Permianville Royalty Trust - Quarter Report: 2013 June (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

For the quarterly period ended June 30, 2013

OR

For the transition period from                      to                     

Commission File Number: 001-35333

ENDURO ROYALTY TRUST

(Exact name of registrant as specified in its charter)

1-800-852-1422

(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  x    No  ¨

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  ¨    No  ¨

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.

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

As of August 5, 2013, 33,000,000 units of beneficial interest in Enduro Royalty Trust were outstanding.

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GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS

The following are definitions of significant terms used in this report.

Bbl—One stock tank barrel of 42 U.S. gallons liquid volume, used herein in reference to crude oil and other liquid hydrocarbons.

Boe—One stock tank barrel of oil equivalent, computed on an approximate energy equivalent basis that one Bbl of crude oil equals approximately six Mcf of natural gas.

Btu—A British Thermal Unit, a common unit of energy measurement.

Completion—The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Development Well—A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Differential—The difference between a benchmark price of oil and natural gas, such as the NYMEX crude oil spot, and the wellhead price received.

Estimated future net revenues—Also referred to as “estimated future net cash flows”. The result of applying current prices of oil and natural gas to estimated future production from oil and natural gas proved reserves, reduced by estimated future expenditures, based on current costs to be incurred, in developing and producing the proved reserves, excluding overhead.

Farm-in or farm-out agreement—An agreement under which the owner of a working interest in an oil or natural gas lease typically assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out.”

Field—An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gross acres or gross wells—The total acres or wells, as the case may be, in which a working interest is owned.

Horizontal well—A well that starts off being drilled vertically but which is eventually curved to become horizontal (or near horizontal) in order to parallel a particular geologic formation.

MBbl—One thousand barrels of crude oil or condensate.

MBoe—One thousand barrels of oil equivalent.

Mcf—One thousand cubic feet of natural gas.

MMBoe—One million barrels of oil equivalent.

MMBtu—One million British Thermal Units.

MMcf—One million cubic feet of natural gas.

Net acres or net wells—The sum of the fractional working interests owned in gross acres or wells, as the case may be.

Net profits interest—A nonoperating interest that creates a share in gross production from an operating or working interest in oil and natural gas properties. The share is measured by net profits from the sale of production after deducting costs associated with that production.

Net revenue interest—An interest in all oil and natural gas produced and saved from, or attributable to, a particular property, net of all royalties, overriding royalties, net profits interests, carried interests, reversionary interests and any other burdens to which the person’s interest is subject.

NYMEX—New York Mercantile Exchange.

NYSE—New York Stock Exchange.

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Plugging and abandonment—Activities to remove production equipment and seal off a well at the end of a well’s economic life.

Proved developed reserves—Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved reserves—Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, LKH, as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil, HKO, elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved undeveloped reserves—Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

PV-10—The present value of estimated future net revenues to be generated from the production of proved reserves, net of estimated future production and development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to income taxes, discounted at 10% per annum.

Recompletion—The completion for production of an existing wellbore in another formation from which that well has been previously completed.

Reservoir—A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Working interest—The right granted to the lessee of a property to explore for and to produce and own oil, gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

Workover—Operations on a producing well to restore or increase production.

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PART I—FINANCIAL INFORMATION

ENDURO ROYALTY TRUST

Statements of Assets, Liabilities and Trust Corpus

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

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ENDURO ROYALTY TRUST

Statements of Distributable Income

(unaudited)

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

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ENDURO ROYALTY TRUST

Statements of Changes in Trust Corpus

(unaudited)

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

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ENDURO ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS

(unaudited)

Formation of the Trust

Enduro Royalty Trust (the “Trust”) is a Delaware statutory trust formed in May 2011 pursuant to a trust agreement (the “Trust Agreement”) among Enduro Resource Partners LLC (“Enduro”), as trustor, The Bank of New York Mellon Trust Company, N.A. (the “Trustee”), as trustee, and Wilmington Trust Company (the “Delaware Trustee”), as Delaware Trustee.

The Trust was created to acquire and hold for the benefit of the Trust unitholders a net profits interest representing the right to receive 80% of the net profits from the sale of oil and natural gas production from certain properties in the states of Texas, Louisiana and New Mexico held by Enduro as of the date of the conveyance of the net profits interest to the Trust (the “Net Profits Interest”). The properties in which the Trust holds the Net Profits Interest are referred to as the “Underlying Properties.” Enduro is a Delaware limited liability company engaged in the production and development of oil and natural gas from properties located in the Rockies, the Permian Basin of west Texas and southeastern New Mexico, east Texas and north Louisiana.

The Net Profits Interest is passive in nature and neither the Trust nor the Trustee has any management control over or responsibility for costs relating to the operation of the Underlying Properties. The Trust is not subject to any pre-set termination provisions based on a maximum volume of oil or natural gas to be produced or the passage of time. The Trust will dissolve upon the earliest to occur of the following:

The Trustee may create a cash reserve to pay for future liabilities of the Trust and may authorize the Trust to borrow money to pay administrative or incidental expenses of the Trust that exceed its cash on hand and available reserves. At June 30, 2013, the Trust had $40,322 of cash and cash equivalents, a decrease of $154,216 from the December 31, 2012 cash and cash equivalents balance of $194,538. The Trustee may authorize the Trust to borrow from any person, including the Trustee, the Delaware Trustee or an affiliate thereof, although none of the Trustee, the Delaware Trustee or any affiliate of either of them intends to lend funds to the Trust. The Trustee may also cause the Trust to mortgage its assets to secure payment of the indebtedness. The terms of such indebtedness and security interest, if funds were loaned by the entity serving as Trustee or Delaware Trustee or an affiliate thereof, would be similar to the terms which such entity would grant to a similarly situated commercial customer with whom it did not have a fiduciary relationship. Under the terms of the Trust Agreement, Enduro provided the Trust with a $1.0 million letter of credit to be used by the Trust in the event that its cash on hand (including available cash reserves) is not sufficient to pay ordinary course administrative expenses. If the Trust requires more than the $1.0 million under the letter of credit to pay administrative expenses, Enduro has agreed to loan funds to the Trust necessary to pay such expenses. If the Trust borrows funds, draws on the letter of credit or Enduro loans funds to the Trust, no further distributions will be made to Trust unitholders until such amounts borrowed or drawn are repaid. Since its formation, the Trust has not borrowed any funds and no amounts have been drawn on the letter of credit.

Each month, the Trustee pays Trust obligations and expenses and distributes to Trust unitholders the remaining proceeds received from the Net Profits Interest. The cash held by the Trustee as a reserve against future liabilities or for distribution at the next distribution date must be invested in:

Alternatively, cash held for distribution at the next distribution date may be held in a noninterest-bearing account. At June 30, 2013 and December 31, 2012, the Trust did not have any cash on hand related to future distributions.

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ENDURO ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS—Continued

(unaudited)

Net Profits Interest Conveyance and Initial Public Offering

On November 8, 2011, Enduro conveyed to the Trust, through the merger of a wholly owned subsidiary of Enduro with the Trust, the Net Profits Interest in exchange for 33,000,000 units of beneficial interest in the Trust (the “Trust Units”). Immediately following the conveyance, Enduro completed an initial public offering of 13,200,000 Trust Units. After the completion of the initial public offering and as of June 30, 2013 and December 31, 2012, Enduro owned 19,800,000 Trust Units, or 60% of the issued and outstanding Trust Units.

The accompanying Statement of Assets, Liabilities and Trust Corpus as of December 31, 2012 which has been derived from audited financial statements, and the unaudited interim financial statements as of June 30, 2013 and for the three and six months ended June 30, 2013 and 2012 have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Accordingly, certain information and disclosures normally included in annual financial statements have been condensed or omitted pursuant to those rules and regulations. Therefore, these financial statements should be read in conjunction with the financial statements and notes thereto included in the Trust’s 2012 Annual Report on Form 10-K.

In the opinion of the Trustee, the accompanying unaudited financial statements reflect all adjustments that are necessary for a fair presentation of the interim periods presented and include all the disclosures necessary to make the information presented not misleading.

The preparation of financial statements requires the Trustee to make estimates and assumptions that affect reported amounts of assets and liabilities and the reported amounts of revenues and expenses during the reporting period. Although the Trustee believes that these estimates are reasonable, actual results could differ from those estimates.

The Trust uses the modified cash basis of accounting to report Trust receipts of the Net Profits Interest and payments of expenses incurred. The Net Profits Interest represents the right to receive revenues (oil and natural gas sales), less direct operating expenses (lease operating expenses and production and property taxes) and development expenses of the Underlying Properties plus any payments made or net payments received in connection with the settlement of certain hedge contracts, multiplied by 80%. Cash distributions of the Trust are made based on the amount of cash received by the Trust pursuant to terms of the conveyance creating the Net Profits Interest.

Under the terms of the conveyance, the monthly Net Profits Interest calculation includes oil and natural gas revenues received as well as cash settlements for applicable hedge contracts received by Enduro during the relevant month. Monthly operating expenses and capital expenditures represent incurred expenses, and as a result, represent accrued expenses as well as expenses paid during the period.

The financial statements of the Trust are prepared on the following basis:

(a) Income from Net Profits Interest is recorded when distributions are received by the Trust;

(b) Distributions to Trust unitholders are recorded when paid by the Trust;

(c) Trust general and administrative expenses (which includes the Trustee’s fees as well as accounting, engineering, legal, and other professional fees) are recorded when paid;

(d) Cash reserves for Trust expenses may be established by the Trustee for certain future expenditures that would not be recorded as contingent liabilities under accounting principles generally accepted in the United States of America (“GAAP”);

(e) Amortization of the Net Profits Interest in oil and natural gas properties is calculated on a unit-of-production basis and is charged directly to Trust corpus; and

(f) The Net Profits Interest in oil and natural gas properties is periodically assessed whenever events or circumstances indicate that the aggregate value may have been impaired below its total capitalized cost based on the Underlying Properties. If an impairment loss is indicated by the carrying amount of the assets exceeding the sum of the undiscounted expected future net cash flows of the Net Profits Interest, then an impairment loss is recognized for the amount by which the carrying amount of the asset exceeds its estimated fair value determined using discounted cash flows.

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ENDURO ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS—Continued

(unaudited)

The financial statements of the Trust differ from financial statements prepared in accordance with GAAP because revenues are not accrued in the month of production; general and administrative expenses are recorded when paid instead of when incurred; cash reserves may be established for contingencies which would not be accrued in financial statements prepared in accordance with GAAP; and amortization of the net profits interest calculated on a unit-of-production basis is charged directly to trust corpus instead of as an expense. While these statements differ from financial statements prepared in accordance with GAAP, the modified cash basis of reporting revenues, expenses, and distributions is considered to be the most meaningful because monthly distributions to the Trust unitholders are based on net cash receipts.

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.

New Accounting Pronouncements

As the Trust’s financial statements are prepared on the modified cash basis, most accounting pronouncements are not applicable to the Trust’s financial statements. No new accounting pronouncements have been adopted or issued that would impact the financial statements of the Trust.

The Net Profits Interest in oil and natural gas properties was recorded at its fair value on the date of conveyance. Amortization of the Net Profits Interest in oil and natural gas properties is calculated on a unit-of-production basis based on the Underlying Properties’ production and reserves. Accumulated amortization as of June 30, 2013 and December 31, 2012 was $125,279,977 and $88,349,261, respectively.

The Trust is exposed to fluctuations in energy prices in the normal course of business due to the Net Profits Interest in the Underlying Properties. The revenues derived from the Underlying Properties depend substantially on prevailing crude oil prices and, to a lesser extent, natural gas prices. As a result, commodity prices affect the amount of cash flow available for distribution to the Trust unitholders. Lower prices may also reduce the amount of oil and natural gas that Enduro and its third party operators can economically produce. To mitigate the negative effects of a possible decline in oil and natural gas prices on distributable income to the Trust and to achieve more predictable cash flows, Enduro entered into hedge contracts with respect to approximately 41% and 67% of expected oil and natural gas production, respectively, for 2013 from the total proved reserves attributable to the Underlying Properties as of December 31, 2012. These hedge contracts include a combination of fixed price swaps, collars and floors. These contracts reduce the exposure of the revenues from oil and natural gas production from the Underlying Properties; however, these contracts also limit the amount of cash available for distribution if prices increase above the fixed hedge price. For production periods after December 31, 2013, none of the production attributable to the Underlying Properties will be hedged.

The following table sets forth the volumes of Enduro’s natural gas commodity derivative contracts related to the Underlying Properties, the weighted average contractual prices per Mcf, and the weighted average NYMEX equivalent prices per Mcf as of June 30, 2013:

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ENDURO ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS—Continued

(unaudited)

The following table sets forth the volumes of Enduro’s oil commodity derivative contracts related to the Underlying Properties and the weighted average NYMEX prices per Bbl as of June 30, 2013:

The amounts received by Enduro from the hedge contract counterparties upon settlement of the hedge contracts reduce the operating expenses related to the Underlying Properties in calculating net profits. In addition, the aggregate amounts paid by Enduro on settlement of the hedge contracts related to the Underlying Properties reduce the amount of net profits paid to the Trust.

Federal Income Taxes

For federal income tax purposes, the Trust is a grantor trust and therefore is not subject to tax at the trust level. Trust unitholders are treated as owning a direct interest in the assets of the Trust, and each Trust unitholder is taxed directly on his pro rata share of the income and gain attributable to the assets of the Trust and entitled to claim his pro rata share of the deductions and expenses attributable to the assets of the Trust. The income of the Trust is deemed to have been received or accrued by each unitholder at the time such income is received or accrued by the Trust rather than when distributed by the Trust.

The deductions of the Trust consist of severance taxes and administrative expenses. In addition, each unitholder is entitled to depletion deductions because the Net Profits Interest constitutes “economic interests” in oil and gas properties for federal income tax purposes. Each unitholder is entitled to amortize the cost of the Trust Units through cost depletion over the life of the Net Profits Interest or, if greater, through percentage depletion. Unlike cost depletion, percentage depletion is not limited to a unitholder’s depletable tax basis in the Trust Units. Rather, a unitholder is entitled to percentage depletion as long as the applicable Underlying Properties generate gross income.

Some Trust Units are held by a middleman, as such term is broadly defined in U.S. Treasury Regulations (and includes custodians, nominees, certain joint owners, and brokers holding an interest for a custodian in street name). Therefore, the Trustee considers the Trust to be a non-mortgage widely held fixed investment trust (“WHFIT”) for U.S. federal income tax purposes. The Bank of New York Mellon Trust Company, N.A., 919 Congress Avenue, Austin, Texas 78701, telephone number (512) 236-6545, is the representative of the Trust that will provide tax information in accordance with applicable U.S. Treasury Regulations governing the information reporting requirements of the Trust as a WHFIT. Tax information is also posted by the trustee at www.enduroroyaltytrust.com. Notwithstanding the foregoing, the middlemen holding units on behalf of unitholders, and not the Trustee of the Trust, are solely responsible for complying with the information reporting requirements under the U.S. Treasury Regulations with respect to such units, including the issuance of IRS Forms 1099 and certain written tax statements. Unitholders whose units are held by middlemen should consult with such middlemen regarding the information that will be reported to them by the middlemen with respect to the Trust Units.

The tax consequences to a unitholder of ownership of Trust Units will depend in part on the unitholder’s tax circumstances. Unitholders should consult their tax advisors about the federal tax consequences relating to owning the Trust Units.

State Taxes

The Trust’s revenues are from sources in the states of Louisiana, New Mexico and Texas. Because it distributes all of its net income to unitholders, the Trust should not be taxed at the trust level in Louisiana or New Mexico. While the Trust should not owe tax, the Trustee is required to file a return with Louisiana reflecting the income and deductions of the Trust attributable to properties located in that state. Texas does not impose a state income tax, so the Trust’s income will not be subject to income tax at the trust level in Texas. Louisiana and New Mexico presently have income taxes which tax income of nonresidents from real property located within that state. Louisiana and New Mexico tax nonresidents on royalty income from the royalties located in that state. Louisiana and New Mexico also impose a corporate income tax which may apply to unitholders organized as corporations.

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ENDURO ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS—Continued

(unaudited)

Texas imposes a franchise tax at a rate of 1% on gross revenues less certain deductions, as specifically set forth in the Texas franchise tax statutes. Entities subject to tax generally include trusts unless otherwise exempt. Trusts that receive at least 90% of their federal gross income from designated passive sources, including royalties from mineral properties and other income from other non-operating mineral interests, and do not receive more than 10% of their income from operating an active trade or business, generally are exempt from the Texas franchise tax as “passive entities.” While the Trust is intended to be exempt from Texas franchise tax at the Trust level as a passive entity, each unitholder that is considered a taxable entity under the Texas franchise tax would generally be required to include its portion of Trust net income in its own Texas franchise tax computation.

Each unitholder should consult his or her own tax advisor regarding state tax requirements, if any, applicable to such person’s ownership of Trust Units.

Each month, the Trustee determines the amount of funds available for distribution to the Trust unitholders. Available funds are the excess cash, if any, received by the Trust from the Net Profits Interest and other sources (such as interest earned on any amounts reserved by the Trustee) that month, over the Trust’s liabilities for that month, subject to adjustments for changes made by the Trustee during the month in any cash reserves established for future liabilities of the Trust. Distributions are made to the holders of Trust Units as of the applicable record date (generally the last business day of each calendar month) and are payable on or before the 10th business day after the record date.

The following table provides information regarding the Trust’s distributions paid during the six months ended June 30, 2013 and 2012:

Under the terms of the Trust Agreement, the Trust pays an annual administrative fee of $200,000 to the Trustee and $2,000 to the Delaware Trustee. In addition, the Trust paid an initial acceptance fee of $10,000 to the Trustee and $1,500 to the Delaware Trustee for the first year of service. During the three and six months ended June 30, 2013, the Trust paid $50,000 and $100,451 respectively, to the Trustee pursuant to the terms of the Trust Agreement. The Trust did not pay any fees to the Delaware Trustee for the three and six months ended June 30, 2013. For the three and six months ended June 30, 2012, the Trust paid $50,000 and $110,000, respectively, to the Trustee and $0 and $3,500, respectively, to the Delaware Trustee pursuant to the terms of the Trust Agreement.

The Trust is party to a registration rights agreement pursuant to which the Trust has agreed, for the benefit of Enduro and any transferee of Enduro’s Trust Units, to register the trust units they hold. On May 24, 2013, pursuant to the registration rights agreement, the Trust filed a registration statement on Form S-3 registering the offering by Enduro of 19,800,000 Trust Units. The registration statement became effective on June 10, 2013. Enduro will bear all costs and expenses incidental to the registration statement, excluding certain internal expenses of the Trust, which will be borne by the Trust. Any underwriting discounts and commissions will be borne by the seller of the Trust Units.

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ENDURO ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS—Continued

(unaudited)

On July 15, 2013, the distribution of $0.128817 per Trust Unit, which was declared on June 18, 2013, was paid to Trust unitholders owning Trust Units as of June 28, 2013. The distribution consisted of net profits allocable to the Trust of $4,300,956, less cash reserves withheld for future Trust expenses of approximately $50,000.

On July 19, 2013, the Trust declared a distribution of $0.133930 per unit to unitholders of record as of July 31, 2013. The distribution is expected to be paid to unitholders on August 14, 2013.

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References to the “Trust” in this document refer to Enduro Royalty Trust while references to “Enduro” in this document refer to Enduro Resource Partners LLC.

The following review of the Trust’s financial condition and results of operations should be read in conjunction with the financial statements and notes thereto, as well as Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Trust’s 2012 Annual Report on Form 10-K. The Trust’s Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all other filings with the SEC are available on the SEC’s website at www.sec.gov.

Forward-Looking Statements

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 fact included in this Form 10-Q, including without limitation the statements under “Trustee’s Discussion and Analysis of Financial Condition and Results of Operations” are forward-looking statements. Such statements may be influenced by factors that could cause actual outcomes and results to differ materially from those projected. No assurance can be given that such expectations will prove to have been correct. When used in this document, the words “believes,” “expects,” “anticipates,” “intends” or similar expressions are intended to identify such forward-looking statements. The following important factors, in addition to those discussed elsewhere in this Form 10-Q, could affect the future results of the energy industry in general, and Enduro and the Trust in particular, and could cause actual results to differ materially from those expressed in such forward-looking statements:

You should not place undue reliance on these forward-looking statements. All forward-looking statements speak only as of the date of this Form 10-Q. The Trust does not undertake any obligation to release publicly any revisions to the forward-looking statements to reflect events or circumstances after the date of this Form 10-Q or to reflect the occurrence of unanticipated events, unless the securities laws require us to do so.

This Form 10-Q describes other important factors that could cause actual results to differ materially from expectations of Enduro and the Trust, including under the caption “Risk Factors.” All subsequent written and oral forward-looking statements attributable to Enduro or the Trust or persons acting on behalf of Enduro 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.

Overview

The Trust is a statutory trust created under the Delaware Statutory Trust Act in May 2011. The business and affairs of the Trust are administered by the Trustee. The Trustee has no authority over or responsibility for, and no involvement with, any aspect of the oil and gas operations or other activities on the Underlying Properties. The Delaware Trustee has only minimal rights and duties that are necessary to satisfy the requirements of the Delaware Statutory Trust Act.

In connection with the closing of the Trust’s initial public offering, on November 8, 2011, Enduro contributed the Net Profits Interest to the Trust in exchange for 33,000,000 newly issued Trust Units. The Net Profits Interest entitles the Trust to receive 80% of the net profits from the sale and production of oil and natural gas attributable to the Underlying Properties that are produced during the term of the Conveyance, which commenced on July 1, 2011.

The Trust is not subject to any pre-set termination provisions based on a maximum volume of oil or natural gas to be produced or the passage of time. The Trust will dissolve upon the earliest to occur of the following: (1) the Trust, upon approval of the holders of at least 75% of the outstanding Trust Units, sells the Net Profits Interest, (2) the annual cash proceeds received by the Trust attributable to the Net Profits Interest are less than $2 million for each of any two consecutive years, (3) the holders of at least 75% of the outstanding Trust Units vote in favor of dissolution or (4) the Trust is judicially dissolved.

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The Trust is required to make monthly cash distributions of substantially all of its monthly cash receipts, after deducting the Trust’s administrative expenses, to holders of record (generally the last business day of each calendar month) on or before the 10^th business day after the record date.

The amount of Trust revenues and cash distributions to Trust unitholders depends on, among other things:

Generally, cash payment is received by Enduro for oil production 30 to 60 days after it is produced and for natural gas production 60 to 90 days after it is produced.

Results of Operations

Three Months Ended June 30, 2013 Compared to Three Months Ended June 30, 2012

The Trust’s net profits income consists of monthly net profits attributable to the Net Profits Interest. Net profits income for the three months ended June 30, 2013 and 2012 was determined as shown in the following table:

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The following table displays oil and natural gas sales volumes and average prices (excluding the effects of the hedging arrangements discussed in Note 4 of the Notes to Financial Statements) from the Underlying Properties, representing the amounts included in the Net Profits Interest calculation for distributions paid during the three months ended June 30, 2013 and 2012:

Net profits income received by the Trust amounted to $9.3 million for the quarter ended June 30, 2013, a decrease of $5.9 million, or 39%, from the $15.2 million for the second quarter of 2012. The decrease was due to a reduction in oil and natural gas volumes as well as a reduction in the oil prices realized in the second quarter of 2013 as compared to the second quarter of 2012. In addition to NYMEX oil prices that were 7% lower for the relevant production periods compared to the same periods in 2012, average oil prices received during the periods represented by the second quarter 2013 distribution were impacted by wider than historical basis differentials in the Permian Basin. As a result, realized oil prices declined by 19%.

Oil sales included in the second quarter 2013 net profits interest calculation primarily relate to oil produced from the Underlying Properties from December 2012 to February 2013. As compared to the second quarter of 2012, oil sales decreased 27% as a result of a decline in oil volumes and an increase in the oil differential, thereby reducing the price received for oil volumes. During the months represented by the second quarter of 2013 net profits interest calculation, wellhead prices received for oil volumes decreased by $18.02 per Bbl primarily as a result of wider than historical basis differentials in the Permian Basin. Basis differentials in the Permian Basin were wider than historical levels through February 2013 production but began narrowing to return to normal levels in March 2013.

Natural gas sales included in the second quarter 2013 net profits interest calculation primarily relate to natural gas produced from the Underlying Properties from November 2012 to January 2013. Natural gas sales decreased 11% from the net profits interest calculation for the quarter ended June 30, 2012 to the quarter ended June 30, 2013 due to a decrease in gas production of 11%. Natural gas volumes reported during the second quarter of 2013 were lower as a result of the natural decline of wells located in north Louisiana. Although NYMEX natural gas prices increased from the second quarter of 2012 to the second quarter of 2013, the differential decreased, resulting in realized wellhead prices remaining consistent for the two periods.

Direct operating expenses included in the second quarter 2013 net profits interest calculation relate to expenses incurred from January to March 2013. Direct operating expenses decreased 3% from the second quarter of 2012 net profits interest distribution calculation to the second quarter of 2013 primarily due to lower sales volumes, which decreased transportation and production tax expenses incurred. Production, ad valorem and other taxes decreased 45% from the quarter ended June 30, 2012 to the quarter ended June 30, 2013 primarily due to lower sales prices received. In addition, during the second quarter of 2012, additional expenses were recorded to production, ad valorem and other taxes as a result of higher than estimated actual expenses during prior periods. Capital development expenses increased $1.1 million to $5.8 million in the second quarter of 2013 as compared to the second quarter of 2012 due to an increase in oil drilling projects in which Enduro owns higher interests. Capital development expenses for the three months ended June 30, 2013 primarily relate to two Permian oil wells being drilled in the Lost Tank field in southeastern New Mexico, in which Enduro owns a 50% working interest. The net profits interest calculation for the three months ended June 30, 2012 included capital for natural gas wells being drilled in the Haynesville Shale.

General and administrative expenses and cash withheld for expenses decreased $0.2 million from the second quarter 2012 net profits interest calculation to the second quarter 2013 calculation. General and administrative expenses for the three months ended June 30, 2012 were higher primarily due to payment for the Trust’s 2011 year-end financial statement audit as well as 2012 annual listing fees for the Trust on the NYSE.

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Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

Net profits income for the six months ended June 30, 2013 and 2012 was determined as shown in the following table:

The following table displays oil and natural gas sales volumes and average prices (excluding the effects of the hedging arrangements discussed in Note 4 of the Notes to Financial Statements) from the Underlying Properties, representing the amounts included in the net profits calculation for distributions paid during the six months ended June 30, 2013 and 2012:

Net profits income received by the Trust amounted to $20.5 million for the six months ended June 30, 2013, a decrease of $9.2 million, or 31%, from the $29.7 million for the first six months of 2012. The decrease was due to a reduction in oil and natural gas volumes as well as a reduction in the oil and natural gas prices realized in the first six months of 2013 as compared to the first six months of 2012. In addition to NYMEX oil prices that were 4% lower for the relevant production periods compared to the same periods in 2012, average oil prices received during the periods represented by the first half of 2013 distribution were impacted by wider than historical basis differentials in the Permian Basin. As a result, realized oil prices declined by 10%.

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Oil sales included in the first six months of 2013 net profits interest calculation primarily relate to oil produced from the Underlying Properties from September 2012 to February 2013. As compared to the first six months of 2012, oil sales decreased 21% as a result of a decline in oil volumes and an increase in the oil differential, thereby reducing the price received for oil volumes. Oil volumes declined partially due to the timing of payments received from third parties for the Underlying Properties. During the first half of 2012, Enduro was continuing to receive payments for oil production from the effective date of the Trust of June 1, 2011, resulting in higher oil volumes reported for that period. Oil volumes decreased 63.9 MBbls in the first six months of 2013 from 516.0 MBbls for the first six months of 2012. Of these volumes reported in the first six months of 2012, 24.0 MBbls related to June to August 2011 oil produced, for which payments generally would have been received in the fourth quarter 2011. In addition to reduced volumes, the wellhead price received for oil volumes declined for the first six months of 2013 as compared to the first six months of 2012. During the months represented by the first six months of 2013 net profits interest calculation, average oil prices decreased by $9.06 per Bbl primarily as a result of wider than historical basis differentials in the Permian Basin. Basis differentials in the Permian Basin were wider than historical levels through February 2013 production but began narrowing to return to normal levels in March 2013.

Natural gas sales included in the first six months of 2013 net profits interest calculation primarily related to natural gas produced from the Underlying Properties from August 2012 to January 2013. Natural gas sales decreased 21% from the net profits interest calculation for the six months ended June 30, 2012 to the six months ended June 30, 2013 due to a 6% reduction in natural gas volumes and a $0.62 per Mcf decrease in realized prices. Natural gas volumes reported during the second quarter of 2013 were lower as a result of the natural decline of wells located in north Louisiana. In addition to a 13% decline in NYMEX natural gas prices from the first half of 2012 to the first half of 2013, differentials widened over the time period.

Direct operating expenses decreased 6% from the first half of 2012 net profits interest distribution calculation to the first half of 2013 primarily due to lower sales volumes, which decreased lease operating, production tax and transportation expenses incurred. Production, ad valorem and other taxes decreased 33% from the six months ended June 30, 2012 to the six months ended June 30, 2013 mainly due to lower sales prices received. In addition, during the first half of 2012, additional expenses were recorded to production, ad valorem and other taxes as a result of higher than estimated actual expenses during prior periods. Capital development expenses increased $0.6 million to $10.9 million in the first six months of 2013 as compared to the first six months of 2012 due to an increase in oil drilling projects in which Enduro owns higher interests. The net profits interest calculation for the six months ended June 30, 2012 included capital for several wells being drilled in the Haynesville Shale. Capital development expenses for the six months ended June 30, 2013 primarily relate to two Permian oil wells being drilled in the Lost Tank field in southeastern New Mexico, in which Enduro owns a 50% working interest.

General and administrative expenses and cash withheld for expenses decreased $0.3 million from the first half 2012 net profits interest calculation to the first half 2013 calculation. General and administrative expenses for the six months ended June 30, 2012 were higher primarily due to payment for the Trust’s 2011 year-end financial statement audit as well as the initial listing fee and 2012 annual listing fees for the Trust on the NYSE.

Liquidity and Capital Resources

The Trust’s principal sources of liquidity are cash flow generated from the Net Profits Interest and borrowing capacity under the letter of credit described below. Other than Trust administrative expenses, including any reserves established by the Trustee for future liabilities, the Trust’s only use of cash is for distributions to Trust unitholders. Available funds are the excess cash, if any, received by the Trust from the Net Profits Interest and other sources (such as interest earned on any amounts reserved by the Trustee) in that month, over the Trust’s expenses paid for that month. Available funds are reduced by any cash the Trustee decides to hold as a reserve against future expenses.

The Trustee may create a cash reserve to pay for future liabilities of the Trust. If the Trustee determines that the cash on hand and the cash to be received are, or will be, insufficient to cover the Trust’s liabilities, the Trustee may authorize the Trust to borrow money to pay administrative or incidental expenses of the Trust that exceed cash held by the Trust. The Trustee may authorize the Trust to borrow from any person, including the Trustee or the Delaware Trustee or an affiliate thereof, although none of the Trustee, the Delaware Trustee or any affiliate of either of them intends to lend funds to the Trust. The Trustee may also cause the Trust to mortgage its assets to secure payment of the indebtedness. The terms of such indebtedness and security interest, if funds were loaned by the entity serving as Trustee or Delaware Trustee or an affiliate thereof, would be similar to the terms which such entity would grant to a similarly situated commercial customer with whom it did not have a fiduciary relationship. In addition, Enduro provided the Trust with a $1 million letter of credit to be used by the Trust in the event that its cash on hand (including available cash reserves) is not sufficient to pay ordinary course administrative expenses. Further, if the Trust requires more than the $1 million under the letter of credit to pay administrative expenses, Enduro has agreed to loan funds to the Trust necessary to pay such expenses. If the Trust borrows funds, draws on the letter of credit or Enduro loans funds to the Trust, no further distributions will be made to Trust unitholders until such amounts borrowed or drawn are repaid. Except for the foregoing, the Trust has no source of liquidity or capital resources. The Trustee has no current plans to authorize the Trust to borrow money. Since the Trust’s formation, it has not borrowed any funds and no amounts have been drawn on the letter of credit.

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Any amounts received by Enduro from the hedge contract counterparties upon settlement of the hedge contracts will reduce the operating expenses related to the Underlying Properties in calculating the net profits. However, if the hedge payments received by Enduro under the hedge contracts and other non-production revenue exceed operating expenses during a period, the ability to use such excess amounts to offset operating expenses will be deferred, with interest accruing on such amounts at the prevailing prime rate, until the next period where the hedge payments and the other non-production revenue are less than such expenses. Any amounts paid by Enduro on settlement of the hedge contracts will reduce the amount of net profits paid to the Trust.

The Trust pays the Trustee an administrative fee of $200,000 per year. The Trust pays the Delaware Trustee a fee of $2,000 per year. The Trust also incurs, either directly or as a reimbursement to the Trustee, legal, accounting, tax and engineering fees, printing costs and other expenses that are deducted by the Trust before distributions are made to Trust unitholders. The Trust also is responsible for paying other expenses incurred as a result of being a publicly traded entity, including costs associated with annual and quarterly reports to Trust unitholders, tax return and Form 1099 preparation and distribution, NYSE listing fees, independent auditor fees and registrar and transfer agent fees.

The Trust does not have any transactions, arrangements or other relationships with unconsolidated entities or persons that could materially affect the Trust’s liquidity or the availability of capital resources.

Distributions Declared After Quarter End

On July 19, 2013, the Trust declared a distribution of $0.133930 per unit to unitholders of record as of July 31, 2013. The distribution is expected to be paid to unitholders on August 14, 2013.

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 other than the commodity hedge contracts disclosed in the section “Quantitative and Qualitative Disclosures About Market Risk.”

New Accounting Pronouncements

As the Trust’s financial statements are prepared on the modified cash basis, most accounting pronouncements are not applicable to the Trust’s financial statements. No new accounting pronouncements have been adopted or issued that would impact the financial statements of the Trust.

Critical Accounting Policies and Estimates

Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” of the Trust’s 2012 Annual Report on Form 10-K for additional information regarding the Trust’s critical accounting policies and estimates. There were no material changes to the Trust’s critical accounting policies or estimates during the quarter ended June 30, 2013.

Commodity Price Sensitivity

The Trust is exposed to fluctuations in energy prices in the normal course of business due to the Net Profits Interest in the Underlying Properties. The revenues derived from the Underlying Properties depend substantially on prevailing crude oil prices and, to a lesser extent, natural gas prices. As a result, commodity prices affect the amount of cash flow available for distribution to the Trust unitholders. Lower prices may also reduce the amount of oil and natural gas that Enduro and its third party operators can economically produce. To mitigate the negative effects of a possible decline in oil and natural gas prices on distributable income to the Trust, Enduro entered into hedge contracts with respect to approximately 41% and 67% of expected oil and natural gas production, respectively, for 2013 from the total proved reserves attributable to the Underlying Properties as of December 31, 2012. The commodity derivative contracts are discussed further in Note 4 of the Notes to Financial Statements included in “Item 1. Financial Statements.”

Evaluation of Disclosure Controls and Procedures.

The Trustee conducted an evaluation of the Trust’s disclosure controls and procedures (as defined in Rules 13a-15 and 15d-15 under the Exchange Act). Based on this evaluation, the Trustee has concluded that the disclosure controls and procedures of the Trust were effective, as of the end of the period covered by this report, in ensuring 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 accumulated and communicated to the Trustee to allow timely decisions regarding required disclosure.

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Due to the nature of the Trust as a passive entity and in light of the contractual arrangements pursuant to which the Trust was created, including the provisions of (i) the Trust Agreement and (ii) the Conveyance of the Net Profits Interest, the Trustee’s disclosure controls and procedures related to the Trust necessarily rely on (A) information provided by Enduro, including information relating to results of operations, the costs and revenues attributable to the Trust’s interest under the conveyance and other operating and historical data, plans for future operating and capital expenditures, reserve information, information relating to projected production, and other information relating to the status and results of operations of the Underlying Properties and the Net Profits Interest, and (B) conclusions and reports regarding reserves by the Trust’s independent reserve engineers.

Changes in Internal Control over Financial Reporting.

During the quarter ended June 30, 2013, there was 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 Trustee notes for purposes of clarification that it has no authority over, and makes no statement concerning, the internal control over financial reporting of Enduro.

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PART II—OTHER INFORMATION

Risk factors relating to the Trust are discussed in Item 1A of the Trust’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012. No material change to such risk factors occurred during the three months ended June 30, 2013.

The exhibits listed in the accompanying index to exhibits are filed as part of the Quarterly Report on Form 10-Q.

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SIGNATURE

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.

Date: August 9, 2013

The Registrant, Enduro Royalty Trust, has no principal executive officer, principal financial officer, board of directors or persons performing similar functions. Accordingly, no additional signatures are available, and none have been provided. In signing the report above, the Trustee does not imply that it has performed any such function or that such function exists pursuant to the terms of the Trust agreement under which it serves.

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INDEX TO EXHIBITS