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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K/A

Amendment No. 1

(Mark One)

x      ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2013

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: 001-35274

SANDRIDGE PERMIAN TRUST

(Exact name of registrant as specified in its charter)

(512) 236-6531

(Registrant’s telephone number, including area code)

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

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

None

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

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

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 o

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

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

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. (Check one):

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

The aggregate market value of Common Units of Beneficial Interest of the Trust held by non-affiliates on June 28, 2013 (the last business day of its most recently completed second quarter) was approximately $543.1 million based on the closing price as quoted on the New York Stock Exchange.  As of February 21, 2014, 39,375,000 Common Units and 13,125,000 Subordinated Units of Beneficial Interest in SandRidge Permian Trust were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: None

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EXPLANATORY NOTE

This Amendment No. 1 to the Annual Report on Form 10-K (this “Amendment No. 1”) of SandRidge Permian Trust (the “Trust”) amends the Trust’s Annual Report on Form 10-K for the year ended December 31, 2013 that was filed with the Securities and Exchange Commission on February 28, 2014 (the “Original Form 10-K”). This Amendment No. 1 does not reflect a change in the Trust’s results of operations or financial position as reported in the Original Form 10-K. This Amendment No. 1 is being filed solely for the purpose of correcting the Report of Independent Registered Public Accounting Firm to cover the statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2013 rather than each of the two years in the period ended December 31, 2013 as indicated in the originally filed report. This Amendment No. 1 does not reflect events occurring after the periods indicated in the Original Form 10-K or modify or update the disclosure contained therein in any way other than as required to reflect the amendments discussed above. Pursuant to Rule 12b-15 promulgated under the Securities Exchange Act of 1934, as amended, the complete text of Item 15, as amended, is repeated in this Amendment No. 1.

This Amendment No. 1 consists solely of the preceding cover page, this explanatory note, amended Item 15, the signature page, the amended exhibit index, the consents filed as Exhibits 23.3 and 23.4 under amended Item 15 and Exhibits 31.2 and 32.2.

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SANDRIDGE PERMIAN TRUST

2013 ANNUAL REPORT ON FORM 10-K

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PART IV

Item 15.                           Exhibits and Financial Statement Schedules

The following documents are filed as a part of this report:

(1)                 Financial Statements

Reference is made to the Index to Financial Statements appearing on page F-1.

(2)                 Financial Statement Schedules

All financial statement schedules have been omitted because they are not applicable or the required information is presented in the financial statements or notes thereto.

(3)                 Exhibits

Reference is made to the Exhibit Index.

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INDEX TO FINANCIAL STATEMENTS

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Report of Independent Registered Public Accounting Firm

To the Unitholders of SandRidge Permian Trust and The Bank of New York Mellon Trust Company, N.A., Trustee:

We have audited the accompanying statements of assets and trust corpus of SandRidge Permian Trust (the “Trust”) as of December 31, 2013 and 2012, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2013. We also have audited the Trust’s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Trustee is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Trustee’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Trust’s internal control over financial reporting based on our integrated audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As described in Note 2, these financial statements were prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.

A trust’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A trust’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the trust; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the trust are being made only in accordance with authorizations of the Trustee; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the trust’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the financial statements referred to above present fairly, in all material respects, the assets and trust corpus of the Trust at December 31, 2013 and 2012, and the distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2013, on the basis of accounting described in Note 2. Also in our opinion, the Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control—Integrated Framework (1992) issued by COSO.

Tulsa, Oklahoma

February 28, 2014

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SANDRIDGE PERMIAN TRUST
STATEMENTS OF ASSETS AND TRUST CORPUS

(In thousands, except unit data)

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

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SANDRIDGE PERMIAN TRUST
STATEMENTS OF DISTRIBUTABLE INCOME

(In thousands, except unit and per unit data)

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

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SANDRIDGE PERMIAN TRUST
STATEMENTS OF CHANGES IN TRUST CORPUS

(In thousands)

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

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SANDRIDGE PERMIAN TRUST

NOTES TO FINANCIAL STATEMENTS

1. Organization of the Trust

Nature of Business. SandRidge Permian Trust (the “Trust”) is a statutory trust formed on May 12, 2011 under the Delaware Statutory Trust Act pursuant to a trust agreement by and among SandRidge Energy, Inc. (“SandRidge”), as Trustor, The Bank of New York Mellon Trust Company, N.A., as Trustee (the “Trustee”), and The Corporation Trust Company, as Delaware Trustee (the “Delaware Trustee”). The trust agreement was amended and restated by SandRidge, the Trustee and the Delaware Trustee on August 16, 2011. References in this report to the “trust agreement” are to the amended and restated trust agreement.

The Trust was created to acquire and hold Royalty Interests in specified oil and natural gas properties located in Andrews County, Texas (the “Underlying Properties”). The Royalty Interests were conveyed to the Trust by SandRidge in exchange for Trust common and subordinated units and the proceeds of the Trust’s initial public offering, described further below.

The Royalty Interests entitle the Trust to receive 80% of the proceeds (after deducting post-production costs and any applicable taxes) from the sale of oil, natural gas liquids (“NGL”) and natural gas production attributable to SandRidge’s net revenue interest in 517 oil and natural gas wells developed as of April 1, 2011, including 21 wells awaiting completion at that time (the “Initial Wells”) and 70% of the proceeds (after deducting post-production costs and any applicable taxes) from the sale of oil, NGL and natural gas production attributable to SandRidge’s net revenue interest in 888 development wells to be drilled (the “Trust Development Wells”) within an area of mutual interest (“AMI”) beginning April 1, 2011, the effective date of the conveyance.

As specified in the development agreement executed by the Trust with SandRidge (see Note 6), SandRidge is credited for having drilled one full Trust Development Well if the well is drilled and perforated for completion to the Grayburg/San Andres formation and SandRidge’s net revenue interest in the well is equal to 69.3%. The actual number of wells required to be drilled may increase or decrease in proportion to SandRidge’s net revenue interest in each well. At December 31, 2013, these properties consisted of Royalty Interests in (a) the Initial Wells, (b) 663 additional wells (equivalent to approximately 683 Trust Development Wells under the development agreement as described below) that were drilled and perforated for completion between April 1, 2011 and December 31, 2013, and (c) the equivalent of approximately 205 Trust Development Wells to be drilled within the AMI.

The Trust is passive in nature and neither the Trust nor the Trustee has any control over, or responsibility for, costs relating to the operation of the Underlying Properties. The business and affairs of the Trust are administered by the Trustee. The trust agreement generally limits the Trust’s business activities to owning the Royalty Interests and entering into derivative contracts on a limited basis and activities reasonably related thereto, including activities required or permitted by the terms of the conveyances related to the Royalty Interests. The Trust is not responsible for any costs related to the drilling of the Trust Development Wells or any other operating or capital costs related to the Underlying Properties.

Initial Public Offering. Through an initial public offering in August 2011, the Trust sold 34,500,000 of its common units to the public for net proceeds, after payment of offering expenses, of approximately $580.6 million. The Trust delivered the net proceeds of the offering, along with 4,875,000 common units and 13,125,000 subordinated units, to certain wholly owned subsidiaries of SandRidge, in exchange for the conveyance of the Royalty Interests to the Trust. Upon completion of these transactions and as of December 31, 2013, there were 52,500,000 Trust units, consisting of 39,375,000 common and 13,125,000 subordinated units, issued and outstanding. At December 31, 2013, SandRidge owned 1,825,000 Trust common units and 13,125,000 Trust subordinated units. The common and subordinated units have identical rights and privileges, except with respect to their rights to receive distributions as described below.

Distributions. The Trust makes quarterly cash distributions of substantially all of its cash receipts, after deducting amounts for the Trust’s administrative expenses and cash reserves withheld by the Trustee, property tax and Texas franchise tax, on or about 60 days following the completion of each quarter. Due to the timing of the payment of production proceeds to the Trust, each distribution covers production from a three-month period consisting of the first two months of the most recently ended quarter and the final month of the quarter preceding it.

The Trust’s cash receipts with respect to the Royalty Interests in the Underlying Properties are determined after deducting post-production costs and any applicable taxes associated with the Royalty Interests. Post-production costs generally consist of costs incurred to gather, store, compress, transport, process, treat, dehydrate and market the oil and natural gas produced. The Trust’s distributable income is adjusted for amounts received and paid under the Trust’s derivative contracts as discussed further in Note 6, and is reduced by the Trust’s cash reserves withheld by the Trustee and general and administrative expenses when paid.

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The subordinated units, all of which are held by SandRidge, constitute 25% of the Trust units issued and outstanding. The subordinated units are entitled to receive pro rata distributions from the Trust each quarter if and to the extent there is sufficient cash to provide a cash distribution on the common units that is no less than 80% of the target distribution for the corresponding quarter (“Subordination Threshold”). If there is not sufficient cash to fund such a distribution on all of the common units, the distribution to be made with respect to the subordinated units is reduced or eliminated for such quarter in order to make a distribution, to the extent possible, of up to the Subordination Threshold amount on all of the common units. In exchange for agreeing to subordinate a portion of its Trust units, and in order to provide additional financial incentive to SandRidge to satisfy its drilling obligation, SandRidge is entitled to receive incentive distributions equal to 50% of the amount by which the cash available for distribution on all of the Trust units in any quarter exceeds 120% of the target distribution for such quarter (“Incentive Threshold”). At the end of the fourth full calendar quarter following SandRidge’s satisfaction of its drilling obligation with respect to the Trust Development Wells, the subordinated units will automatically convert into common units on a one-for-one basis and SandRidge’s right to receive incentive distributions in respect of subsequent periods will terminate. Distributions made to common units in respect of subsequent periods will no longer have the protection of the Subordination Threshold, and all Trust unitholders will share on a pro rata basis in the Trust’s distributions.

Dissolution. The Trust will dissolve and begin to liquidate on March 31, 2031 (the “Termination Date”) and will soon thereafter wind up its affairs and terminate. At the Termination Date, 50% of the Royalty Interests will revert automatically to SandRidge. The remaining 50% of the Royalty Interests will be retained by the Trust at the Termination Date and thereafter sold, with the net proceeds of the sale, as well as any remaining Trust cash reserves, distributed to the unitholders on a pro rata basis. SandRidge has a right of first refusal to purchase the Royalty Interests retained by the Trust at the Termination Date.

2. Significant Accounting Policies

Basis of Accounting. The financial statements of the Trust differ from financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) as the Trust records revenues when cash is received (rather than when earned) and expenses when paid (rather than when incurred) and may also establish cash reserves for contingencies, which would not be accrued in financial statements prepared in accordance with GAAP. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the Securities and Exchange Commission (“SEC”) as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts. Amortization of investment in royalty interests, calculated on a unit-of-production basis, and any impairments are charged directly to trust corpus. Distributions to unitholders are recorded when declared.

Significant Accounting Policies. Most accounting pronouncements apply to entities whose financial statements are prepared in accordance with GAAP, which may require such entities to accrue or defer revenues and expenses in a period other than when such revenues are received or expenses are paid. Because the Trust’s financial statements are prepared on the modified cash basis as described above, most accounting pronouncements are not applicable to the Trust’s financial statements.

Use of Estimates. The preparation of financial statements requires the Trust to make estimates and assumptions that affect the reported amounts of assets and trust corpus and the reported amounts of revenues and expenses during the reporting period. Significant estimates that impact the Trust’s financial statements include estimates of proved oil and natural gas reserves, which are used to compute the Trust’s amortization of investment in royalty interests and, as necessary, to evaluate potential impairment of its investment in royalty interests. Actual results could differ from those estimates.

Distributable Income Per Common and Subordinated Unit. The Trust calculates distributable income per common and subordinated unit using the two-class method. In accordance with this method, undistributed earnings in the accompanying statements of distributable income have been allocated to the common and subordinated units based upon the subordinated units’ contractual participation rights as if all of the distributable income for the periods presented had been distributed. Distributable income per unit amounts as calculated for the periods presented in the accompanying statement of distributable income may differ from declared distribution amounts per unit due to the timing of the Trust’s receipt or payment of settlements on the novated derivative contracts. See discussion of the Trust’s derivative contracts at Note 6.

Cash and Cash Equivalents. Cash and cash equivalents consist of all highly-liquid instruments with original maturities of three months or less.

Investment in Royalty Interests. The conveyance of the Royalty Interests to the Trust in August 2011 was accounted for as a transfer of properties between entities under common control and recorded at SandRidge’s historical cost, or $549.8 million, which was determined by allocating the historical net book value of SandRidge’s full cost pool based on the fair value of the Royalty Interests relative to the fair value of SandRidge’s full cost pool. The carrying value of the Trust’s investment in royalty interests is not necessarily indicative of the fair value of such Royalty Interests.

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Significant dispositions or abandonments of the Underlying Properties are charged to investment in royalty interests and the trust corpus. Amortization of investment in royalty interests is calculated on a units-of-production basis, whereby the Trust’s cost basis is divided by the proved reserves attributable to the Royalty Interests to derive an amortization rate per reserve unit. Amortization is recorded when units are produced. Such amortization does not reduce distributable income, rather it is charged directly to trust corpus. Revisions to estimated future units-of-production are treated on a prospective basis beginning on the date significant revisions are known.

The investment in royalty interests is assessed to determine whether net capitalized cost is impaired whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If an assessment is necessary, an impairment would be indicated when the net capitalized costs of investment in royalty interests exceeds undiscounted future net revenues attributable to the Trust’s interest in the proved oil and natural gas reserves of the Underlying Properties. The Trust will provide a write-down to the extent that the net capitalized costs exceed the fair value of the proved oil and natural gas reserves attributable to the Royalty Interests. Any such write-down would be charged directly to trust corpus and would not reduce distributable income. No impairments were recorded in 2013, 2012 or 2011.

Derivative Financial Instruments. The Trust entered into derivative contracts to manage risks related to oil price volatility. See Note 6. In accordance with the Trust’s accounting policy, derivative instruments are recorded when benefits are received or obligations are paid. The fair market values and changes in the fair market value of the derivative contracts are not included in the accompanying financial statements as the statements are presented on a modified cash basis. Net cash settlements received related to the Trust’s derivative contracts during the year ended December 31, 2013 were approximately $8.9 million, and included (i) approximately $3.8 million received related to the conveyed contracts for production attributable to the Royalty Interests from September 1, 2012 to August 31, 2013, (ii) approximately $5.4 million received from the counterparty to the novated contracts for production attributable to the Royalty Interests from October 1, 2012 to August 31, 2013 and (iii) approximately $0.3 million paid to the counterparty related to the novated contracts for September 2013 production. Net settlements paid during 2013 related to September 2013 production reduced the Trust’s February 2014 distribution. Net cash settlements received related to the Trust’s derivative contracts during the year ended December 31, 2012 were approximately $6.8 million, and included (i) approximately $2.2 million received related to the conveyed contracts for production attributable to the Royalty Interests from September 1, 2011 to August 31, 2012, (ii) approximately $4.1 million received from the counterparty to the novated contracts for production attributable to the Royalty Interests from October 1, 2011 to August 31, 2012 and (iii) approximately $0.5 million received from the counterparty to the novated contracts for September 2012 production. Net settlements received during 2012 related to September 2012 production were included in the Trust’s March 2013 distribution. The Trust received net settlement proceeds of approximately $1.8 million related to its derivative contracts during the year ended December 31, 2011, including $0.7 million related to September 2011 production that was included in the Trust’s February 2012 distribution.

Revenue and Expenses. Revenues received by the Trust are net of gathering and post-production expenses and production taxes in order to determine distributable income. The Trust’s distributable income is adjusted for amounts received or paid under its derivative contracts and is reduced by cash reserves withheld by the Trustee and other allowable costs such as general and administrative expenses, property tax and Texas franchise tax, when paid. The Royalty Interests are not burdened by field and lease operating expenses.

Concentration of Risk. The Trust maintains cash balances at one financial institution which are insured by the Federal Deposit Insurance Corporation up to $250,000. The Trust typically has balances in these accounts that exceed the federally insured limit substantially. The Trust does not anticipate any loss associated with balances exceeding the federally insured limit.

The use of hedging transactions involves the risk that the counterparties may be unable to meet the financial terms of the transactions. The counterparties to the contracts novated to the Trust by SandRidge have an “investment grade” credit rating. SandRidge, on behalf of the Trust, monitors on an ongoing basis the credit rating of the hedging counterparties. The Trust has a master netting agreement with its derivative contract counterparties, which allows the Trust to net amounts due from and owed to the same counterparty. As a result of the netting provision, the Trust’s maximum amount of loss under the hedging transaction due to credit risk of the counterparties to the novated contracts is limited to the net amount due from the counterparties under the derivatives. As of December 31, 2013, the counterparty to the contracts novated to the Trust by SandRidge consisted of one financial institution. The Trust is not required to post additional collateral under the derivative contract.

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3. Income Taxes

The Trust is treated for federal and applicable state income tax purposes as a partnership. For U.S. federal income tax purposes, a partnership is not a taxable entity and incurs no U.S. federal income tax liability. With respect to state taxation, a partnership is typically treated in the same manner as it is for U.S. federal income tax purposes. However, the Trust’s activities result in the Trust having nexus in Texas and, therefore, make it subject to the Texas franchise tax. Texas franchise tax is treated as an income tax for financial statement purposes and the Trust will be required to pay Texas franchise tax each year at a maximum effective rate of 0.7% of its gross income apportioned to Texas in the prior year. The Trust records Texas franchise tax when paid. The Trust paid its 2012 Texas franchise tax of approximately $0.4 million during the year ended December 31, 2013 and paid its 2011 Texas franchise tax of approximately $0.2 million during the year ended December 31, 2012. The Trust’s estimated 2013 Texas franchise tax liability of approximately $0.4 million will be paid during 2014.

4. Distributions to Unitholders

The Trust makes quarterly cash distributions of substantially all of its cash receipts, after deducting amounts for the Trust’s administrative expenses and cash reserves withheld by the Trustee, property tax and Texas franchise tax, on or about 60 days following the completion of each quarter. Other than the first distribution, which covered production for the five-month period from April 1, 2011 to August 31, 2011, distributions cover a three-month period. A summary of the Trust’s distributions to unitholders is as follows:

On February 28, 2014, the Trust will pay a cash distribution covering production for the period from September 1, 2013 to November 30, 2013. See Note 8 for further discussion.

5. Commitments and Contingencies

Loan Commitment. Pursuant to the trust agreement, if at any time the Trust’s cash on hand (including available cash reserves) is not sufficient to pay the Trust’s ordinary course administrative expenses as they become due, SandRidge will loan funds to the Trust necessary to pay such expenses. Any funds loaned by SandRidge pursuant to this commitment will be limited to the payment of current accounts payable or other obligations to trade creditors in connection with obtaining goods or services or the payment of other

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accrued current liabilities arising in the ordinary course of the Trust’s business, and may not be used to satisfy Trust indebtedness, or to make distributions. If SandRidge loans funds pursuant to this commitment, unless SandRidge agrees otherwise, no further distributions will be made to unitholders (except in respect of any previously determined quarterly cash distribution amount) until such loan is repaid. Any such loan will be on an unsecured basis, and the terms of such loan will be substantially the same as those which would be obtained in an arm’s length transaction between SandRidge and an unaffiliated third party. There was no such loan outstanding with SandRidge at December 31, 2013 or 2012.

Risks and Uncertainties. The Trust’s revenue and distributions are substantially dependent upon the prevailing and future prices for oil and natural gas, each of which depends on numerous factors beyond the Trust’s control such as overall oil and natural gas production and inventories in relevant markets, economic conditions, the global political environment, regulatory developments and competition from other energy sources. Oil and natural gas prices historically have been volatile, and may be subject to significant fluctuations in the future. The Trust’s derivative arrangements serve to mitigate a portion of the effect of this price volatility through March 31, 2015. See Note 6 for a discussion of the Trust’s open oil derivative contracts.

6. Related Party Transactions

Trustee Administrative Fee. Under the terms of the trust agreement, the Trust pays an annual administrative fee of $150,000 to the Trustee, which will be adjusted for inflation by no more than 3% in any year, beginning in 2017. The Trustee’s administrative fees paid during the years ended December 31, 2013, 2012 and 2011 totaled approximately $150,000, $150,000 and $47,500, respectively.

Registration Rights Agreement. The Trust is party to a registration rights agreement pursuant to which the Trust has agreed to register the offering of the Trust units held by SandRidge and certain of its affiliates and permitted transferees upon request by SandRidge. One such registration statement was filed and declared effective during 2012 and remains effective currently. The holders have the right to require the Trust to file no more than five registration statements in aggregate. The Trust does not bear any expenses associated with such transactions.

Development Agreement. The Trust is party to a development agreement with SandRidge, effective April 1, 2011, that obligates SandRidge to drill, or cause to be drilled, the Trust Development Wells by March 31, 2016. Additionally, SandRidge agreed not to drill and complete, or allow another person within its control to drill and complete, any other well in the AMI, other than (a) the Trust Development Wells, (b) up to five horizontal wells to test the results of horizontal drilling in the AMI and (c) wells that were spud and temporarily abandoned on or before March 31, 2011, until SandRidge has fulfilled its drilling obligation. The Trust will not own any interests in the five test horizontal wells, if they are drilled, and such wells will not count toward SandRidge’s drilling obligation.

A wholly owned subsidiary of SandRidge granted to the Trust a lien (“Drilling Support Lien”) covering its interest in the AMI (except its interest in the Initial Wells) in order to secure the estimated amount of the drilling costs for the Trust’s interests in the undeveloped Underlying Properties. The initial amount recoverable by the Trust pursuant to the Drilling Support Lien could not exceed approximately $295.0 million, subject to adjustment as described below. As SandRidge fulfills its drilling obligation over time, the total amount that may be recovered is proportionately reduced and the Trust Development Wells drilled and perforated for completion are released from the lien. If SandRidge does not fulfill its drilling obligation by March 31, 2016, the Trust may foreclose on any remaining interest in the AMI that is subject to the Drilling Support Lien. Any amounts actually recovered in a foreclosure action would be applied to the completion of SandRidge’s drilling obligation and would not result in a distribution to the Trust’s unitholders. As of December 31, 2013, SandRidge had drilled and perforated for completion approximately 683 equivalent Trust Development Wells, and, accordingly, the maximum amount potentially recoverable under the Drilling Support Lien had been reduced to approximately $68.0 million.

Administrative Services Agreement. The Trust is party to an administrative services agreement with SandRidge, effective April 1, 2011, that obligates the Trust to pay SandRidge an annual administrative services fee for accounting, tax preparation, bookkeeping and informational services to be performed by SandRidge on behalf of the Trust. Additionally, the administrative services agreement designates SandRidge as the Trust’s hedge manager, pursuant to which SandRidge has authority to administer the derivative contracts underlying the derivatives agreement (described below), and, on behalf of the Trust, to administer the Trust’s derivative contracts with unaffiliated third parties. For its services under the administrative services agreement, SandRidge receives an annual fee of $300,000, which is payable in equal quarterly installments and will remain fixed for the life of the Trust. SandRidge is also entitled to receive reimbursement for its out-of-pocket fees, costs and expenses incurred in connection with the provision of any of the services under this agreement. The administrative services agreement will terminate on the earliest to occur of: (i) the date the Trust shall have dissolved and commenced winding up in accordance with the trust agreement, (ii) the date that all of the Royalty Interests have been terminated or are no longer held by the Trust, (iii) pertaining to services to be provided with respect to any Underlying Properties transferred by SandRidge, the date that either SandRidge or the Trustee may designate by delivering 90-days’ prior written notice, provided that SandRidge’s drilling obligation has been completed and the transferee of such Underlying Properties assumes responsibility to perform the services in place of SandRidge and (iv) a date mutually agreed to by SandRidge and the Trustee. The Trust paid administrative fees to SandRidge equal to $300,000 during the years ended December 31, 2013 and 2012, respectively, and $75,000 during the year ended 2011.

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Derivatives Agreement. The Trust is party to a derivatives agreement with SandRidge, effective August 1, 2011, that provides the Trust with the economic effect of certain oil derivative contracts entered into between SandRidge and a third party. Under the derivatives agreement, SandRidge pays the Trust amounts it receives from its counterparty and the Trust pays SandRidge any amounts that SandRidge is required to pay such counterparty. Substantially concurrent with the execution of the derivatives agreement, SandRidge novated certain of the derivative contracts underlying the derivatives agreement to the Trust. As a party to these contracts, the Trust receives payment directly from the counterparty and is required to pay any amounts owed directly to the counterparty. To secure its obligations under these novated contracts, the Trust entered into a collateral agency agreement and granted the counterparty a lien on the Royalty Interests. Under the collateral agency agreement, the Trust pays a $15,000 annual fee to the collateral agent. Under the derivatives agreement, as Trust Development Wells are drilled, SandRidge has the right, under certain circumstances, to assign or novate to the Trust additional derivative contracts. The Trust’s derivative contracts consist of fixed price swaps. In April 2012 and March 2013, SandRidge novated certain additional portions of the derivative contracts underlying the derivatives agreement to the Trust.

The following tables present, as of December 31, 2013, the notional amount and weighted average fixed price of the open contracts underlying the derivatives agreement and the contracts that have been novated to the Trust. The combined volume in the tables below reflects the total volume of oil derivative contracts for the Trust.

Oil Contracts Underlying the Derivatives Agreement

Oil Contracts Underlying the Derivatives Agreement and Novated to the Trust

7. Major Customers

For the years ended December 31, 2013, 2012 and 2011, sales of production attributable to the Royalty Interests exceeding 10% of the Trust’s total revenues were made to the following oil or natural gas purchasers:

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8. Subsequent Events

On January 30, 2014, the Trust declared a cash distribution of $0.641 per unit covering production for the three-month period from September 1, 2013 to November 30, 2013 for record unitholders as of February 14, 2014. The distribution will be paid on February 28, 2014. Distributable income for September 1, 2013 to November 30, 2013 was calculated as follows (in thousands, except for unit and per unit amounts):

(1)                  Includes amounts withheld for payment of future Trust administrative expenses.

9. Supplemental Information on Oil and Natural Gas Producing Activities

The following supplemental information includes capitalized costs related to oil and natural gas producing activities; costs incurred in oil and natural gas property acquisition, exploration and development; and the results of operations for oil and natural gas producing activities. Supplemental information is also provided for oil, NGL and natural gas production and average sales prices; the estimated quantities of proved oil, NGL and natural gas reserves; the standardized measure of discounted future net cash flows associated with proved oil, NGL and natural gas reserves; and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved oil, NGL and natural gas reserves. This supplemental information was prepared on an accrual basis, which is the basis upon which SandRidge and the Underlying Properties maintain their records and is different from the modified cash basis on which the Trust financial statements are prepared. A reconciliation of information presented on the modified cash basis to the accrual basis for the years ended December 31, 2013, 2012 and 2011 is as follows:

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(1)                  Production volumes attributable to the Royalty Interests and related revenues and expenses included in SandRidge’s 2013 net revenue distributions to the Trust. Represents production from September 1, 2012 to August 31, 2013.

(2)                Production volumes attributable to the Royalty Interests and related revenues and expenses, presented on an accrual basis for the year ended December 31, 2013.

(3)                  Production volumes attributable to the Royalty Interests and related revenues and expenses included in SandRidge’s 2012 net revenue distributions to the Trust. Represents production from September 1, 2011 to August 31, 2012.

(4)                  Production volumes attributable to the Royalty Interests and related revenues and expenses, presented on an accrual basis for the year ended December 31, 2012.

(5)                  Production volumes attributable to the Royalty Interests and related revenues and expenses included in SandRidge’s 2011 net revenue distribution to the Trust. Represents production from April 1, 2011 to August 31, 2011.

(6)                  Production volumes attributable to the Royalty Interests and related revenues and expenses, presented on an accrual basis, from the date of conveyance, August 16, 2011, through December 31, 2011.

Capitalized Costs Related to Oil and Natural Gas Producing Activities

The Trust’s capitalized costs consisted of the following (in thousands):

(1)                  Royalty Interests conveyed to the Trust by SandRidge consist of interests in proved properties only.

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Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development

The conveyance of the Royalty Interests was accounted for as a transfer of properties between entities under common control and recorded by the Trust at SandRidge’s historical cost, which was $549.8 million. The Trust delivered the net proceeds of its initial public offering, or $580.6 million, along with 4,875,000 common units and 13,125,000 subordinated units, to certain wholly owned subsidiaries of SandRidge in exchange for the conveyance of the Royalty Interests to the Trust in August 2011. The Trust is not responsible for any costs incurred to drill the Trust Development Wells. As such, the Trust did not incur any costs in the exploration or development of oil and natural gas properties during any of the years ended December 31, 2013, 2012 or 2011.

Results of Operations for Oil and Natural Gas Producing Activities (Unaudited)

The Trust’s results of operations from oil and natural gas producing activities for each of the years 2013, 2012 and 2011 are shown in the following table (in thousands):

(1)                  Revenues and post-production costs attributable to volumes produced from January 1, 2013 to December 31, 2013, regardless of whether proceeds from the sale of production have been remitted to the Trust by SandRidge.

(2)                  The Trust does not bear any well operating costs.

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(3)                  Amortization is recorded by the Trust as volumes are produced and does not reduce distributable income, but rather, is recorded directly to trust corpus.

(4)                  Reflect Trust’s effective state income tax rate of 0.35%.  The Trust is not required to pay federal income tax.

(5)                  Revenues and post-production costs attributable to volumes produced from January 1, 2012 to December 31, 2012, regardless of whether proceeds from the sale of production have been remitted to the Trust by SandRidge.

(6)                  Revenues and post-production costs attributable to volumes produced from August 16, 2011, the date of conveyance, to December 31, 2011, regardless of whether proceeds from the sale of production have been remitted to the Trust by SandRidge.

Oil, NGL and Natural Gas Reserve Quantities (Unaudited)

Proved reserves are those quantities of oil, NGL and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, based on prices used to estimate reserves, from a given date forward from known reservoirs, and under existing economic conditions, operating methods, and government regulation before the time of which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Proved developed reserves are proved reserves expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively large major expenditure is required for recompletion.

Netherland, Sewell & Associates, Inc. (“Netherland Sewell”), independent oil and natural gas consultants, prepared the estimates of proved reserves of oil, NGLs and natural gas attributable to the Royalty Interests as of December 31, 2013, 2012 and 2011. Netherland Sewell are independent petroleum engineers, geologists, geophysicists and petrophysicists and do not own an interest in the Trust or its properties and are not employed on a contingent basis.

Based on its review of the estimates of proved reserves made by the independent petroleum engineers, SandRidge has advised the Trustee that the geoscience and engineering data examined provides reasonable assurance that the proved reserves are economically producible in future years from known reservoirs, and under existing economic conditions, operating methods and governmental regulations. Estimates of proved reserves are subject to change, either positively or negatively, as additional information is available and contractual and economic conditions change.

The table below represents the estimate of proved reserves attributable to the Trust’s net interest in oil and natural gas properties, all of which are located in the continental United States, based upon the evaluation by the Trustee and its independent petroleum engineers of pertinent geoscience and engineering data in accordance with the SEC’s regulations. Estimates of the Trust’s proved reserves have been prepared by independent reservoir engineers and geoscience professionals and are reviewed by members of the SandRidge’s senior management with professional training in petroleum engineering to ensure that rigorous professional standards and the reserve definitions prescribed by the SEC are consistently applied.

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The summary below presents changes in the Trust’s estimated reserves during the years ended December 31, 2011, 2012 and 2013.

(1)                  Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.

(2)                  Volumes produced from August 16, 2011, the date of Royalty Interest conveyance, to December 31, 2011, regardless of whether proceeds from the sale of such production have been remitted to the Trust by SandRidge.

(3)                  Volumes produced from January 1, 2012 to December 31, 2012 regardless of whether proceeds from the sale of such production have been remitted to the Trust by SandRidge

(4)                  Volumes produced from January 1, 2013 to December 31, 2013 regardless of whether proceeds from the sale of such production have been remitted to the Trust by SandRidge

(5)                  Estimated proved reserves were determined using a 12-month average price for oil, NGLs and natural gas.

The Trust recognized net reductions to oil, NGLs and natural gas reserves associated with proved properties in the AMI of approximately 2,192.4 MBoe as a result of negative revisions due to well performance and pricing during 2013. Additionally, approximately 1,069.2 MBoe were converted from proved undeveloped reserves to proved developed reserves during 2013 as SandRidge drilled the Trust Development Wells in order to fulfill its drilling obligation.

The Trust recognized net reductions to oil, NGLs and natural gas reserves associated with proved properties in the AMI of approximately 2,378.5 MBoe as a result of negative revisions due to well performance and pricing during 2012. Additionally, approximately 3,171.9 MBoe were converted from proved undeveloped reserves to proved developed reserves during 2012 as SandRidge drilled the Trust Development Wells in order to fulfill its drilling obligation.

During 2011, the Trust recognized additions to oil, NGLs and natural gas reserves associated with proved properties in the AMI of approximately 921.8 MBoe as a result of positive revisions due to well performance.

Standardized Measure of Discounted Future Net Cash Flows (Unaudited)

The assumptions underlying the computation of the standardized measure of discounted cash flows are summarized as follows:

·                  the standardized measure includes estimates of proved oil, NGL and natural gas reserves and projected future production volumes based upon economic conditions;

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·                  pricing is applied based upon 12-month average market prices at December 31, 2013, 2012 and 2011. The calculated weighted average per unit prices for the Trust’s proved reserves and future net revenues were as follows;

·                  a discount factor of 10% per year is applied annually to the future net cash flows; and

·                  future income tax expenses are computed based upon the estimated effective state income tax rate of 0.35%. The Trust is not required to pay federal income taxes.

The summary below presents the Trust’s future net cash flows relating to proved oil, NGL and natural gas reserves based on the standardized measure in ASC Topic 932 (in thousands).

(1)              Includes the Trust’s proportionate share of production taxes and post-production costs. The Trust does not bear any development or operational costs related to wells.

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The following table represents the Trust’s estimate of changes in the standardized measure of discounted future net cash flows from proved reserves (in thousands):