaudited)

Summarized quarterly financial data is as follows:

	First		Second		Third		Fourth

2016:
Royalty income	$	713	$	116,429	$	0	$	0
Distributable income	$	0	$	0	$	0	$	0
Distributions per Unit	$	0.000000	$	0.000000	$	0.000000	$	0.000000
2015:
Royalty income	$	0	$	0	$	0	$	1,316
Distributable income	$	0	$	0	$	0	$	0
Distributions per Unit	$	0.000000	$	0.000000	$	0.000000	$	0.000000

See Note 4 for a discussion regarding uncertainty of distributions.

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

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 of the 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" included in this Form 10-K and "Trustee'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

During the quarter ended December 31, 2016, there has been no change in the Trust's internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Trust's internal control over financial reporting relating to the Trust. The Corporate Trustee notes for purposes of clarification that it has no authority over, and makes no statement concerning, the internal control over financial reporting of Chevron.

Corporate Trustee's Annual 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 the modified cash basis of accounting. 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 the modified

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cash basis of accounting, 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 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 (2013) 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 (2013), the Corporate Trustee concluded that the Trust's internal control over financial reporting was effective as of December 31, 2016.

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.

Item 9B. Other Information.

None.

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PART III

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. The Individual Trustees tendered their resignations on January 17, 2017 and such resignations will become effective on September 1, 2017, a date more than one hundred twenty days after the date upon which this Form 10-K is mailed to the Trust's Unit holders.

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 of New York Mellon Trust Company, N.A.'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, a compensation committee 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 Corporate Trustee is not aware of any person having failed to file on a timely basis the reports required under Section 16(a) of the Securities Exchange Act of 1934 during the most recent fiscal year.

Item 11. Executive Compensation.

During the year ended December 31, 2016, the Corporate Trustee and each of the Individual Trustees received no compensation from the Trust. The Trust does not have any executive officers.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

(a) Security Ownership of Certain Beneficial Owners.

The following table sets forth certain information regarding the beneficial ownership of the Units as of March 30, 2017 by each person who, to the Trustees' knowledge, beneficially owns more than 5% of the outstanding Units.

Name and Address of Beneficial Owner	Title of Class

RNR Production, Land and Cattle Company, Inc.(1)(2)	Units of Beneficial Interest	730,265	15.4	%
Albert Speisman (3)(4)	Units of Beneficial Interest	492,306	10.36	%
Joyce E. Speisman (3)(5)	Units of Beneficial Interest	359,718	7.6	%

(1): Has a principal business address of 14531 Hwy 377 South, Fort Worth, TX 76126.
(2): This information has been derived from a Schedule 13D/A filed with the SEC on February 26, 2014. Based on the information contained in the filing, RNR Production, Land and Cattle Company, Inc., Roy T. Rimmer, Jr. and Nancy Rimmer have shared voting power and dispositive power with respect to, and beneficially own, an aggregate of 730,265 Units.
(3): Has a principal business address of P.O. Box 1878, Highland Park, IL 60035.

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(4): This information is derived from a Schedule 13G/A filed with the SEC on February 27, 2017. Based on the information contained in the filing, Albert Speisman has sole voting power and sole dispositive power in 464,206 Units and shared voting power and shared dispositive in 28,100 Units with the Albert Speisman as Trustee, Retirement Account for the benefit of Joyce E. Speisman.
(5): This information is derived from a Schedule 13G/A filed with the SEC on January 19, 2017. Based on the information contained in the filing, Joyce E. Speisman has sole voting power and sole dispositive power in 359,178 Units.

(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. Certain Relationships and Related Transactions, and Director Independence.

Each of the Working Interest Owners may own interests, for its own account, in leases that 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 100% of crude oil revenues from the Royalty Properties for each of the years ended December 31, 2016, 2015 and 2014. During the years ended December 31, 2016, 2015 and 2014, 100% 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.

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 and its affiliates (collectively "Deloitte") as the independent registered public accounting firm to audit the trust's financial statements for the fiscal year ending December 31, 2017. During fiscal 2016, Deloitte served as the Trust's independent registered public accounting firm and also provided certain tax services.

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The following table presents the aggregate fees billed to the Trust for the fiscal years ended December 31, 2016 and 2015 by Deloitte:

	2016		2015

Audit fees(1)	$	75,000	$	150,000
Audit-related fees		—		—
Tax fees(2)		8,320		8,000
All other fees		—		—

Total fees	$	83,320	$	158,000

(1): Fees for audit services in 2016 and 2015 consisted of the audit of the Trust's annual financial statements and reviews of the Trust's quarterly financial statements.
(2): Fees for tax services billed in 2016 and 2015 consisted of tax compliance services.

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PART IV

Item 15. Exhibits, Financial Statement Schedules.

(a)(1) Financial Statements

The following financial statements are set forth under Part II, Item 8 of this Form 10-K on the pages as indicated:

		Page in This Form 10-K

Report of Independent Registered Public Accounting Firm			30
Statements of Assets, Liabilities and Trust Corpus			31
Statements of Distributable Income			31
Statements of Changes in Trust Corpus			31
Notes to Financial Statements			32

(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.)



4(a	)*	Trust Agreement dated as of January 1, 1983, among Tenneco Offshore Company, Inc., Texas Commerce Bank National Association, as corporate trustee, and Horace C. Bailey, Joseph C. Broadus and F. Arnold Daum, as individual trustees (Exhibit 4(a) to Form 10-K for year ended December 31, 1992 of TEL Offshore Trust)	000-06910	4(a	)

4(b	)*	Agreement of General Partnership of TEL Offshore Trust Partnership between Tenneco Oil Company and the TEL Offshore Trust, dated January 1, 1983 (Exhibit 4(b) to Form 10-K for year ended December 31, 1992 of TEL Offshore Trust)	000-06910	4(b	)

4(c	)*	Conveyance of Overriding Royalty Interests from Exploration I to the Partnership (Exhibit 4(c) to Form 10-K for year ended December 31, 1992 of TEL Offshore Trust)	000-06910	4(c	)

4(d	)*	Amendments to TEL Offshore Trust Agreement, dated December 7, 1984 (Exhibit 4(d) to Form 10-K for year ended December 31, 1992 of TEL Offshore Trust)	000-06910	4(d	)

4(e	)*	Amendment to the Agreement of General Partnership of TEL Offshore Trust Partnership, effective as of January 1, 1983 (Exhibit 4(e) to Form 10-K for year ended December 31, 1992 of TEL Offshore Trust)	000-06910	4(e	)

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10(a	)*	Purchase Agreement, dated as of December 7, 1984 by and between Tenneco Oil Company and Tenneco Offshore II Company (Exhibit 10(a) to Form 10-K for year ended December 31, 1992 of TEL Offshore Trust)	000-06910	10(a	)

10(b	)*	Consent Agreement, dated November 16, 1988, between TEL Offshore Trust and Tenneco Oil Company (Exhibit 10(b) to Form 10-K for year ended December 31, 1988 of TEL Offshore Trust)	000-06910	10(b	)

10(c	)*	Assignment and Assumption Agreement, dated November 17, 1988, between Tenneco Oil Company and TOC-Gulf of Mexico Inc. (Exhibit 10(c) to Form 10-K for year ended December 31, 1988 of TEL Offshore Trust)	000-06910	10(c	)

10(d	)*	Gas Purchase and Sales Agreement Effective September 1, 1993 between Tennessee Gas Pipeline Company and Chevron U.S.A. Production Company (Exhibit 10(d) to Form 10-K for year ended December 31, 1993 of TEL Offshore Trust)	000-06910	10(d	)

10(e	)*	Letter Agreement, effective August 1, 2011, between TEL Offshore Trust Partnership and RNR Production, Land and Cattle Company, Inc. (Exhibit 99.2 to Current Report on Form 8-K filed October 27, 2011)	000-06910	99.2

10(f	)*	Partial Assignment of Overriding Royalty Interests, effective August 1, 2011, between TEL Offshore Trust Partnership and RNR Production, Land and Cattle Company, Inc. (Exhibit 99.3 to Current Report on Form 8-K filed October 27, 2011)	000-06910	99.3

10(g	)*	Letter Agreement, effective August 1, 2013, between TEL Offshore Trust Partnership and RNR Production, Land and Cattle Company, Inc. (Exhibit 99.2 to Current Report on Form 8-K filed October 31, 2013)	000-06910	99.2

10(h	)*	Partial Assignment of Overriding Royalty Interests, effective August 1, 2013, between TEL Offshore Trust Partnership and RNR Production, Land and Cattle Company, Inc. (Exhibit 99.3 to Current Report on Form 8-K filed October 31, 2013)	000-06910	99.3

10(i	)*	Renewal Demand Promissory Note in the original principal amount of $1,056,885, dated September 25, 2015 (Exhibit 10.1 to Current Report on Form 8-K filed October 20, 2015).

10(j	)*	Assignment of Overriding Royalty Interests, effective February 1, 2016, between TEL Offshore Trust Partnership and Arena Energy, LP (Exhibit 99.2 to Current Report on Form 8-K filed June 27, 2016)	000-6910	99.2

31.1		Certification furnished pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1		Certification furnished pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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99.2*	Order Approving Settlement Agreement, dated January 20, 2017 (Exhibit 99.1 to Current Report on Form 8-K filed January 27, 2017)	000-06910	99.1

99.3*	Final Judgment as to Individual Trustees dated January 20, 2017 (Exhibit 99.2 to Current Report on Form 8-K filed January 27, 2017)	000-06910	99.2

99.4*	Order Severing Final Judgment as to Individual Trustees dated January 20, 2017 (Exhibit 99.3 to Current Report on Form 8-K filed January 27, 2017)	000-06910	99.3

Item 16. Form 10-K Summary.

None.

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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 17^th day of April, 2017.


		TEL OFFSHORE TRUST
		By:		THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A., Corporate Trustee
		By:		/s/ MICHAEL J. ULRICH Michael J. Ulrich Vice President

Signature		Date


THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A., Corporate Trustee
By:	/s/ MICHAEL J. ULRICH Michael J. Ulrich, Vice President & Trust Officer	April 17, 2017
INDIVIDUAL TRUSTEES
/s/ GARY C. EVANS Gary C. Evans, Individual Trustee		April 17, 2017
/s/ THOMAS H. OWEN, JR. Thomas H. Owen, Jr., Individual Trustee		April 17, 2017
/s/ JEFFREY S. SWANSON Jeffrey S. Swanson, Individual Trustee		April 17, 2017

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.

TEL OFFSHORE TRUST 10-K