TEL OFFSHORE TRUST - FORM 10-Q

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

FORM 10-Q


ý		Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the quarterly period ended June 30, 2014
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: 0-06910

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. 919 Congress Avenue Austin, Texas (Address of principal executive offices)		78701 (Zip Code)

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

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 Web site, 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 whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting 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

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

As of August 13, 2014, 4,751,510 Units of Beneficial Interest in TEL Offshore Trust were outstanding.

NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (this "Form 10-Q") 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-Q, including without limitation, statements under "Trustee's Discussion and Analysis of Financial Condition and Results of Operations" in Item 2 of Part I and elsewhere herein regarding the financial position, production and reserve growth, 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 TEL Offshore Trust Partnership, 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 the risk factors discussed in Item 1A of Part I of the Trust's Annual Report on Form 10-K for the year ended December 31, 2013 (the "2013 10-K"), in Item 1A of Part II of this Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, and such other factors as may be set forth from time to time in the Trust's filings with the Securities and Exchange Commission. 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 factors. The Trust assumes no obligation, and disclaims any duty, to update these forward-looking statements.

PART I—FINANCIAL INFORMATION

Item 1. Condensed Financial Statements.

TEL OFFSHORE TRUST

CONDENSED STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS (UNAUDITED)

	June 30, 2014		December 31, 2013

Assets
Cash and cash equivalents	$	207,679	$	873,640
Net overriding royalty interest in oil and gas properties, net of accumulated amortization of $28,254,155 and $28,253,140, respectively		13,500		14,515


Total assets	$	221,179	$	888,155




Liabilities and Trust Corpus
Distribution payable to Unit holders	$	—	$	—
Reserve for future Trust expenses		207,679		873,640
Trust corpus (4,751,510 Units of beneficial interest authorized and outstanding)		13,500		14,515


Total liabilities and Trust corpus	$	221,179	$	888,155

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

TEL OFFSHORE TRUST

CONDENSED STATEMENTS OF DISTRIBUTABLE INCOME (UNAUDITED)

	Three Months Ended June 30,						Six Months Ended June 30,

	2014			2013			2014			2013
Royalty income	$	—		$	—		$	—		$	—
Interest income		—			2			—			7


		—			2			—			7
Decrease in reserve for future Trust expenses		177,036			47,565			665,961			223,925
Proceeds from note used for Trust expenses		—			44,170			—			44,170
General and administrative expenses		(177,036	)		(91,737	)		(665,961	)		(268,102	)


Distributable income		—			—			—			—


Distributable income per Unit (basic and diluted (4,751,510 Units))	$	.000000		$	.000000		$	.000000		$	.000000




Distributions per Unit (4,751,510 Units)	$	.000000		$	.000000		$	.000000		$	.000000

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

TEL OFFSHORE TRUST

CONDENSED STATEMENTS OF CHANGES IN TRUST CORPUS (UNAUDITED)

	Three Months Ended June 30,						Six Months Ended June 30,

	2014			2013			2014			2013
Trust corpus, beginning of period	$	14,128		$	16,210		$	14,515		$	17,308
Distributable income		—			—			—			—
Distribution payable to Unit holders		—			—			—			—
Proceeds from note used for Trust expenses		—			(44,170	)		—			(44,170	)
Amortization of net overriding royalty interest		(628	)		(481	)		(1,015	)		(1,579	)


Trust corpus, end of period	$	13,500		$	(28,441	)	$	13,500		$	(28,441	)

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

TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED)

(1) Trust Organization

Tenneco Offshore Company, Inc. ("Tenneco Offshore") created the TEL Offshore Trust ("Trust") effective January 1, 1983, pursuant to the Plan of Dissolution ("Plan") approved by Tenneco Offshore's stockholders on December 22, 1982. In accordance with the Plan, the TEL Offshore Trust Partnership ("Partnership") was formed in which the Trust owns a 99.99% interest and Tenneco Oil Company initially owned a .01% interest. In general, the Plan was effected by transferring an overriding royalty interest 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 held from time to time by the Partnership following the sales described in Note 3.

On January 14, 1983, Tenneco Offshore distributed Units 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 June 30, 2014 and December 31, 2013, respectively, the reserve amount was $207,679 and $873,640;

(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 $1.2 million (assuming no further sales of any interests in the Royalty) or (ii) a decision to terminate the Trust by the affirmative vote of Unit holders representing a majority of the Units. Future net revenues attributable to the Royalty were estimated at approximately $8.6 million (unaudited) as of October 31, 2013. Such future net revenues include projected reserves attributable to the three wells drilled by Arena Offshore, LP ("Arena") but do not include capital expenditures attributable to the redevelopment of to Eugene Island 339. However, such future net revenues do include the estimated total plugging and abandonment costs related to Eugene Island 339, with costs to the Original Royalty as of October 31, 2013 relating thereto estimated to be approximately $19.8 million, with no

TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

(1) Trust Organization (Continued)

further expenses expected to be incurred. Upon termination of the Trust, the Corporate Trustee will sell for cash all assets held in the Trust estate and make a final distribution to the Unit holders of any funds remaining, after all Trust liabilities have been satisfied.

On October 27, 2011, the Partnership sold 20% of the Original 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.

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 (the "Individual Trustees"), as trustees (collectively, the "Trustees").

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 owner or owners of the Royalty Properties (the "Working Interest Owners").

(2) Basis of Accounting and Going Concern

The accompanying unaudited financial information has been prepared by the Corporate Trustee. The accompanying financial information is prepared on a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America ("GAAP"). The Corporate Trustee and the Individual Trustees believe that the information furnished reflects all adjustments that are, in the opinion of the Trustees, necessary for a fair presentation of the results for the interim periods presented. Such adjustments are of a normal and recurring nature. The financial information should be read in conjunction with the financial statements and notes thereto included in the Trust's Annual Report on Form 10-K for the year ended December 31, 2013.

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. The actual cash distributions to the Trust are made based on the terms of the conveyance that created the Trust's overriding royalty interest. The overriding royalty interest entitles 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 previous sales by the Partnership, the Royalty now represents a 15% net profits interest.

TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

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

Actual cash receipts may 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 condensed financial statements of the Trust, as prepared on a modified cash basis, reflect the Trust's assets, liabilities, Trust corpus, earnings and distributions, as follows:

(a): Royalty income from the overriding royalty interest is recorded when received, including the effect of overtaken or undertaken positions and negative or positive adjustments, by the Corporate Trustee on the last business day of each calendar quarter. In addition, Royalty income includes amounts related to funds deposited or released from the Special Cost Escrow account—see (d);
(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 are recorded at the time of payment or receipt. The Special Cost Escrow account is an account of the Working Interest Owners and is not reflected in the condensed financial statements of the Trust;
(e): Amortization of the investment in overriding royalty interest is calculated based on the units-of-production method. Such amortization is charged directly to Trust corpus and does not affect distributable income; and
(f): Proceeds from loans used to pay for Trust expenses is charged directly to Trust corpus.

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 condensed financial statements of the Trust differ from condensed 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.

TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

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

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 amortizes the investment in overriding royalty interest using the units-of-production method. The Trust's rate of recording amortization is dependent upon the estimates of total proved reserves, which incorporates various assumptions and future projections. If the estimates of total proved reserves decline significantly, the rate at which the Trust records amortization expense would increase, reducing Trust corpus. Such a decline in reserves may result from lower commodity prices, which may make it uneconomic to produce from higher cost fields. The Trust is unable to predict changes in reserve quantity estimates as such quantities are dependent on future economic and operational conditions.

Impairment of Investment in Overriding Royalty Interest. The Trust reviews overriding royalty interests in oil and gas properties for possible impairment whenever events or circumstances indicate the carrying amount of the asset may not be recoverable. If there is an indication of impairment, the Trust prepares an estimate of future cash flows (undiscounted and without interest charges) expected to result from the use of the asset and its eventual disposition. If these cash flows are less than the carrying amount of the asset, an impairment loss is recognized to write down the asset to its estimated fair value. Preparation of estimated expected future cash flows is inherently subjective and is based on the Corporate Trustee's best estimate of assumptions concerning expected future conditions. There were no write downs taken in the three or six months ended June 30, 2014.

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

Reserve for future Trust expenses. Represents cash reserves for future Trust expenses established by the Trustee. The changes in reserves 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 6.

TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

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

Proceeds from Sale of Overriding Royalty. The Trust records proceeds from the sale of Overriding Royalty Interests when received.

Special Cost Escrow account. The Special Cost Escrow account (see Note 5) is established for future costs to be incurred to plug and abandon wells, dismantle and remove platforms, pipelines and other production facilities, and for the estimated amount of future capital expenditures on the Royalty Properties. The funds held in the Special Cost Escrow account are not reflected in the condensed financial statements of the Trust. However, funds deposited to or released from the Special Cost Escrow account are included in Royalty income.

Use of Estimates. The preparation of financial statements requires the Trustees to make use of estimates and assumptions that affect amounts reported in the condensed 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 three months ended June 30, 2014, applicable to the Trust or its condensed financial statements.

Going Concern. The accompanying condensed 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. The Trust has not received Royalty income since the fourth quarter of 2008. The lack of sufficient Net Proceeds to make distributions in the foreseeable future as discussed in Note 4 and the inability to maintain adequate cash reserves raise substantial doubt about the Trust's ability to continue as a going concern. Certain potential alternatives available to the Trustees are described in Note 6. The condensed financial statements do not include any adjustments that might result from the outcome of this uncertainty.

(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 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 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 is established for the future costs to be incurred to plug and abandon wells, dismantle and remove platforms, pipelines and other production facilities, and for the estimated amount of future capital expenditures on the Royalty Properties. Net Proceeds do not include amounts received by the Working Interest Owners as advance gas payments, "take-or-pay" payments or similar payments unless and until such payments are extinguished or repaid through the future delivery of gas.

TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

(3) Net Overriding Royalty Interest (Continued)

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. Refer to Note 6 for further discussion of the 2011 Royalty Sale.

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. Refer to Note 6 for further discussion of the 2013 Royalty Sale.

Following the 2011 Royalty Sale and the 2013 Royalty Sale, the Partnership has retained a 60% interest in the Original Royalty, and thus the Partnership will receive in the future only 15% of the Net Proceeds when there are sufficient Net Proceeds for distribution on the Partnership's Royalty.

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 and (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 are to pay to the Partnership 15% of the Net Proceeds for the immediately preceding Quarterly Period. A Quarterly Period is each period of three months commencing on the first day of February, May, August and November. In turn, the Partnership distributes funds to its partners on the last business day of each calendar quarter. Cash distributions from the Trust, if any, are made in January, April, July and October of each year, and are payable to Unit holders of record as of the last business day of each calendar quarter. Thus, any cash conveyed to the Trust from the Partnership during the quarter ended June 30, 2014 would substantially represent the revenues and expenses from the Royalty Properties from February 2014 through April 2014. Similarly, any cash conveyed to the Trust from the Partnership during the quarter ended June 30, 2013 would substantially represent the revenues and expenses from the Royalty Properties from February 2013 through April 2013. However, there was no cash conveyed to the Trust from the Partnership pursuant to its overriding royalty interest in the Royalty Properties from either February 2014 through April 2014 or February 2013 through April 2013. The financial and operating information included in this Form 10-Q for the three and six months ended June 30, 2014 and June 30, 2013 represents financial and operating information with respect to the Royalty Properties for the immediately preceding months of November, December, January, February, March and April. Income received pursuant to the Partnership's overriding royalty interest is recorded by the Trust on a cash basis, when it is received by the Trust from the Partnership.

TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

(4) Distributions to Unit Holders

Production ceased at Eugene Island 339 and Ship Shoal 182 and 183 following damages inflicted by Hurricane Ike in September 2008. Future Net Proceeds may take into account the Trust's share of project costs and other related expenditures that are not covered by insurance of the operator of the Royalty Properties. On December 19, 2008, the Trust announced its fourth quarter distribution of approximately $0.7 million, which was paid on January 9, 2009. The funds available for the fourth quarter distribution were severely negatively impacted by Hurricane Ike. On March 25, 2009, the Trust announced that there would be no trust distribution for the first quarter of 2009, and the Trust has not made a distribution since January 9, 2009.

While oil and gas production at Ship Shoal 182 and 183 and at Eugene Island 339 has been partially restored, there are not likely to be sufficient Net Proceeds from the Royalty Properties for the Trust to make a regularly scheduled quarterly distribution to Unit holders for the foreseeable future. As a result of the damage inflicted by Hurricane Ike, Net Proceeds will continue to be severely impacted by reduced production. There can be no assurance by Chevron or anyone else as to the actual timing for any future distributions to the Partnership from its interests in the Royalty Properties, and there is no guarantee that any further distributions will be made. Future Net Proceeds from the Royalty Properties will take into account the Trust's share of project costs and other related expenditures that are not covered by the insurance of the operators of the Royalty Properties. Chevron has completed the work associated with the wells on Eugene Island 339 and informed the Trust that the estimate of 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. No further expenses are expected to be incurred. If development and production costs of the Royalty Properties exceed the proceeds of production from the Royalty Properties, the Trust will not receive Net Proceeds until future proceeds from production exceed the total of the excess costs plus accrued interest. As a result of the damage inflicted by Hurricane Ike, the Trust has not received Net Proceeds since December 2008. As of April 30, 2014, aggregate development and production costs for the Royalty Properties since November 2008 have exceeded the related proceeds of production from the Royalty Properties by approximately $4.3 million, net to the entire Original Royalty ($2.6 million applicable to the Trust).

For the three months ended June 30, 2014, the Trust had undistributed net income of $341,771, representing the Trust's portion of the aggregate undistributed net income of $2,278,477 associated with the Royalty Properties for the three months ended June 30, 2014. For the six months ended June 30,

TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

(4) Distributions to Unit Holders (Continued)

2014, the Trust had undistributed net income of $405,739, representing the Trust's portion of the aggregate undistributed net income of $2,704,931 associated with the Royalty Properties for the six months ended June 30, 2014. Undistributed net income represents positive Net Proceeds, generated during the respective period, but not distributed by the Working Interest Owners.

The Trust's portion of the cumulative undistributed net loss associated with the Royalty Properties was $2,570,783 as of April 30, 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 is carried forward and offset, in future periods, by positive proceeds earned by the related Working Interests Owner(s). The Trust will not receive Net Proceeds until future proceeds from production exceed the total of the excess costs plus applicable accrued interest.

(5) Special Cost Escrow Account

The Special Cost Escrow is an account of the Working Interest Owners, and it is described herein for informational purposes only. The Conveyance provides for reserving funds for estimated future "Special Costs" of plugging and abandoning wells, dismantling platforms and other costs of abandoning the Royalty Properties, as well as for the estimated amount of future drilling projects and other capital expenditures on the Royalty Properties. As provided in the Conveyance, the amount of funds to be reserved is determined based on certain factors, including estimates of aggregate future production costs, aggregate future Special Costs, aggregate future net revenues and actual current net proceeds. Deposits into this account reduce current distributions and are placed in an escrow account and invested in short-term certificates of deposit. Such account is herein referred to as the "Special Cost Escrow" account. As of June 30, 2014, approximately $1,000 remained in the Special Cost Escrow account. The funds held in the Special Cost Escrow account are not reflected in the condensed financial statements of the Trust. Special Cost Escrow account funds will generally be utilized to pay Special Costs to the extent there are not adequate current net proceeds to pay such costs. Special Costs that have been paid are no longer included in the Special Cost Escrow calculation. Deposits to the Special Cost Escrow account will generally be made when the balance in the Special Cost Escrow account is less than 125% of estimated future Special Costs and there is a Net Revenues Shortfall (a calculation of the excess of estimated future costs over estimated future net revenues pursuant to a formula contained in the Conveyance). When there is not a Net Revenues Shortfall, amounts in the Special Cost Escrow account will generally be released, to the extent that Special Costs have been incurred. Amounts in the Special Cost Escrow account will also be released when the balance in such account exceeds 125% of future Special Costs.

During the first six months of 2014 and during 2013, there were no funds released from or deposited into the Special Cost Escrow account.

RNR Production was the purchaser of the partial interests in the overriding royalty interest sold pursuant to the 2011 Royalty Sale and the 2013 Royalty Sale and now holds 40% of the Original

TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

(5) Special Cost Escrow Account (Continued)

Royalty (or 10% of 8/8ths) and 40% of the Partnership's rights and obligations with respect to the Special Cost Escrow, which were assigned in connection with the 2011 Royalty Sale and the 2013 Royalty Sale.

Deposits to the Special Cost Escrow Account will be required in future periods in connection with other production costs, other abandonment costs, other capital expenditures and changes in the estimates and factors described above. Such deposits could result in a significant reduction in Royalty income in the periods in which such deposits are made.

(6) 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 June 30, 2014 and December 31, 2013, the reserve amount was $207,679 and $873,640, respectively.

There are not likely to be positive Net Proceeds from the Royalty Properties for the foreseeable future. There can be no assurance by Chevron or anyone else as to the actual timing for any future distributions to the Partnership from the Royalty, and there is no guarantee that any further distributions will be made. Absent the receipt of Net Proceeds or other actions being taken, at some time, the Trust will not have sufficient funds to pay the liabilities of the Trust. Based upon currently estimated expenditures, exclusive of the costs and expenses relating to the probate proceeding described below, it is anticipated that the Trust's existing cash reserves will be depleted during the third quarter of 2014. It is anticipated that the Trust will fund the costs and expenses of the probate proceeding with loans from The Bank of New York Mellon, an affiliate of the Corporate Trustee. However, The Bank of New York Mellon will continue to evaluate the probate proceeding and the costs and expenses associated therewith. It is further anticipated that any such loans will be repaid from any proceeds received by the Trust, including any proceeds received upon any sale of the remaining Royalty and will therefore reduce the cash available for distribution to the Trust's unitholders.

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 10, the Trustees previously 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

TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

(6) Reserve For Future Trust Expenses (Continued)

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.

On October 27, 2011, the Trust issued a press release announcing that the Partnership had consummated the 2011 Royalty Sale, which generated $1,600,000 in gross proceeds and occurred as part of a formal auction process for the Partnership's overriding royalty interest in the Royalty Properties. The Trust received from the Partnership a distribution of approximately $1,485,851, representing 99.99% of the net proceeds from the sale of $1,486,000. The Trust used such net proceeds solely for the payment of expenses of the Trust.

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 Demand Promissory Note (as defined in Note 10 below) and has used, and will continue to use, the remaining net proceeds solely for the payment of expenses of the Trust.

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 six months ended June 30, 2014.

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 June 30, 2014, the amount of such fees was approximately $113,105 in the aggregate. Such suspended fees will be recorded as an expense of the Trust when invoiced by the Trustees and paid.

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 requests the Court to 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 unitholder 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") are 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 Trust's unitholders; and, to, thereafter terminate the Partnership and the Trust. There can be no assurances whether the Court will grant the requested relief and, if such relief is granted, when such actions will be completed.

TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

(7) Federal Income Tax Matters

The IRS has ruled that the Trust is a grantor trust and that the Partnership is a partnership for federal income tax purposes. Thus, the Trust will incur no federal income tax liability and each Unit holder will be treated as owning an interest in the Partnership.

(8) Commitments and Contingencies

The Managing General Partner of the Partnership has advised the Trust that, although Chevron believes that it is in general compliance with applicable health, safety and environmental laws and regulations that have taken effect at the federal, state and local levels, costs may be incurred to comply with current and proposed environmental legislation that could result in increased operating expenses on the Royalty Properties.

(9) Related Party Transactions

Each of the Working Interest Owners owns 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 from the Chevron Corporation accounted for approximately 100% of crude oil revenues from the Royalty Properties for the three and six months ended June 30, 2014 and 2013. Sales to Chevron Corporation accounted for 100% of total gas revenues from the Royalty Properties during the three and six months ended June 30, 2014 and 2013.

The Trust's share of Royalty income was reduced by approximately $23,406 and $32,174 for each of the three months ended June 30, 2014 and 2013, respectively, and $42,366 and $71,896 for each of the six months ended June 30, 2014 and 2013, respectively, for management fees paid to the Working Interest Owners as reimbursement for expenses incurred by them on behalf of the Trust. Such management fees were calculated as 3% of the Trust's share of the sum of revenues, production expenses and capital expenditures attributable to the Royalty Properties in each of the periods above.

(10) Note Payable

On May 23, 2013, the Trust executed that certain Demand Promissory Note (the "Note") for $300,000 payable to Bank of New York Mellon, N.A., an affiliate of the Corporate Trustee, which evidenced an extension of credit for borrowed money authorized under Section 6.08 of the Trust Agreement. The outstanding indebtedness evidenced by the Note was paid by the Trust in November 2013 from proceeds of the 2013 Royalty Sale.

TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

(11) Subsequent Events

On July 2, 2014, the Trust issued a press release announcing that there would be no trust distribution for the second quarter of 2014 for Trust unitholders of record on June 30, 2014.

Refer to the final paragraph of Note 6 above for a discussion of the Probate Proceeding initiated by the Trustees on July 10, 2014.

Item 2. Trustee's Discussion and Analysis of Financial Condition and Results of Operations.

Liquidity and Capital Resources

Source of Liquidity and Capital

The Trust's source of liquidity and capital is the Royalty income received from its share of the Net Proceeds from the Royalty Properties. Total future net revenues attributable to the Partnership's interest in the Royalty were estimated at $8.6 million as of October 31, 2013. However, there are not likely to be sufficient Net Proceeds from the Royalty Properties for the Trust to make a regularly scheduled quarterly distribution to Unit holders for the foreseeable future. The Trust has not received a distribution of Net Proceeds since December 2008. 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 Royalty in order to pay Trust expenses. As of June 30, 2014, the cash reserves remaining from the 2013 Royalty Sale were $207,679. Based upon currently estimated expenditures, exclusive of the costs and expenses relating to the probate proceeding described below, it is anticipated that the existing cash reserves will be depleted during the third quarter of 2014. In light of the continuing expenses of the Trust and the lack of any distributions and any assurances as to the actual timing of any future distributions, the Trustees have considered the alternatives available to the Trust to obtain funds or to reduce the ongoing costs and expenses of the Trust and after evaluating the alternatives available to the Trust, the Trustees elected to institute the probate proceeding described below.

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 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 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. Accordingly, on May 23, 2013, the Trust executed that certain Demand Promissory Note (the "Note") for $300,000 payable to Bank of New York Mellon, N.A., an affiliate of the Corporate Trustee, which evidenced an extension of credit for borrowed money authorized under Section 6.08 of the Trust Agreement. A portion of the proceeds from this Note were used to pay expenses of the Trust. The outstanding indebtedness evidenced by the Note was paid by the Trust in November 2013 from proceeds of the 2013 Royalty Sale.

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), which generated $1,600,000 in gross proceeds and occurred as part of a formal auction process for the Partnership's overriding royalty interest in the Royalty Properties. The Trust received from the Partnership a distribution of approximately $1,485,581, representing 99.99% of the net proceeds from the sale of $1,486,000. The 2011 Royalty Sale was made to RNR Production, Land and Cattle Company, Inc. ("RNR Production") on October 27, 2011, though the assignment was effective as of

August 1, 2011. The Trust used the net proceeds from the 2011 Royalty Sale solely for the payment of expenses of the Trust.

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), 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 2013 Royalty Sale to RNR Production closed on October 31, 2013, though the assignment was effective as of August 1, 2013. The Trust used approximately $300,000 of the net proceeds received in October 2013 to repay the Trust's indebtedness under the Note and has used, and will continue to use, the remaining net proceeds solely for the payment of expenses of the Trust.

Following the 2013 Royalty Sale to RNR Production, the Partnership's remaining interest in the Original Royalty currently entitles the Trust to its share (99.99%) of 60% of 25% of the Net Proceeds attributable to the Royalty Properties. Generally, "Net Proceeds" means the amounts received by the Working Interest Owners from the sale of minerals from the Royalty Properties less operating and capital costs incurred, management fees and expense reimbursements owing to the Managing General Partner of the Partnership, applicable taxes other than income taxes, and the Special Cost Escrow account. The Special Cost Escrow account is established for the future costs to be incurred to plug and abandon wells, dismantle and remove platforms, pipelines and other production facilities, and for the estimated amount of future capital expenditures on the Royalty Properties. Net Proceeds do not include amounts received by the Working Interest Owners as advance gas payments, "take-or-pay" payments or similar payments unless and until such payments are extinguished or repaid through the future delivery of gas.

As indicated above, the Trustees have previously authorized the Trust to borrow funds and the Partnership to sell portions of the Original Royalty in an effort to pay the ongoing costs and expenses incurred by the Trust in fulfilling its obligations under the Trust Agreement. 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 requests the Court to 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 unitholder 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 are 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 Trust's unitholders; and, to, thereafter terminate the Partnership and the Trust. It is anticipated that the Trust will fund the costs and expenses of the probate proceeding with loans from The Bank of New York Mellon, an affiliate of the Corporate Trustee. However, The Bank of New York Mellon will continue to evaluate the probate proceeding and the costs and expenses. There can be no assurances whether the Court will grant the requested relief and, if such relief is granted, when such actions will be completed. In addition, it is anticipated that any loans obtained by the Trust to pay the costs and expenses of the Probate Proceeding will be repaid from any proceeds received by the Trust, including any proceeds received upon any sale of the remaining Royalty and, as a result, there can be no assurances as to amount of net proceeds resulting from any such sale of the Royalty that may be available for distribution to the Trust's unitholders.

Historical Damage to Royalty Properties

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. On December 19, 2008, the Trust announced its fourth quarter distribution of approximately $0.7 million, which was paid on January 9, 2009. Based on the damage caused by Hurricane Ike, the Trust's scheduled distribution for the fourth quarter of 2008 was severely negatively impacted and no distributions have been made to Unit holders since January 9, 2009. In the fourth quarter of 2010, Chevron withdrew $4,304,894 from the Special Cost Escrow account of the Working Interest Owners (a reserve fund for certain costs) to cover expenses incurred in connection with the plugging and abandonment of Eugene Island 339, which served to reduce the amount by which production costs exceeded the proceeds from production; however, additional deposits to the Special Cost Escrow account would be required in future periods in accordance with the terms of the Conveyance if, and when, Net Proceeds would otherwise be payable on the Partnership's Royalty. As a result of the damage inflicted by Hurricane Ike, Net Proceeds will continue to be severely impacted by reduced production, from historical levels, and the amount of expenditures incurred that are associated with such damages, including any remaining expenditures required to plug and abandon the wells on Eugene Island 339.

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 estimate of 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. No further expenses are expected to be incurred. In December 2009, Chevron and Arena entered into a participation agreement (as amended, 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 Royalty, and the Royalty held by the Partnership with respect to such properties has been reduced proportionately.

As a result of such assignment, the Royalty held by the Partnership on Eugene Island 339 has been reduced by 65%. See "—Operations" for a more detailed discussion of Eugene Island 339.

In addition, production from West Cameron 643 and East Cameron 371 ceased following damage inflicted by Hurricane Ike in September 2008 to third-party transporters' pipelines. The lease for West Cameron 643 expired on May 31, 2010 and the lease for East Cameron 371 expired on March 31, 2010. Plugging and abandoning of the wells at West Cameron 643 was completed in October 2012. Field abandonment work for East Cameron 371, including the related wells, equipment platforms and any field infrastructure, remains to be completed.

Future Net Proceeds from the Royalty Properties will take into account the Trust's share of project costs and other related expenditures that are not covered by the insurance of the operators of the Royalty Properties. Chevron reached settlements that provide Chevron with insurance proceeds associated with damages that Chevron's assets sustained from Hurricane Ike. The allocated portion thereof with respect to the Partnership's interest in Eugene Island 339, as a Royalty Property, was approximately $781,000. Chevron applied $400,000 thereof in the first quarter of 2011 and applied the remaining amount of approximately $381,000 in the fourth quarter of 2012. All such allocated insurance proceeds were applied to the Partnership's portion of the aggregate cost to plug and abandon the wells subject to the Royalty on Eugene Island 339. Chevron has completed the work associated with the wells on Eugene Island 339 and informed the Trust that the estimate of 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. No further expenses are expected to be incurred. If Production Costs of the Royalty Properties exceed the Gross Proceeds from the Royalty Properties, the Trust will not receive Net Proceeds until future proceeds from production exceed the total of the excess costs plus accrued interest at a rate equal to one-fourth of (i) one-half of one percent plus (ii) the median between the prime interest rate at the end of a quarterly period in which there are excess costs and the prime interest rate at the end of the preceding quarterly period, during the deficit period. As a result of the damage inflicted by Hurricane Ike, the Trust has not received Net Proceeds since December 2008. As of April 30, 2014, aggregate development and production costs for the Royalty Properties since November 2008 have exceeded the related proceeds of production from the Royalty Properties by approximately $4.3 million, net to the entire Original Royalty (or $2.6 million, net to the Trust). While

Chevron has not withdrawn any funds from the Special Cost Escrow Account since the fourth quarter of 2010, additional deposits to the Special Cost Escrow account would be required in future periods in accordance with the terms of the Conveyance if, and when, Net Proceeds would otherwise be payable on the Royalty. Accordingly, there will not be sufficient Net Proceeds from the Royalty Properties to make distributions for some period of time in the future. At this time, the ultimate outcome of these various matters cannot be determined. See "—Operations"

Substantial uncertainties exist with regard to future oil and gas prices, which are subject to material fluctuations due to changes in production levels and pricing and other actions taken by major petroleum producing nations, as well as the regional supply and demand for oil and gas, worldwide political conditions, weather, industrial growth, conservation measures, competition, economic conditions generally and other variables.

In accordance with the provisions of the Trust Agreement, generally all Net Proceeds received by the Trust, net of Trust general and administrative expenses and any cash reserves established for the payment of contingent or future obligations of the Trust, are distributed currently to the Unit holders. In 1994, in anticipation of future periods when the cash received from the Royalty may not be sufficient for payment of Trust expenses, the Trust determined, in accordance with the Trust Agreement, to begin further increasing the Trust's cash reserve each quarter. In the first quarter of 1998, the Trust determined that the Trust's cash reserve was then sufficient to provide for future administrative expenses in connection with the winding up of the Trust. The Trust determined that a cash reserve equal to three times the average expenses of the Trust during each of the past three years was sufficient at such time to provide for future administrative expenses in connection with the winding up of the Trust.

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. During the six months ended June 30, 2014, the Trust utilized $655,961 of the proceeds from the 2013 Royalty Sale to pay for Trust expenses and as a result the reserve balance of $873,640 as of December 31, 2013 was reduced to $207,679 as of June 30, 2014.

The accompanying condensed 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. 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. Certain potential alternatives available to the Trustees are described in Note 6 to the condensed financial statements. The condensed financial statements do not include any adjustments that might result from the outcome of this uncertainty. See Notes 2 and 6 to the condensed financial statements.

Future Net Revenues and Termination of the Trust

Based on a reserve study provided to Chevron, as the Managing General Partner of the Partnership, by DeGolyer and MacNaughton, independent petroleum engineers, as of October 31, 2013 future net revenues attributable to the Trust's royalty interests were estimated at $8.6 million. Estimates

of proved oil and gas reserves attributable to the Partnership's royalty interest are based on existing economic and operating conditions in effect at October 31, 2013 in order to correspond with distributions to the Trust. Such reserve study also indicates that approximately 4% of the future net revenues from the Royalty Properties are expected to be received by the Trust by October 31, 2015. The reserve study does include projected reserves attributable to the well drilled by Arena during the fourth quarter of 2012 on Eugene Island 339 but does not include any capital expenditures for any redevelopment of Eugene Island 339. However, such reserve study does include the Trust's share of the estimated total plugging and abandonment costs related to Eugene Island 339. Chevron has completed the work associated with the wells on Eugene Island 339 and informed the Trust that the estimate of the aggregate cost 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. No further expenses are expected to be incurred. Because the Trust Agreement provides that the Trust will terminate in the event estimated future net revenues fall below $1.2 million, it would be possible for the Trust to terminate even though some or all of the Royalty Properties continued to have remaining productive lives. Upon any termination of the Trust, the Trustees will sell for cash all of the assets held in the Trust estate and make a final distribution to Unit holders of any funds remaining after all Trust liabilities have been satisfied. The estimates of future net revenues discussed above are subject to large variances from year to year and should not be construed as exact. There are numerous uncertainties present in estimating future net revenues for the Royalty Properties. The estimate may vary depending on changes in market prices for crude oil and natural gas, the recoverable reserves, annual production and costs assumed by DeGolyer and MacNaughton. In addition, future economic and operating conditions as well as results of future drilling plans may cause significant changes in such estimate. The discussion set forth above is qualified in its entirety by reference to the Trust's Annual Report on Form 10-K for the year ended December 31, 2013. The Trust's Form 10-K is available at the website of the Securities and Exchange Commission ("SEC") at www.sec.gov or upon request from the Corporate Trustee.

Special Cost Escrow Account

The Conveyance provides for reserving funds for estimated future "Special Costs" of plugging and abandoning wells, dismantling platforms and other costs of abandoning the Royalty Properties, as well as for the estimated amount of future drilling projects and other capital expenditures on the Royalty Properties. As provided in the Conveyance, the amount of funds to be reserved is determined based on factors including estimates of aggregate future production costs, aggregate future Special Costs, aggregate future net revenues and actual current net proceeds. Deposits into this account reduce current distributions and are placed in an escrow account and invested in short-term certificates of deposit. Such account is herein referred to as the "Special Cost Escrow" account. The Trust's share of interest generated from the Special Cost Escrow account serves to reduce the Trust's share of allocated production costs. Special Cost Escrow funds will generally be utilized to pay Special Costs to the extent there are not adequate current net proceeds to pay such costs. Special Costs that have been paid are no longer included in the Special Cost Escrow calculation. Deposits to the Special Cost Escrow account will generally be made when the balance in the Special Cost Escrow account is less than 125% of estimated future Special Costs and there is a Net Revenues Shortfall (a calculation of the excess of estimated future costs over estimated future net revenues pursuant to a formula contained in the Conveyance). When there is not a Net Revenues Shortfall, amounts in the Special Cost Escrow account will generally be released, to the extent that Special Costs have been incurred. Amounts in the Special

Cost Escrow account will also be released when the balance in such account exceeds 125% of estimated future Special Costs. In the first six months of 2013, there were no funds released or escrowed from the Special Cost Escrow account. As of June 30, 2014, $1,000 remained in the Special Cost Escrow account. The funds held in the Special Cost Escrow account are not reflected in the condensed financial statements of the Trust. The discussion of the terms of the Conveyance and Special Cost Escrow account contained herein is qualified in its entirety by reference to the Conveyance itself, which is an exhibit to this Form 10-Q and is available upon request from the Corporate Trustee.

Aggregate development and production costs in excess of the related proceeds for the royalty properties, as of April 30, 2014, were approximately $4.3 million, net to the entire Royalty ($2.6 million applicable to the Trust); however, additional deposits to the Special Cost Escrow account would be required in future periods in accordance with the underlying conveyance of the royalty if, and when, net proceeds would otherwise be payable on the royalty. During the first six months of 2014 and during 2013, there were no funds released from or escrowed into the Special Cost Escrow account. As of June 30, 2014, $1,000 remained in the Special Cost Escrow account.

In connection with the 2013 Royalty Sale, and including the effect of the 2011 Royalty Sale, the Partnership has assigned an aggregate 40% of its rights and obligations with respect to the Special Cost Escrow account.

Chevron, in its capacity as Managing General Partner of the Partnership, has advised the Trust that additional deposits to the Special Cost Escrow account will be required in future periods in connection with other production costs, other abandonment costs, other capital expenditures and changes in the estimates and factors described above. Such deposits could result in a significant reduction in Royalty income in the periods in which such deposits are made, including the possibility that no Royalty income would be received in such periods.

Three Months Ended June 30, 2014 and 2013

Royalty Trust Comparison

Royalty income was $0 for the three months ended June 30, 2014 and 2013. Gross proceeds for the underlying Royalty Properties exceeded development and production costs by $2,278,477, or $341,771 attributable to the Trust, for the production period of February, March and April 2014 attributable to the three months ended June 30, 2014 and by $1,993,763, or $398,753 attributable to the Trust for the production period of February, March and April 2013 attributable to the three months ended June 30, 2013. 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 protection, and as a result there was no royalty income for the quarters ended June 30, 2014 and 2013.

General and administrative expenses for the Trust were $177,036 for the three months ended June 30, 2014 compared to $91,737for the three months ended June 30, 2013.

The reserve for future Trust expenses decreased $177,036 from March 31, 2014 to June 30, 2014 due to payments for Trust expenses.

There was no distributable income for each of the three months ended June 30, 2014 and June 30, 2013 and therefore no distributions to unit holders.

For the three months ended June 30, 2014 and June 30, 2013, the Trust had undistributed net income of $341,771 and $398,753, respectively, representing the Trust's portion of the undistributed net income of $2,278,477 and $1,993,763 associated with the Royalty Properties for the three months ended June 30, 2014 and 2013. The cumulative undistributed net loss for the Trust was $2,570,783 as of April 30, 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 is carried forward and offset, in future periods, by positive proceeds earned by the related Working Interest Owner(s). The Trust will not receive Net Proceeds until future proceeds from production exceed the total of the excess costs plus applicable accrued interest.

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 have no control over these operations or internal controls relating to this information.

Volumes and dollar amounts discussed below represent amounts recorded by the Working Interest Owners unless otherwise specified.

Natural Gas and Gas Products

Gas revenues increased $212,506, or 265%, to $292,564 in the second quarter of 2014 from $80,058 in the second quarter of 2013. The increase is a result of Ship Shoal 182/183 wells coming back on line in the second quarter of 2014. Gas volumes during the second quarter of 2014 increased 172% to 68,575 Mcf from 25,254 Mcf in the second quarter of 2013. The increase in volumes is due primarily to gas wells coming back on line. Excluding the impact of prior period adjustments, the average price received for natural gas increased approximately 39.9% from an average price of $3.69 per Mcf in the second quarter of 2013 to $5.16 per Mcf in the second quarter of 2014.

Crude Oil and Condensate

Crude oil and condensate revenues decreased $184,459, or 5%, to $3,470,334 in the second quarter of 2014 from $3,654,793 in the second quarter of 2013. Oil volumes increased 2% from 33,195 barrels in the second quarter of 2013 to 33,858 barrels in the second quarter of 2014. Excluding the impact of prior period adjustments, the average price received for crude oil and condensate production decreased 7%, or $8.31, to $102.52 per barrel in the second quarter of 2014 from $110.83 per barrel in the second quarter of 2013.

Capital Expenditures

Capital expenditures decreased by $58,160, or 78%, from $74,103 in the second quarter of 2013 to $15,943 in the second quarter of 2014. The higher amount of capital expenditures during the second quarter of 2013 relate primarily to facility improvement projects and drilling and completion costs associated with a well at Ship Shoal 182/183.

Production Expenses

Production expenses decreased by $323,061, or 19%, from $1,690,543 in the second quarter of 2013 to $1,367,482 in the second quarter of 2014. The decrease in operating expenses is due to a reduction in maintenance projects at Ship Shoal 169 in the second quarter of 2014 as compared to the second quarter of 2013.

Special Cost Escrow Account

In the second quarter of 2014, there were no funds released from or escrowed into the Special Cost Escrow account. As of June 30, 2014, $1,000 remained in the Special Cost Escrow account. The funds held in the Special Cost Escrow account are not reflected in the condensed financial statements of the Trust. The Special Cost Escrow account is set aside for estimated abandonment costs and future capital expenditures, as provided for in the Conveyance. For additional information relating to the Special Cost Escrow account, see "—Special Cost Escrow Account" below.

Summary By Property

Listed below is a summary of operations of the principal Royalty Properties for the second quarter of 2014 as compared to operations for the second quarter of 2013 based on gross revenues generated during these periods combined.

Eugene Island 339

Eugene Island 339 net crude oil revenues decreased from $1,029,665 in the second quarter of 2013 to $663,078 in the second quarter of 2014, due to a decrease in net crude oil production from 9,427 barrels in the second quarter of 2013 to 6,454 barrels in the second quarter of 2014. Gas revenues increased from $19,677 in the second quarter of 2013 to $50,632 in the second quarter of 2014, due to an increase in gas production from 6,091 Mcf in the second quarter of 2013 to 9,498 Mcf in the second quarter of 2014. The increase in volumes is primarily attributable to the two new wells on Eugene Island 339. Capital expenditures were $0 in the second quarter of 2014. Prior period adjustments to capital expenditures resulted in a benefit of $41,507 in the second quarter of 2013. Operating expenses increased from $20,274 in the second quarter of 2013 to $21,038 in the second quarter of 2014.

Ship Shoal 182/183

Ship Shoal 182/183 net crude oil revenues increased from $2,515,589 in the second quarter of 2013 to $2,644,396 in the second quarter of 2014, due to an increase in net crude oil production from 22,788 barrels in the second quarter of 2013 to 25,784 barrels in the second quarter of 2014. The revenue increase from production was partially offset by a decrease in the average crude oil price received from $110.39 per barrel in the second quarter of 2013 to $102,56 per barrel for the same period in 2014. Gas revenues increased from $43,125 in the second quarter of 2013 to $225,476 in the second quarter of 2014, due to an increase in gas production from 11,199 Mcf in the second quarter of 2013 to 43,963 Mcf in the second quarter of 2014 as a result of the shut ins during the second quarter of 2013. Gas revenues also increased due an increase in the average gas revenue price received from $3.85 per Mcf in the second quarter of 2013 to $5.13 per Mcf for the same period in 2014. Capital expenditures decreased from $73,407 in the second quarter of 2013 to $14,245 in the second quarter of 2014. Operating expenses decreased from $1,488,626 in the second quarter of 2013 to $1,321,482 for the same period in 2014.

South Timbalier 36/37

South Timbalier 36/37 crude oil revenues decreased from $109,539 in the second quarter of 2013 to $92,510 for the same period in 2014 due primarily to a decrease in the average crude oil price received from $111.85 per barrel in the second quarter of 2013 to $101.02 per barrel in the second quarter of 2014. In addition, there was a slight decrease in oil production volumes from 979 barrels in the second quarter of 2013 to 916 barrels in the second quarter of 2014. Gas revenues decreased from $8,319 in the second quarter of 2013 to $6,765 in the second quarter of 2014 due to a decrease in gas production from 2,388 Mcf in the second quarter of 2013 to 1,327 Mcf in the second quarter of 2014. The decrease in gas revenues caused by the decrease in gas production was partially offset by an increase in the average natural gas price received from $3.48 per Mcf in the second quarter of 2013 to $5.10 per Mcf in the second quarter of 2014. Capital expenditures decreased from $42,202 in the second quarter of 2013 to $1,698 in the second quarter of 2014. The costs in the second quarter of 2013 were primarily associated with facility improvements. Operating expenses increased from $20,778 in the second quarter of 2013 to $24,962 in the second quarter of 2014 due to maintenance repairs conducted during the second quarter of 2014.

Eugene Island 342

Production from Eugene Island 342 effectively ceased in the second quarter of 2011 because a third party pipeline from the field was shut in due to a leak. Following repairs to fix the leak, limited production resumed in July 2012. Including the impact of prior period adjustments, net crude oil revenues were $70,350 and net crude oil production was 704 barrels in the second quarter of 2014. Also including the impact of prior period adjustments, gas revenues were $9,692 and gas production was 2,445 Mcf in the second quarter of 2014. While there was no actual production of oil or gas from Eugene Island in the second quarter of 2013, as a result of prior period adjustments gas revenues of $8,937 were recorded in the second quarter of 2013. As the underlying interest in Eugene Island 342 is an overriding royalty interest, there were no capital or operating expenses recorded in the second quarter of 2014 and 2013.

Six Months Ended June 30, 2014 and 2013

Royalty Trust Comparison

Royalty income was $0 for the six months ended June 30, 2014 and 2013. Gross proceeds for the underlying Royalty Properties exceeded development and production costs by $2,278,477, or $341,771 attributable to the Trust, for the production period of November and December 2013 and January, February, March and April 2014 attributable to the six months ended June 30, 2014 and by $5,697,613, or $1,139,523 attributable to the Trust for the production period of December and January 2012 and January, February, March and April 2013 attributable to the six months ended June 30, 2013. The large fluctuation is primarily due to working interest audit adjustments, which impacted the production period attributable to the six months ended March 31, 2013. 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 protection, and as a result there was no royalty income for the six months ended June 30, 2014 and 2013.

General and administrative expenses for the Trust were $665,961 for the six months ended June 30, 2014 compared to $268,102 for the six months ended June 30, 2013. The increase is due to the timing

of the recording of expenses, of which $339,414 related to payment of the suspended Trustee fees paid in January 2014.

The reserve for future Trust expenses decreased $665,961 from December 31, 2013 to June 30, 2014 due to payments for Trust expenses.

There was no distributable income for each of the six months ended June 30, 2014 and June 30, 2013 and therefore no distributions to unit holders.

For the six months ended June 30, 2014 and June 30, 2013, the Trust had undistributed net income of $405,739 and $1,139,523, respectively, representing the Trust's portion of the undistributed net income of $2,278,477 and $5,697,613 associated with the Royalty Properties for the six months ended June 30, 2014 and 2013. The net income for the Royalty Properties for the production period of November and December 2012 and January, February, March and April 2013 reflects the benefit of an audit adjustment of Eugene Island 339, which resulted in additional proceeds of $1,869,919 for the six months ended June 30, 2013, as well as prior period adjustments for Eugene Island 342. For the six months ended June 30, 2014, net income for the Royalty Properties included additional proceeds of $72,443, net to the Trust, as a result of an audit adjustment for the Royalty Properties. The cumulative undistributed net loss for the Trust was $2,570,783 as of April 30, 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 is carried forward and offset, in future periods, by positive proceeds earned by the related Working Interest Owner(s). The Trust will not receive Net Proceeds until future proceeds from production exceed the total of the excess costs plus applicable accrued interest.

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

Gas revenues decreased $1,617,492, or 81%, to $384,831 in the first six months of 2014 from $2,002,323 in the first six months of 2013. The reduction is the result of working interest audit adjustments for Eugene Island 339 and Eugene Island 342, which resulted in additional proceeds of $1,884,307 for the first six months of 2013. Gas volumes during the first six months of 2014 decreased 30% to 97,802 Mcf from 139,442 Mcf in the first six months of 2013. The decrease in volumes is due primarily to the prior period working interest audit adjustment for Eugene Island 339 and, to a lesser extent, the prior period adjustment for Eugene Island 342. Excluding the impact of prior period adjustments, the average price received for natural gas increased approximately 33% from an average price, excluding adjustments, of $3.74 per Mcf in the first six months of 2013 to $5.00 per Mcf in the first six months of 2014. Also as a result of the adjustments, gas products volumes during the first six months of 2014 increased 137% to 119,892 gallons, compared to (323,661) gallons in the first six months of 2013.

Crude Oil and Condensate

Crude oil and condensate revenues decreased $1,788,818, or 24%, to $5,718,708 in the first six months of 2014 from $7,507,526 in the first six months of 2013. The reduction is primarily the result of working interest audit adjustments for Eugene Island 339 and Eugene Island 342, which resulted in additional proceeds of $852,014 for the first six months of 2013 and a decline in production for Ship Shoal 181/183 for the first six months of 2014. Oil volumes decreased 32% from 83,035 barrels in the first six months of 2013 to 56,425 barrels in the first six months of 2014. The decrease in volumes is due primarily to the decline in production for Ship Shoal 182/183 and the audit adjustment for Eugene Island 339 and, to a lesser extent, the adjustment for Eugene Island 342. Excluding the impact of prior period adjustments, the average price received for crude oil and condensate production decreased 4%, or $4.55, to $101.08 per barrel in the first six months of 2014 from $105.63 per barrel in the first six months of 2013.

Capital Expenditures

Capital expenditures decreased by $82,535, or 34%, from $240,112 in the first six months of 2013 to $157,577 in the first six months of 2014. The higher amount of capital expenditures during the first six months of 2013 relate primarily to facility improvement projects and drilling and completion costs associated with a well at Ship Shoal 182/183.

Production Expenses

Production expenses decreased by $256,412, or 8%, from $3,082,067 in the first six months of 2013 to $3,338,478 in the first six months of 2014.

Special Cost Escrow Account

In the first six months of 2014, there were no funds released from or escrowed into the Special Cost Escrow account. As of June 30, 2014, $1,000 remained in the Special Cost Escrow account. The funds held in the Special Cost Escrow account are not reflected in the condensed financial statements of the Trust. The Special Cost Escrow account is set aside for estimated abandonment costs and future capital expenditures, as provided for in the Conveyance. For additional information relating to the Special Cost Escrow account, see "—Special Cost Escrow Account" below.

Summary By Property

Listed below is a summary of operations of the principal Royalty Properties for the first six months of 2014 as compared to operations for the first six months of 2013 based on gross revenues generated during these periods combined.

Eugene Island 339

Eugene Island 339 net crude oil revenues decreased from $1,881,678 in the first six months of 2013 to $1,395,483 in the first six months of 2014, due to a decrease in net crude oil production from 29,385 barrels in the first six months of 2013 to 13,873 barrels in the first six months of 2014. Gas revenues decreased from $1,903,984 in the first six months of 2013 to $99,650 in the first six months of 2014, due to a decrease in gas production from 168,976 Mcf in the first six months of 2013 to 20,975 Mcf in the first six months of 2014. The decrease in volumes is primarily attributable to the benefit of the working interest audit adjustment of Eugene Island 339 being reflected in the first six months of 2013. While no

actual proceeds or revenues were received from Eugene Island 339 for the months of November and December 2012 and January 2013, the first six months of 2013 revenues and production include and reflect the benefit of a working interest audit adjustment of Eugene Island 339. Capital expenditures were $0 the first six months of 2014. Prior period adjustments to capital expenditures resulted in a benefit of $41,507 for the first six months of 2013. Operating expenses decreased from $297,505 in the first six months of 2013 to $56,407 in the first six months of 2014 due primarily to increased well and platform abandonment costs in the first six months of 2013 as compared to the first six months of 2014.

Ship Shoal 182/183

Ship Shoal 182/183 net crude oil revenues decreased from $5,337,565 in the first six months of 2013 to $4,009,097 in the first six months of 2014, due to a decrease in net crude oil production from 49,900 barrels in the first six months of 2013 to 39,430 barrels in the first six months of 2014. The decrease in volumes was primarily due to multiple shut ins for facility improvement projects during the first six months of 2014. There was also a decrease in the average crude oil price received from $106.97 per barrel in the first six months of 2013 to $101.68 per barrel for the same period in 2014. Gas revenues increased from $57,601 in the first six months of 2013 to $257,351 in the first six months of 2014, due to an increase in gas production from 14,678 Mcf in the first six months of 2013 to 49,814 Mcf in the first six months of 2014 as a result of the shut ins during the first six months of 2013. Gas revenues also increased due an increase in the average gas revenue price received from $3.92 per Mcf in the first six months of 2013 to $5.16 per Mcf for the same period in 2014. Capital expenditures decreased from $235,602 in the first six months of 2013 to $153,757 in the first six months of 2014. Operating expenses increased from $2,389,824 in the first six months of 2013 to $2,956,557 for the same period in 2014 due to several maintenance projects during the first six months of 2014.

South Timbalier 36/37

South Timbalier 36/37 crude oil revenues decreased from $215,753 in the first six months of 2013 to $184,098 for the same period in 2014 due primarily to a decrease in the average crude oil price received from $109.27 per barrel in the first six months of 2013 to $99.99 per barrel in the first six months of 2014. In addition, there was a slight decrease in oil production volumes from 1,975 barrels in the first six months of 2013 to 1,841 barrels in the first six months of 2014. Gas revenues increased from $16,809 in the first six months of 2013 to $18,139 in the first six months of 2014 due to an increase in the average natural gas price received from $3.45 per Mcf in the first six months of 2013 to $3.95 per Mcf in the first six months of 2014, partially offset by a decrease in gas production from 4,873Mcf in the first six months of 2013 to 4,586 Mcf in the first six months of 2014. Capital expenditures decreased from $46,017 in the first six months of 2013 to $3,820 in the first six months of 2014. The costs in the first six months of 2013 were primarily associated with facility improvements. Operating expenses increased from $35,263 in the first six months of 2013 to $43,076 in the first six months of 2014 due to maintenance repairs conducted during the first six months of 2014.

Eugene Island 342

Production from Eugene Island 342 effectively ceased in the first six months of 2011 because a third party pipeline from the field was shut in due to a leak. Following repairs to fix the leak, limited production resumed in July 2012. Net crude oil revenues were $130,031 and net crude oil production was 1,282 barrels in the first six months of 2014. While there was no actual production of oil or gas from Eugene Island in the first six months of 2013, as a result of prior period adjustments, net crude

oil revenues were $72,530 and net crude oil production was 1,776 barrels in the first six months of 2013. Gas revenues were $9,692 and gas production was 2,445 Mcf in the first six months of 2014, compared to gas revenues of $23,930 and gas production of 4,858 Mcf in the first six months of 2013 as a result of the prior period adjustments. As the underlying interest in Eugene Island 342 is an overriding royalty interest, there were no capital or operating expenses recorded in the first six months of 2014 and 2013.

Operations

The following operational information has been based on information provided to the Corporate Trustee by Chevron as the Managing General Partner of the Partnership. The Trustees have no control over these operations or internal controls relating to this information.

The platforms and wells on Eugene Island 339 were completely destroyed by Hurricane Ike in September 2008. Crude oil revenues from Eugene Island 339 represented approximately 48% of the crude oil and condensate revenues for the Royalty Properties in 2007 and approximately 47% of such revenues for the nine months ended September 30, 2008. Eugene Island 339 contributed approximately 12% of the revenues from natural gas sales from the Royalty Properties in 2007 and approximately 41% of such revenues for the nine months ended September 30, 2008. Based on a prior year reserve study prepared by DeGolyer and MacNaughton, independent petroleum engineering consultants, Eugene Island 339 accounted for approximately 34% of the total future net revenues attributable to the Partnership's interest in the Royalty as of October 31, 2007.

Chevron has completed the work associated with the wells on Eugene Island 339 and informed the Trust that the estimate of 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. No further expenses are expected to be incurred.

Generally, if production ceases from an outer continental shelf lease, like that for Eugene Island 339, production must be restored or drilling operations must commence within 180 days of the cessation of production (which was in early March 2009 with respect to Eugene Island 339 given the cessation of production in September 2008 resulting from Hurricane Ike), or the lease will be terminated. Alternatively, an operator of a lease may seek an SOP, that, if approved by the regional supervisor of the BOEM allows additional time to restore production in the event of certain circumstances, such as hurricanes and other events beyond the control of the operator. Although Chevron successfully obtained a series of SOPs and, with the participation of Arena, obtained additional SOPs resulting in the restoration of limited production at Eugene Island 339, other Working Interest Owners have been unable to timely restore production or obtain an SOP and as a result, many of the leases covering the Royalty Properties have been terminated or expired thereby reducing the proceeds payable to the Trust.

On December 15, 2009, Chevron entered into the Arena Agreement with Arena to assist in the redevelopment as a farmout of portions of Eugene Island 338 and 339. Pursuant to the terms of the Arena Agreement, Arena could earn an assignment of 65% of Chevron's working interests in Eugene Island 338 and Eugene Island 339. Chevron holds a 50% interest in Eugene Island 339, which interest is included in the 5500' and the 4500' sand units; 42.05% of all production from the 5500' sand unit is allocated to Eugene Island 339 and 38.50% of the gas production and 24.44% of the oil production from the 4500' sand unit is allocated to Eugene Island 339. Pursuant to the terms of the Conveyance, Chevron may enter into a farmout agreement whereby Chevron assigns any portion of its interest in the Royalty Properties free and clear of the Original Royalty, and the Original Royalty will be reduced in the same proportion as that in which the Royalty Property is reduced. Under the terms of the Conveyance, a "farmout agreement" is defined as an agreement with a third party requiring or permitting the performance of drilling or development operations on a Royalty Property, and for which all or substantially all of the consideration is the transfer of an interest in a Royalty Property. On August 4, 2012, Arena completed installation of the remaining topside decks of the structure and on August 16, 2012, Arena commenced mobilization of the H&P 100 platform rig components. On September 28, 2012, Arena spud the OCS-G 2318 Well No. K002 and production from this well was realized in the fourth quarter of 2012. Pursuant to the terms of the Arena Agreement, following completion of the well and the other drilling and development operations, 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 has been reduced proportionately. As a result of such assignment, the Royalty held by the Partnership on Eugene Island 339 has been reduced by 65%.

Production at Ship Shoal 182/183 ceased following damage inflicted by Hurricane Ike in September 2008. While the hurricane caused limited surface damage to the facilities at Ship Shoal 182/183, all of the wells at Ship Shoal 182/183 were shut-in following hurricane-related damage to a third-party transporter's natural gas pipeline. Crude oil revenues from Ship Shoal 182/183 represented approximately 50% of the crude oil and condensate revenues for the Royalty Properties in 2007 and approximately 51% of such revenues for the nine months ended September 30, 2008. Ship Shoal 182/183 contributed approximately 77% of the revenues from natural gas sales from the Royalty Properties in 2007 and approximately 42% of such revenues for the nine months ended September 30, 2008. A limited volume of oil production was restored in November 2008. The volume of oil production that can be produced is limited by the amount of gas that is also produced by the oil wells. The third-party transporter's natural gas pipeline repairs were completed and gas sales at Ship Shoal 182/183 were restored on June 26, 2009. However, the pipeline was shut down in mid-September 2009 for additional repairs. Production sales for both oil and natural gas at Ship Shoal 182 and 183 were restored on October 8, 2009 following completion of such additional repairs. Oil and gas production at Ship Shoal 182/183 ceased in March 2010 due to a leak in the oil pipeline that services Ship Shoal 182/183. Such oil pipeline was subsequently repaired and Ship Shoal 182/183 was reopened on May 1, 2010 after a 36-day shut- in. In November 2010, the platform at Ship Shoal 182/183 was shut-in for a scheduled tank replacement and production has slowly returned thereafter. Production was shut-in on multiple occasions during 2012 and 2013 for various facility improvement projects during which time production was temporarily impacted.

Overview of Production, Prices and Royalty Income

The following schedule provides a summary of the volumes and weighted average prices for crude oil and condensate and natural gas recorded by the Working Interest Owners for the Royalty Properties, as well as the Working Interest Owners' calculations of the Net Proceeds and Royalties paid to the Trust during the periods indicated. The following information for the three-and six-month periods ended June 30, 2014 includes the effect of the audit adjustments of Eugene Island 339 and Eugene Island 342.

	Royalty Properties Three Months Ended June 30,(1)						Royalty Properties Six Months Ended June 30,(1)

	2014			2013			2014			2013
Crude oil and condensate (bbls)		33,858			33,195			56,425			83,035
Natural gas and gas products (Mcfe)		68,575			25,254			97,802			139,442
Crude oil and condensate average price, per bbl(2)	$	102.50		$	110.10		$	101.35		$	90.41
Natural gas average price, per Mcf (excluding gas products)(3)	$	5.11		$	3.78		$	4.95		$	10.35
Crude oil and condensate revenues	$	3,470,334		$	3,654,793		$	5,718,708		$	7,507,526
Natural gas and gas products revenues		347,610			103,616			482,279			1,512,267
Production expenses		(1,523,523	)		(1,690,543	)		(3,338,478	)		(3,082,067	)
Capital expenditures		(15,943	)		(74,103	)		(157,577	)		(240,112	)
Interest
Undistributed net loss (income)(4)		(2,278,477	)		(1,993,763	)		(2,704,931	)		(5,697,613	)
Refund of (provision for) Special Cost Escrow		—			—			—			—


Net Proceeds		—			—			—			—
Royalty interest		X15	%		x20	%		X15	%		x20	%


Partnership share		—			—			—			—
Trust interest		x99.99	%		x99.99	%		x99.99	%		x99.99	%


Trust share of Royalty Income(5)	$	—		$	—		$	—		$	—

(1): Amounts are based on production for the three- and six-month periods ended April 30 of each year, respectively, and include the results of the adjustments for Eugene Island 339 and Eugene Island 342.
(2): Excluding the adjustments, the average price for the three months ended June 30, 2014 and 2013 was $102.52 and $110.83, respectively, and for the six months ended June 30, 2014 and 2013 was $101.08 and $105.63, respectively.

(3): Excluding the adjustments, the average price for the three months ended June 30, 2014 and 2013 was $5.16 and $3.69, respectively, and for the six months ended June 30, 2014 and 2013 was $5.00 and $3.74, respectively.
(4): 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 is carried forward and offset, in future periods, by positive proceeds earned by the related Working Interest Owner(s). The Trust will not receive Net Proceeds until future proceeds from production exceed the total of the excess costs plus applicable accrued interest. Undistributed net income represents positive Net Proceeds, generated during the respective period, but not distributed by the Working Interest Owners.
(5): See "Trustee's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources" and Note 4 to the Notes to the Condensed Financial Statements under Item 1 of Part I of this Form 10-Q for a discussion regarding uncertainty of distributions.

Critical Accounting Policies

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

(a): Royalty income from the overriding royalty interest is recorded when received, including the effect of overtaken or undertaken positions and negative or positive adjustments, by the Corporate Trustee on the last business day of each calendar quarter. In addition, Royalty income includes amounts related to funds deposited or released from the Special Cost Escrow account—see (d);
(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 are recorded at the time of payment or receipt. The Special Cost Escrow account is an account of the Working Interest Owners and is not reflected in the condensed financial statements of the Trust;
(e): Amortization of the investment in overriding royalty interest is calculated based on the units-of-production method. Such amortization is charged directly to Trust corpus and does not affect distributable income; and
(f): Proceeds from loans used to pay for Trust expenses is charged directly to Trust corpus.

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.

Impairment of Investment in Overriding Royalty Interest. The Trust reviews net overriding royalty interests in oil and gas properties for possible impairment whenever events or circumstances indicate the carrying amount of the asset may not be recoverable. If there is an indication of impairment, the Trust prepares an estimate of future cash flows (undiscounted and without interest charges) expected to result from the use of the asset and its eventual disposition. If these cash flows are less than the carrying amount of the asset, an impairment loss is recognized to write down the asset to its estimated fair value. Preparation of estimated expected future cash flows is inherently subjective and is based on the Corporate Trustee's best estimate of assumptions concerning expected future conditions. There were no write downs taken in the periods presented.

New Accounting Pronouncements

There were no accounting pronouncements issued during the three months ended June 30, 2014 applicable to the Trust or its condensed financial statements.

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.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

The only assets of and sources of income to the Trust are cash and the Trust's interest in the Partnership, which is the holder of the Royalty. Consequently, the Trust is exposed to market risk associated with the Royalty from fluctuations in oil and gas prices. Reference is also made to Note 2 of the Notes to Condensed Financial Statements included in Item 1 of this Form 10-Q.

The Trust may borrow money to pay expenses of the Trust. Additionally, if development and production costs of the Royalty exceed the proceeds of production from the Royalty Properties, the Trust will not receive Net Proceeds until future proceeds from production exceed the total of the excess costs plus accrued interest, at a rate equal to one-fourth of (i) one-half of one percent plus (ii) the median between the prime interest rate at the end of a quarterly period in which there are excess costs and the prime interest rate at the end of the preceding quarterly period, during the deficit period. Consequently, the Trust will be exposed to interest rate market risk should it borrow money to pay expenses and to the extent that development and production costs of the Royalty exceed the proceeds of production from the Royalty Properties.

Item 4. Controls and Procedures.

Evaluation of disclosure controls and procedures. The Corporate Trustee maintains disclosure controls and procedures designed to ensure that information required 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 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. Michael J. 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" and "The Trustees rely upon the Working Interest Owners and Managing General

Partner for information regarding the Royalty Properties" in the 2013 Form 10-K for a description of certain risks relating to these arrangements and reliance on 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 three months ended June 30, 2014, 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. The Corporate Trustee notes for purposes of clarification that it has no authority over, and makes no statement concerning, the internal control over financial reporting of the Working Interest Owners or the Managing General Partner of the Partnership.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings.

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 requests the Court to 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 unitholder 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 are 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 Trust's unitholders; and, to, thereafter terminate the Partnership and the Trust. There can be no assurances whether the Court will grant the requested relief and, if such relief is granted, when such actions will be completed.

Item 1A. Risk Factors.

The Trust may not receive a favorable result in the Probate Proceeding and the costs and expenses could further reduce the funds held by the Trust.

The goals of the Probate Proceeding are to permit the Partnership to sell the Royalty; to distribute the net proceeds, if any, from such sale to the unitholders; and, terminate the Trust. If the Court does not grant the requested relief, the Trust will continue to face ongoing costs and expenses without any assurances of distributions to pay such costs and expenses. In addition, the costs and expenses of the Probate Proceeding will accelerate the expenditure of the Trust's current cash reserve and may cause the Trust to incur additional indebtedness to pay such costs and expenses.

Even if the Trust is permitted to sell the remaining Royalty, there is no assurance that there will be any funds available for distribution to the unitholders.

There is a very limited market for the Royalty, as indicated in the previous sales of portions of the Original Royalty, and the Trustees are unable to predict the amount that may be paid for the remaining Royalty. In addition, the Trust will be required to pay its liabilities before any proceeds from the sale of the Royalty are distributed. These liabilities will include the ongoing costs and expense of the Trust as well as the costs and expenses incurred in the Probate Proceeding, which may include additional indebtedness incurred by the Trust to pay such costs and expenses. Accordingly, there can be no assurances as to the amount, if any, of the proceeds that will be available for distribution to the Trust's unitholders.

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 significantly decreased since the filing of the Probate Proceeding was announced. As developments occur in the Probate Proceeding, these 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 unitholders 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.

Item 6. Exhibits.

(Asterisk indicates exhibit previously filed with the Securities and Exchange Commission and incorporated herein by reference.)



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 the year ended December 31, 1992 of TEL Offshore Trust)	0-06910	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)	0-06910	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)	0-06910	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)	0-06910	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 the year ended December 31, 1992 of TEL Offshore Trust)	0-06910	4(e	)
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)	0-06910	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)	0-06910	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)	0-06910	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)	0-06910	10(d	)
31	—	Certification furnished pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32	—	Certification furnished pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

SIGNATURES

Pursuant to the requirements 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.


		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

Date: August 14, 2014

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.

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NOTE REGARDING FORWARD-LOOKING STATEMENTS
PART I—FINANCIAL INFORMATION

Item 1. Condensed Financial Statements.

TEL OFFSHORE TRUST CONDENSED STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS (UNAUDITED)
TEL OFFSHORE TRUST CONDENSED STATEMENTS OF DISTRIBUTABLE INCOME (UNAUDITED)
TEL OFFSHORE TRUST CONDENSED STATEMENTS OF CHANGES IN TRUST CORPUS (UNAUDITED)
TEL OFFSHORE TRUST NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED)

Item 2. Trustee's Discussion and Analysis of Financial Condition and Results of Operations.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Item 4. Controls and Procedures.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings.

Item 1A. Risk Factors.

Item 6. Exhibits.

SIGNATURES

Attached files

TEL OFFSHORE TRUST Reports

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