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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

For the fiscal year ended December 31, 2013

OR

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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SANDRIDGE PERMIAN TRUST

2013 ANNUAL REPORT ON FORM 10-K

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All references to “we,” “us,” “our,” or the “Trust” refer to SandRidge Permian Trust. References to “SandRidge” refer to SandRidge Energy, Inc., and where the context requires, its subsidiaries. The royalty interests conveyed by SandRidge from its interests in certain properties in the Permian Basin in Andrews County, Texas and held by the Trust are referred to as the “Royalty Interests.” This report includes terms commonly used in the oil and natural gas industry, which are defined in the Glossary of Oil and Natural Gas Terms beginning on page 17.

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FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K includes “forward-looking statements” about the Trust, SandRidge and other matters discussed herein that are subject to risks and uncertainties within the meaning of Section 27A of the Securities Act of 1933, as amended, (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical fact included in this document, including, without limitation, statements under “Trustee’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of Part II and “Risk Factors” in Item 1A of Part I and elsewhere herein regarding the proved oil, natural gas liquids and natural gas reserves associated with the properties underlying the Royalty Interests, the Trust’s or SandRidge’s future financial position, business strategy, project costs and plans and objectives for future operations, information regarding target distributions, statements pertaining to future development activities and costs, statements regarding the number of development wells to be completed in future periods and information regarding production and reserve growth, are forward-looking statements. Actual outcomes and results may differ materially from those projected. Forward-looking statements are generally accompanied by words such as “estimate,” “target,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal,” “should,” “intend” or other words that convey the uncertainty of future events or outcomes. We have based these forward-looking statements on our current expectations and assumptions about future events. These statements are based on certain assumptions made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. The actual results or developments anticipated may not be realized or, even if substantially realized, they may not have the expected consequences to or effects on SandRidge’s business or the Trust’s results. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in such forward-looking statements. The Trust undertakes no obligation to publicly update or revise any forward-looking statements. Whether actual results and developments will conform to expectations and predictions is subject to a number of risks and uncertainties, including the risk factors discussed in Item 1A of Part I of this report.

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PART I

Item 1.                          Business

General

SandRidge Permian 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, 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’s affairs are administered by the Trustee, which maintains its offices at 919 Congress Avenue, Austin, Texas 78701. The Trust does not have any employees.

Copies of reports filed by the Trust under the Exchange Act are made available as soon as reasonably practicable after such materials are filed with or furnished to the Securities and Exchange Commission (“SEC”). Certain information concerning the Trust and Trust units as well as a link to the Trust’s filings with the SEC may be obtained at the following web site location: www.businesswire.com/cnn/per.htm. Any materials filed with the SEC may be read and copied at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549 or accessed via the SEC’s website at www.sec.gov. The Trust will also provide electronic or paper copies of its filings free of charge upon request to the Trustee.

Formation and Structure. The Trust was created to acquire and hold the Royalty Interests for the benefit of Trust unitholders pursuant to a trust agreement dated May 12, 2011, by and among SandRidge, the Trustee and the Delaware Trustee (as subsequently amended and restated as of August 16, 2011). Concurrent with the initial public offering described below, SandRidge conveyed to the Trust royalty interests in specified oil and natural gas properties in the Permian Basin located in Andrews County, Texas (the “Underlying Properties”). The Royalty Interests were derived from SandRidge’s interests in (a) 517 oil and natural gas wells developed as of April 1, 2011, including 21 wells awaiting completion at that time (together, the “Initial Wells”) and (b) the equivalent of 888 oil and natural gas development wells to be drilled (“Trust Development Wells”) within an area of mutual interest (“AMI”). As of December 31, 2013, the AMI consisted of approximately 16,000 gross acres (15,400 net acres) in the counties where the Underlying Properties are located.

The Trust issued 52,500,000 Trust units and 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. SandRidge owned 1,825,000 Trust common units and 13,125,000 Trust subordinated units at December 31, 2013. On January 9, 2014 SandRidge sold its remaining Trust common units. The common and subordinated units have identical rights and privileges, except with respect to their rights to receive distributions. See “—Distributions” 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 the Initial Wells and 70% of the proceeds (after deducting post-production costs and any applicable taxes) from the sale of oil, NGLs and natural gas production attributable to SandRidge’s net revenue interest in the Trust Development Wells beginning on the effective date of the conveyance, April 1, 2011. The Royalty Interests are not subject to field or lease operating expenses.

Under the terms of conveyances pursuant to which the Royalty Interests were granted to the Trust, SandRidge is obligated to act as a reasonably prudent operator in the AMI under the same or similar circumstances as it would if it were acting with respect to its own properties, disregarding the existence of the Royalty Interests as burdens affecting such properties. The conveyances generally permit SandRidge to sell all or any part of its interest in the Underlying Properties, if the Underlying Properties are sold subject to and burdened by the Royalty Interests; however, SandRidge may not sell any of the Underlying Properties subject to the Royalty Interest in the Trust Development Wells until it has satisfied its drilling obligation pursuant to the terms of the development agreement discussed below.

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. However, 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 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 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

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50% of the Royalty Interests will be retained by the Trust at the Termination Date and thereafter sold, and the net proceeds of the sale, as well as any remaining Trust cash reserves, will be 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.

Income Tax Considerations. The Trust is treated for federal and applicable state income tax purposes as a partnership. Trust unitholders are treated as partners in that partnership. For United States (“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. Each partner is required to take into account his or her share of items of income, gain, loss, deduction and credit of the partnership in computing his or her federal income tax liability, regardless of whether cash distributions are made to him or her by the partnership. Distributions by a partnership to a partner are generally not taxable to the partner (but instead reduce tax basis but not below zero) unless the amount of cash distributed to such partner is in excess of the partner’s adjusted tax basis in his or her partnership interest. The Trust’s activities result in the Trust having nexus in Texas and, therefore, make it subject to Texas franchise tax. The Trust is 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.

Agreements with SandRidge

In conjunction with the conveyance of the Royalty Interests to the Trust, the Trust entered into the following agreements with SandRidge and/or one of its wholly owned subsidiaries on August 16, 2011.

Development Agreement. The Trust entered into 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) 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 fulfills 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. Under the terms of the agreement, SandRidge is credited for having drilled one full Trust Development Well if a 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%. For wells in which SandRidge has a net revenue interest greater or less than 69.3%, it receives credit for such well in proportion that its net revenue interest in the well bears 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 certain circumstances, SandRidge may also receive credit for Trust Development Wells for wells drilled horizontally to the target formation. The Trust is not responsible for any costs related to the drilling of the Trust Development Wells or any other operating or capital costs associated with the wells.

A wholly owned subsidiary of SandRidge granted to the Trust a lien (the “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, which is reduced proportionately as the Trust Development Wells are drilled and perforated for completion. The lien is reduced and the properties subject to the lien are released, in each case, as SandRidge fulfills its drilling obligation under the development agreement. The maximum amount potentially recoverable under the Drilling Support Lien was approximately $68.0 million as of December 31, 2013.

Administrative Services Agreement. The Trust entered into 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.

Derivatives Agreement and Other Hedging Arrangements. The Trust entered into a derivatives agreement with SandRidge, effective August 1, 2011, that provides the Trust with the economic effect of certain derivative contracts entered into between SandRidge and a third party. Under the derivatives agreement, SandRidge pays the Trust amounts it receives from its counterparty,

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and the Trust pays SandRidge any amounts that SandRidge is required to pay such counterparty. The Trust did not bear any costs related to the establishment of the underlying contracts and, except in limited circumstances involving the restructuring of an existing hedge or the novation of a hedge from SandRidge, does not have the ability to enter into its own derivative contracts. Substantially concurrent with the execution of the derivatives agreement and also on April 12, 2012 and March 13, 2013, 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 has 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. The hedging arrangements terminate on March 31, 2015.

Registration Rights Agreement. The Trust entered into a registration rights agreement for the benefit of SandRidge and certain of its affiliates and transferees, pursuant to which the Trust agreed to register the offering of the Trust units held by SandRidge and certain of its affiliates and permitted transferees upon request by SandRidge. Specifically, the Trust agreed:

·                  to use its reasonable best efforts to file a registration statement, including, if so requested, a shelf registration statement, with the SEC as promptly as practicable following receipt of a notice requesting the filing of a registration statement from holders representing a majority of the then outstanding registrable Trust units;

·                 to use its reasonable best efforts to cause the registration statement or shelf registration statement to be declared effective under the Securities Act as promptly as practicable after the filing thereof; and

·                 to continuously maintain the effectiveness of the registration statement under the Securities Act for 90 days (or continuously if a shelf registration statement is requested) after the effectiveness thereof or until the Trust units covered by the registration statement have been sold pursuant to such registration statement or until all registrable Trust units:

·                          have been sold pursuant to Rule 144 under the Securities Act if the transferee thereof does not receive “restricted securities”;

·                          have been sold in a private transaction in which the transferor’s rights under the registration rights agreement are not assigned to the transferee of the Trust units; or

·                          become eligible for resale pursuant to Rule 144 (or any similar rule then in effect under the Securities Act).

The holders will have the right to require the Trust to file no more than five registration statements in aggregate.

In connection with the preparation and filing of any registration statement, SandRidge will bear all costs and expenses incidental to any registration statement, excluding certain internal expenses of the Trust, which will be borne by the Trustee, and any underwriting discounts and commissions, which will be borne by the seller of the Trust units. One such registration statement was filed and declared effective during 2012 and remains effective currently. The Trust does not bear any expenses associated with such transactions.

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. The first distribution covered production for the five-month period from April 1, 2011 to August 31, 2011. The remaining distributions each cover production for a three-month period. The amount of Trust revenues and cash distributions to Trust unitholders depends on:

·                  the timing of initial production from the Trust Development Wells;

·                  oil, NGL and natural gas prices received;

·                  volume of oil, NGLs and natural gas produced and sold;

·                  amounts realized and paid under derivative arrangements;

·                  post-production costs and any applicable taxes; and

·                  the Trust’s general and administrative expenses.

The amount of the quarterly distributions will fluctuate from quarter to quarter, depending on the factors discussed above. There is no minimum required distribution. However, in order to provide support for cash distributions on the common units, SandRidge agreed to subordinate 13,125,000 of the Trust units it received in exchange for conveyance of the Royalty Interests, which constitute

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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 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.

The following table sets forth the Subordination Threshold and Incentive Threshold for each remaining quarterly distribution through the first quarterly distribution in 2017, as set out in the trust agreement.

(1)               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.

(2)               Each of the Subordination Threshold (80% of quarterly target distribution) and Incentive Threshold (120% of quarterly target distribution) terminates after the fourth full calendar quarter following SandRidge’s completion of its drilling obligation. Amounts have been rounded to two decimal places and are presented as set forth in the trust agreement. Actual distributions are declared and paid based upon a calculation carried out to three decimal places.

(3)               A distribution of $0.641 per unit was declared on January 30, 2014 and will be paid on February 28, 2014. See Note 8 to the financial statements contained in Item 8 of this report for further discussion.

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, the Trust may borrow funds from the Trustee or other lenders, including SandRidge, to pay such expenses. The Trustee does not intend to lend funds to the Trust. If such funds are borrowed, no further distributions will be made to unitholders (except in respect of any previously determined quarterly distribution amount) until the borrowed funds have been repaid, except that if SandRidge loans such funds, SandRidge may permit the Trust to make distributions prior to SandRidge being repaid.

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Properties

As of December 31, 2013, the Trust’s 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) 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 following table presents the number of Initial Wells, Trust Development Wells drilled and Trust Development Wells to be drilled at the dates shown.

(1)                  SandRidge is credited for having drilled one full Trust Development Well if a 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%. For wells in which SandRidge has a net revenue interest greater or less than 69.3%, SandRidge will receive proportionate credit for such well. In certain circumstances, SandRidge may also receive Trust Development Well credit for horizontal wells drilled to such formation.

The Royalty Interests are in properties located in the greater Fuhrman-Mascho field, a field in Andrews County, Texas that produces primarily oil from the Grayburg/San Andres formation in the Permian Basin. The Permian Basin extends throughout southwestern Texas and southeastern New Mexico over an area approximately 250 miles wide and 300 miles long. It is one of the largest, most active and longest-producing oil basins in the United States. The Permian Basin has been producing oil for over 80 years resulting in cumulative production of more than 29 billion barrels.

Proved Reserves

The following estimates of net proved oil, NGL and natural gas reserves are based on reserve reports prepared by independent petroleum engineers. The PV-10 and Standardized Measure shown in the table below are not intended to represent the current value of estimated oil, NGL and natural gas reserves attributable to the Royalty Interests as of the dates shown. The reserve reports as of December 31, 2013, 2012 and 2011 were based on SandRidge’s drilling schedule and the average price during the 12-month periods ended December 31, 2013, 2012 and 2011, using first-day-of-the-month prices for each month. Refer to “Risk Factors” in Item 1A of this report and “Trustee’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this report in evaluating the reserve information presented below.

All of the oil, NGL and natural gas reserves in these reports were estimated by independent petroleum engineers. The process to review and estimate the reserves begins with a staff reservoir engineer collecting and verifying all pertinent data, including but not limited to well test data, production data, historical pricing, cost information, property ownership interests, reservoir data, and geosciences data. This data was reviewed by members of SandRidge’s Reservoir Engineering Department and various levels of SandRidge management for accuracy, before consultation with the independent petroleum engineers. Members of SandRidge’s Reservoir Engineering Department consulted regularly with the independent petroleum engineers during the reserve estimation process to review properties, assumptions, and any new data available. SandRidge’s internal reserve estimates and methodologies were compared to the independent petroleum engineers’ estimates and conclusions before the reserve estimates were included in the independent petroleum engineers’ reports. Additionally, SandRidge’s senior management reviewed and approved the reserve reports contained herein.

Internal Controls. SandRidge’s Senior Vice President — Corporate Reservoir Engineering is the technical person primarily responsible for overseeing the preparation of the Trust’s reserve estimates. He has a Bachelor of Science degree in Petroleum Engineering with over 30 years of practical industry experience, including over 28 years of estimating and evaluating reserve information. In addition, SandRidge’s Senior Vice President — Corporate Reservoir Engineering has been a certified professional engineer in the state of Oklahoma since 2007 and a member of the Society of Petroleum Engineers since 1980.

SandRidge’s Reservoir Engineering Department continually monitors asset performance, making reserves estimate adjustments, as necessary, to ensure the most current reservoir information is reflected in reserves estimates. Reserve information includes production histories as well as other geologic, economic, ownership and engineering data. The corporate Reservoir department currently has a total of 17 full-time employees, comprised of five degreed engineers, and 12 engineering analysts/technicians with a minimum of a four-year degree in mathematics, economics, finance or other business or science field.

SandRidge maintains a continuous education program for engineers and technicians on new technologies and industry advancements and also offers refresher training on basic skill sets.

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In order to ensure the reliability of reserves estimates, SandRidge’s internal controls observed within the reserve estimation process include:

·         No employee’s compensation is tied to the amount of reserves booked.

·         Reserves estimates are prepared by experienced reservoir engineers or under their direct supervision.

·         The Reservoir Engineering Department reports directly to SandRidge’s Chief Operating Officer.

·         The Reservoir Engineering Department follows comprehensive SEC-compliant internal policies to determine and reportproved reserves including:

·      confirming that reserve estimates include all properties owned and are based upon proper working and net revenue interests;

·      reviewing and using in the estimation process data provided by other departments within SandRidge such as Accounting; and

·      comparing and reconciling internally generated reserve estimates to those prepared by third parties.

Independent petroleum engineers estimated all of the proved reserve information in these reports, in accordance with the definitions and guidelines of the SEC and in conformity with the Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. They are independent petroleum engineers, geologists, geophysicists, and petrophysicists; and do not own an interest in these properties and are not employed on a contingent basis. The qualifications of the independent petroleum engineer’s technical personnel primarily responsible for overseeing the  preparation of the Company’s reserves estimates included in this report are set forth below. These qualifications meet or exceed the Society of Petroleum Engineers’ standard requirements to be a professionally qualified Reserve Estimator and Auditor.

Netherland, Sewell & Associates, Inc. (“Netherland Sewell”).

·                  practical experience in petroleum engineering ranging from more than 14 years to more than 25 years and experience estimating and evaluating reserve information ranging from more than nine years to more than 20 years;

·                  Licensed Professional Engineers in the states of Texas and Louisiana and Licensed Professional Geoscientists in the State of Texas; and

·                  Bachelor of Science Degree in Civil Engineering, Bachelor of Science Degree in Mechanical Engineering, Bachelor of Science Degree in Geology, Master of Science Degree in Geology and Master of Business Administration Degree.

Reporting of Natural Gas Liquids. Natural gas liquids, or NGLs, are produced as a result of the processing of a portion of the Trust’s natural gas production stream. At December 31, 2013, NGLs comprised approximately 9% of the Trust’s total proved reserves on a barrel equivalent basis and represented volumes to be produced from properties where contracts are in place for the extraction and separate sale of NGLs. NGLs are products sold by the gallon. In reporting proved reserves and production of NGLs, production and reserves have been included in barrels. The extraction of NGLs in the processing of natural gas reduces the volume of natural gas available for sale. All production information related to natural gas is reported net of the effect of any reduction in natural gas volumes resulting from the processing and extraction of NGLs.

A summary of the Trust’s proved oil, NGL and natural gas reserves, all of which are located in the continental United States, is presented below:

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(1)                  Determined using a 12-month average of the first-day-of-the-month prices for oil and natural gas without giving effect to derivative transactions. The prices used in the reserve report yield weighted average wellhead prices, which are based on first-day-of-the-month index prices and adjusted for transportation and regional price differentials. The index prices and the equivalent weighted average wellhead prices are shown in the table below.

(2)                  PV-10 is the present value of estimated future net revenue to be generated from the production of proved reserves, discounted at 10% per annum to reflect timing of future cash flows and calculated without deducting future income taxes. PV-10 is a non-GAAP financial measure and generally differs from standardized measure of discounted net cash flows, or Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized Measure are intended to represent an estimate of fair market value of the Royalty Interests. PV-10 is used by the industry as an arbitrary reserve asset value measure to compare the relative size and value of the proved reserves held by companies without regard to the specific tax characteristics of such entities. The following table provides a reconciliation of Standardized Measure to PV-10:

(3)              Standardized Measure represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development and production costs, and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as are used to calculate PV-10. Standardized Measure differs from PV-10 as Standardized Measure includes the effect of future income taxes.

Proved reserves are those quantities of oil, NGLs and natural gas that, 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 estimation. To be classified as proved reserves, the project to extract the oil or natural gas must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

The area of a reservoir considered 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 natural 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 as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty.

Where direct observation from well penetrations has defined a highest known oil 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.

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Reserves that can be produced economically through application of improved recovery techniques (such as 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. In determining the amount of proved reserves, the price used must be the average price during the 12-month period prior to the ending date of the period covered by the reserve 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.  During 2013, SandRidge drilled 107 Trust Development Wells, resulting in the conversion of approximately 1.1 MMBoe of proved undeveloped reserves to proved developed reserves. At December 31, 2013, all of these wells were classified as proved developed producing properties. Additionally, proved undeveloped reserves decreased by approximately 1.2 MMBoe as a result of downward revisions due to well performance and pricing. SandRidge is not required to drill Trust Development Wells on locations with respect to which proved undeveloped reserves have previously been identified for the Trust. In this regard, Trust Development Wells were drilled during 2013 on locations different than those included in the reserve report prepared as of December 31, 2012. As a result, and because no more than 888 Trust Development Wells are to be drilled for the Trust, certain locations with proved undeveloped reserves were removed from the drilling plan developed for the Trust, resulting in downward revisions of 1.7 MMBoe during the period.

During 2012, SandRidge drilled 259 Trust Development Wells, resulting in the conversion of approximately 3.2 MMBoe of proved undeveloped reserves to proved developed reserves. At December 31, 2012, 237 of these wells were classified as proved developed producing properties. Additionally, proved undeveloped reserves decreased by approximately 3.0 MMBoe as a result of downward revisions due to well performance and pricing.

On August 16, 2011, royalty interests in Trust Development Wells were conveyed to the Trust. At that time, there were a total of 16.1 MMBoe of proved reserves associated with the Royalty Interests in such Trust Development Wells. By December 31, 2011, SandRidge had drilled 192 Trust Development Wells on proved undeveloped locations, resulting in the conversion of approximately 3.0 MMBoe of proved undeveloped reserves to proved developed reserves. At December 31, 2011, 167 of these wells were classified as proved developed producing properties with the remaining wells still in progress. In addition, there were five wells that were drilled yet to be classified as Trust Development Wells, resulting in the conversion of approximately 0.1 MMBoe of proved undeveloped reserves. Additionally, certain locations with proved undeveloped reserves were removed from the drilling plan developed for the Trust and replaced with locations different than those included in the reserve report prepared as of December 31, 2010, resulting in downward revisions of 0.2 MMBoe during the period.

Under the terms of the development agreement, SandRidge is obligated to drill, or cause to be drilled, the remaining Trust Development Wells by March 31, 2016. The Trust does not bear any costs associated with drilling the Trust Development Wells.

Production and Price History

The following tables set forth information regarding the net oil, NGL and natural gas production attributable to the Royalty Interests and certain price and cost information for each of the periods indicated.

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(1)         Production volumes and related revenues and expenses for the year ended December 31, 2013 (included in SandRidge’s 2013 net revenue distributions to the Trust) represent production from September 1, 2012 to August 31, 2013.

(2)         Production volumes and related revenues and expenses for the year ended December 31, 2012 (included in SandRidge’s 2012 net revenue distributions to the Trust) represent production from September 1, 2011 to August 31, 2012.

(3)         Production volumes and related revenues and expenses for the year ended December 31, 2011 (included in SandRidge’s 2011 net revenue distribution to the Trust) represent production from April 1, 2011 to August 31, 2011.

(4)         Includes impact of derivative settlements attributable to production from September 1, 2012 to August 31, 2013 for the year ended December 31, 2013, from September 1, 2011 to August 31, 2012 for the year ended December 31, 2012 and from April 1, 2011 to August 31, 2011 for the year ended December 31, 2011.

Productive Wells

The following table sets forth as of December 31, 2013 the number of productive wells within the AMI subject to the Royalty Interests. Productive wells consist of producing wells and wells capable of producing, including oil wells awaiting connection to production facilities and natural gas wells awaiting pipeline connections to commence deliveries. Gross wells are the total number of producing wells subject to the Royalty Interests and net wells are the sum of the Trust’s fractional royalty interests owned in gross wells.

Developed and Undeveloped Acreage

The following table sets forth information regarding developed and undeveloped acreage within the AMI subject to the Royalty Interests at December 31, 2013:

Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage is established prior to such date, in which event the lease will remain in effect until production has ceased. The following table sets forth as of December 31, 2013 the expiration periods of the gross and net acres that are subject to leases in the undeveloped acreage summarized in the above table.

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(1)                  Leases remaining in effect until development efforts or production on the developed portion of the particular lease has ceased.

Drilling Activity

The following table sets forth information with respect to wells completed within the AMI and subject to the Royalty Interests during each of the periods indicated. The information presented is not necessarily indicative of future performance, and should not be interpreted to present any correlation between the number of productive wells drilled and quantities or economic value of reserves found. Productive wells are those that produce commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return. Gross wells refer to the total number of wells in which the Trust had a royalty interest and net wells refer to gross wells multiplied by the Trust’s weighted average royalty interest percentage. As of December 31, 2013, there were 25 gross (13.0 net) wells subject to the Royalty Interests drilling or awaiting completion.

(1)                   Represents wells completed within the AMI and subject to the Royalty Interests during the period from August 16, 2011, the date of the Royalty Interests conveyance, to December 31, 2011.

Marketing and Customers

Pursuant to the terms of the conveyance creating the Royalty Interests, SandRidge has the responsibility to market, or cause to be marketed, the oil and natural gas production attributable to the Underlying Properties. The terms of the conveyance creating the Royalty Interests do not permit SandRidge to charge any marketing fees when determining the net proceeds upon which the royalty payments are calculated, except for marketing fees and costs of non-affiliates. As a result, the net proceeds to the Trust from the sales of oil, NGL and natural gas production from the Underlying Properties are determined based on the same price (net of post-production costs) that SandRidge receives for oil, NGL and natural gas production attributable to SandRidge’s remaining interest in the Underlying Properties.

SandRidge sells oil, NGLs and natural gas from the Underlying Properties to a variety of customers, including oil and natural gas companies and trading and energy marketing companies. During 2013 two customers individually accounted for more than 10% of total revenue attributable to the Royalty Interests compared to one customer in 2011 and 2012. The number of readily available purchasers for the production from the Underlying Properties makes it unlikely that the loss of a single customer in the areas in which SandRidge sells oil, NGL and natural gas production from the Underlying Properties would materially affect the Trust’s revenue. The Trust is not committed under any existing contracts or agreements to provide fixed and determinable quantities of oil or natural gas in the future. See below for additional information on the Trust’s major customers.

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Title to Properties

The Underlying Properties are subject to certain burdens that are described in more detail below. To the extent that these burdens and obligations affect SandRidge’s rights to production and the value of production from the Underlying Properties, they have been taken into account in calculating the Trust’s interest and in estimating the size and value of the reserves attributable to the Royalty Interests. SandRidge’s interests in the oil and natural gas properties comprising the Underlying Properties are typically subject, in one degree or another, to one or more of the following:

·                  royalties and other burdens, express and implied, under oil and natural gas leases;

·                  production payments and similar interests and other burdens created by SandRidge or its predecessors in title;

·                  a variety of contractual obligations arising under operating agreements, farmout agreements, production sales contracts and other agreements that may affect the properties or their titles;

·                  liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors and contractual liens under operating agreements that are not yet delinquent or, if delinquent, are being contested in good faith;

·                  pooling, unitization and communitization agreements, declarations and orders;

·                  easements, restrictions, rights-of-way and other matters that commonly affect real property;

·                  conventional rights of reassignment that obligate SandRidge to reassign all or part of a property to a third party if SandRidge intends to release or abandon such property; and

·                  rights reserved to or vested in the appropriate governmental agency or authority to control or regulate the Underlying Properties.

SandRidge believes that its title to the Underlying Properties is, and the Trust’s title to the Royalty Interest is, good and defensible in accordance with standards generally accepted in the oil and natural gas industry, subject to such exceptions as are not so material as to detract substantially from the use or value of such properties or Royalty Interests. Consistent with industry practice, SandRidge has not yet obtained drilling title opinions on the properties upon which SandRidge intends to drill the remaining Trust Development Wells. Prior to the drilling of a remaining Trust Development Well, SandRidge expects that a drilling title opinion to identify defects in title to the leasehold will be obtained. Frequently, as a result of such examinations, certain curative work must be done to correct identified title defects, and such curative work entails time and expense. SandRidge will not be relieved of its obligation to drill a well if such title examination prior to drilling reveals a title defect preventing SandRidge from drilling such drill site.

SandRidge acquired its interests in the Underlying Properties in July 2010 as part of its acquisition of Arena Resources, Inc. (“Arena”). Arena acquired its working interest in a large portion of the Underlying Properties in 2004, and acquired interests in additional Underlying Properties from 2005 through 2009 through a variety of means, including through the acquisition of oil and natural gas leases directly from the mineral owner, through assignments of oil and natural gas leases by the lessee who originally obtained leases from the mineral owner, through farmout agreements that grant the right to earn interests in the properties covered by such agreements by drilling wells, and through acquisitions of other oil and natural gas interests.

Competition and Markets

The production and sale of oil, NGLs and natural gas is highly competitive. Competitors in the Permian Basin include major oil and gas companies, independent oil and gas companies, and individual producers and operators. There are numerous producers in the Permian Basin and competitive position in this area is affected by price, contract terms and quality of service.

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Oil, NGLs and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil, natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil, NGLs and natural gas.

Future price fluctuations for oil, NGLs and natural gas will directly impact Trust distributions, estimates of reserves attributable to the Royalty Interests and estimated and actual future net revenues to the Trust. Due to the many uncertainties that affect the supply and demand for oil, NGLs and natural gas, reliable predictions of future oil and natural gas supply and demand, future product prices or the effect of future product prices on Trust distributions cannot be made.

Seasonal Nature of Business

Generally, demand for oil and natural gas decreases during the summer months and increases during the winter months. Certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions and lease stipulations can limit drilling and producing activities and other oil and natural gas operations. These seasonal anomalies can pose challenges for meeting well drilling objectives and can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increased costs or delay operations.

Insurance

Insurance is maintained by the operators of the Underlying Properties, in accordance with industry practice, against some, but not all, of the operating risks to which the operators are exposed. Insurance policies include coverage for general liability (including sudden and accidental pollution), physical damage to oil and natural gas properties, auto liability, worker’s compensation and employer’s liability, among other things. At the depths and in the areas in which the Underlying Properties are operated, and in light of the vertical and horizontal drilling that are undertaken, high pressures or extreme drilling conditions are typically not encountered. Accordingly, control of well insurance for operations is not typically carried.

General liability insurance coverage up to $1 million per occurrence is maintained, which includes sudden and accidental environmental liability coverage for the effects of pollution on third parties arising from operations. Insurance policies contain aggregate policy limits and in most cases, deductibles (generally ranging from $25,000 to $1 million) that must be met prior to recovery. These insurance policies are subject to certain customary exclusions and limitations. In addition, $100 million in excess liability coverage is maintained, which is in addition to and triggered if the general liability per occurrence limit is reached.

All of SandRidge’s third-party contractors are required to sign master services agreements in which they agree to indemnify SandRidge for injuries and deaths of the service provider’s employees as well as contractors and subcontractors hired by the service provider. Similarly, SandRidge generally agrees to indemnify each third-party contractor against claims made by employees of SandRidge and SandRidge’s other contractors. Additionally, each party generally is responsible for damage to its own property.

The third-party contractors that perform hydraulic fracturing operations sign the master services agreements containing the indemnification provisions noted above. Currently there are no insurance policies in effect intended to provide coverage for losses solely related to hydraulic fracturing operations. However, general liability and excess liability insurance policies are believed to cover third-party claims related to hydraulic fracturing operations and associated legal expenses, in accordance with, and subject to, the terms of such policies.

The purchase of insurance, coverage limits and deductibles is re-evaluated annually by SandRidge. Future insurance coverage for the oil and natural gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable. No assurance can be given that insurance may be maintained in the future at rates considered reasonable. Self-insurance or only catastrophic coverage may be elected for certain risks in the future. The Trust does not maintain any insurance policies or coverage.

Regulation

Oil and Natural Gas Regulations. The oil and natural gas industry is extensively regulated by numerous federal, state, local and regional authorities, as well as Native American tribes. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, and Native American tribes are authorized by statute to issue rules and regulations affecting the oil and natural gas industry and its individual members, some of which carry substantial penalties for noncompliance. Although the regulatory burden on the oil and natural gas industry increases the cost of doing business and, consequently, affects it profitability, these burdens generally do not affect SandRidge any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production. The availability, terms and cost of transportation significantly affect sales of oil and natural gas.

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The interstate transportation and sale for resale of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.

Sales of oil, NGLs and natural gas are not currently regulated and are made at market prices. Although oil, NGL and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. Whether new legislation to regulate oil, NGL and natural gas prices might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the Underlying Properties cannot be predicted.

Drilling and Production.  Operations are subject to various types of regulation at federal, state, local and Native American tribal levels.  These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations.  Most states, and some counties, municipalities and Native American tribal areas also regulate one or more of the following activities:  the location of wells, the method of drilling and casing wells, the timing of construction or drilling activities, the rates of production, or “allowables”, the use of surface or subsurface waters, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells, and the notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties.  Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases.  In some instances, forced pooling or unitization may be implemented by third parties and may reduce SandRidge’s interest in the unitized properties.  In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production.  These laws and regulations may limit the amount of oil and natural gas production from its wells or limit the number of wells or the locations at which can be drilled. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas, and natural gas liquids within its jurisdiction.

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure of decommissioning of production facilities and pipelines, and for site restorations, in areas where the Underlying Properties are located.  For example, the Railroad Commission of Texas imposes financial assurance requirements on operators, with additional financial security required for offshore wells and the United States Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration.

Natural Gas Sales and Transportation.  Historically, federal legislation and regulatory controls have affected the price of the natural gas SandRidge produces and the manner in which SandRidge markets its production.  FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978.  Various federal laws enacted since 1978 have resulted in the removal of all price and non-price controls for sale of domestic natural gas sold in first sales, which include all of the Company’s sales of its own production.  Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.

FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which SandRidge may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that SandRidge produces, as well as the revenues it receives for sales of its natural gas and release of its natural gas pipeline capacity.  Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas.  Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company.  FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines.  However, the natural gas industry historically has been very heavily regulated; therefore, SandRidge cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can SandRidge determine what effect, if any, future regulatory changes might have on the Company’s natural gas related activities.

Under FERC’s current regulatory regime, transmission services must be provided on an open-access, nondiscriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive.  Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in-state waters.  Although its policy is still in flux, in the past FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase the cost of transporting gas to point-of-sale locations.

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Environmental Regulation. The exploration, development and production of oil and natural gas are subject to stringent and comprehensive federal, state regional and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection or to employee health and safety. These laws and regulations may, among other things, require permits to conduct drilling, water withdrawal and waste disposal operations; govern the amounts and types of substances that may be disposed or released into the environment; limit or prohibit construction or drilling activities or require formal mitigation measures in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; require investigatory and remedial actions to mitigate pollution conditions arising from SandRidge’s operations or attributable to former operations; impose restrictions designed to protect employees from exposure to hazardous substances; and impose obligations to reclaim and abandon well sites and pits. Failure to comply with these laws and regulations may result in the assessment of sanctions, including monetary penalties, the imposition of remedial obligations and the issuance of orders enjoining operations in affected areas. Pursuant to such laws, regulations and permits, SandRidge and other operators of the Underlying Properties may be subject to operational restrictions and have made and are likely to continue to be required to make, capital and other compliance expenditures.

Increasingly restrictions and limitations are being placed on activities that may affect the environment. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly construction, drilling, water management, completion, waste handling, storage, transport, disposal, or remediation requirements or emission or discharge limits could have a material adverse effect on the proceeds available to the Trust under the Royalty Interests. Moreover, accidental releases or spills may occur in the course of operations on the Underlying Properties and there can be no assurance that significant costs and liabilities as a result of such releases or spills, including third-party claims for damage to property and natural resources or personal injury will be incurred.

The following is a summary of the more significant existing environmental and employee health and safety laws and regulations applicable to the oil and natural gas industry and for which compliance may have a material adverse impact on the operation of the Underlying Properties.

Hazardous Substances and Wastes. The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also known as the Superfund law and comparable state laws impose joint and several liability, without regard to fault or legality of conduct, on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include current and prior owners or operators of the site where the release occurred and entities that disposed or arranged for the disposal of the hazardous substances at the site. Under CERCLA, these “responsible persons” may be subject to strict, joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain environmental and health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury, natural resource damage and property damage allegedly caused by the release of hazardous substances into the environment. CERCLA also authorizes the Environmental Protection Agency (“EPA”) and, in some instances, third parties to act in response to threats to the public health or the environment and to seek recovery from the responsible classes of persons the costs the third parties incur. Materials used and generated in the course of operations with respect to the Underlying Properties may be regulated as hazardous substances. To date, none of the Underlying Properties have been designated as a Superfund site. Wastes are generated that are subject to the requirements of the Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes. RCRA imposes strict requirements on the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Drilling fluids, produced waters and other wastes associated with the exploration, production and/or development of oil and natural gas are currently exempt from regulation as hazardous wastes under RCRA. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. In September 2010, the Natural Resources Defense Council filed a petition for rulemaking with the EPA requesting reconsideration of the RCRA exemption for exploration, production, and development wastes. To date, the EPA has not taken any formal action on the petition. Any change in the RCRA exemption for such wastes could result in an increase in costs to manage and dispose of wastes, which could have a material adverse effect on the cash distributions to the Trust unitholders. In the course of operations, with respect to the Underlying Properties, petroleum hydrocarbon wastes and ordinary industrial wastes that are subject to regulation under the RCRA are generated. The Underlying Properties are being operated in substantial compliance with all regulations regarding the handling and disposal of oil and natural gas exploration and production wastes from operations.

Air Emissions. The Clean Air Act, as amended, the Outer Continental Shelf Lands Act (the “OCSLA”) and comparable state laws and regulations restrict the emission of air pollutants from many sources and also impose various permitting, monitoring and reporting requirements. These laws and regulations may require pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, strict compliance with air permit requirements or the utilization of specific equipment or technologies to control emissions. Obtaining permits has the potential to delay the development of oil and natural gas projects. While SandRidge may be required to incur certain capital expenditures for air pollution control equipment or other air emissions-related issues, SandRidge does not believe that such requirements will have a material adverse effect on its ability

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to satisfy its obligations to the Trust. Additionally, violations of lease conditions or regulations related to air emissions can result in civil and criminal penalties, as well as potential court injunctions curtailing operations and canceling leases. Such enforcement liabilities can result from either governmental or citizen prosecution. In August 2012, the EPA issued final regulations that established new air emission controls for oil and natural gas production and natural gas processing, including, among other things, new source performance standards for volatile organic compounds that would apply to newly hydraulically fractured wells, existing wells that are re-fractured, compressors, pneumatic controllers, storage vessels and natural gas processing plants placed in service after August 2011. However, on January 16, 2013, the EPA made an unopposed motion in federal court to seek an abeyance of legal challenges to the regulations while it reconsiders and potentially revises portions of the new rules. The EPA has also implemented an engine emission testing program to ensure certain categories of engines, depending on the date manufactured, meet the EPA emission standards. The federal standard for engines manufactured before 2006 also requires emission testing on engines greater than 500 horsepower and strict engine maintenance plans to be in place by October 2013. SandRidge currently has such plans in place.

Water Discharges. The Federal Water Pollution Act, as amended (“Clean Water Act”), and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into navigable waters. Pursuant to these laws and accompanying regulations, permits must be obtained to discharge produced waters and sand, drilling fluids, drill cuttings and other substances related to the oil and natural gas industry into onshore, coastal and offshore waters of the United States or state waters. Any such discharge of pollutants into regulated waters must be performed in accordance with the terms of the permit issued by the EPA or the analogous state agency. The Clean Water Act and other laws, such as the OCSLA, require the development and implementation of spill response plans intended to prepare the owner of the facility to respond to a hazardous substance or oil discharge. In addition, spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters or adjoining shorelines in the event of a spill, rupture or leak from an onshore, or offshore, facility. The Clean Water Act and analogous state laws also require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities.

Climate Change. In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and certain other greenhouse gases (“GHGs”) present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the Clean Air Act. Accordingly, the EPA adopted rules that require a reduction in emissions of GHGs from motor vehicles and also trigger Clean Air Act construction and operating permit review for GHG emissions from certain stationary sources. EPA’s endangerment finding and GHG rules were upheld by the United States Court of Appeals for the D.C. Circuit in a June 2012 decision, and a petition for review of the case by the entire D.C. Circuit was denied in December 2012. The EPA has also adopted rules requiring the reporting of GHG emissions from onshore oil and natural gas production and processing facilities in the United States on an annual basis. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHG gases from, equipment and operations related to the Underlying Properties could require costs to be incurred by SandRidge to reduce emissions of GHGs associated with operations or could adversely affect demand for the oil and natural gas production attributable to the Royalty Interests. Finally, to the extent increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; such events could have an adverse effect on assets and operations related to the Underlying Properties. In addition, Congress has actively considered legislation to reduce emissions of GHGs and more than one-half of the states have begun taking actions to control and/or reduce emissions of GHGs, primarily through the adoption of a climate change action plan, completion of GHG emission inventories and/or regional GHG cap and trade programs. Any future federal laws or implementing regulations that may be adopted to address GHG emissions could adversely affect demand for the oil and natural gas production attributable to the Royalty Interests, and could have a material adverse effect on the Trust’s revenues.

Endangered Species. The federal Endangered Species Act (‘‘ESA’’) restricts activities that may affect endangered or threatened species or their habitats. Operations of the Underlying Properties are in substantial compliance with the ESA. If endangered species are located in areas of the Underlying Properties where seismic surveys, development activities or abandonment operations may be conducted, the work could be prohibited or delayed or expensive mitigation may be required. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia on September 9, 2011, the U.S. Fish and Wildlife Service is required to consider listing more than 250 species as endangered under the ESA. Under the September 9, 2011 settlement, the federal agency is required to make a determination on listing of the species as endangered or threatened over the six-year period ending with the agency’s 2017 fiscal year. The designation of previously unprotected species as threatened or endangered in areas where the Underlying Properties operations are located could cause SandRidge to incur increased costs arising from species protection measures or could result in limitations on exploration and production activities that could have an adverse impact on the ability to develop and produce reserves from the Underlying Properties. SandRidge is an active participant on various agency and industry committees that are developing or addressing various ESA and other federal and state agency programs to minimize potential impacts to its business and the Underlying Properties.

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Employee Health and Safety. The operations of SandRidge are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA Hazardous Communication Standard requires that information be maintained concerning hazardous materials used or produced in SandRidge’s operations and that this information be provided to employees. Pursuant to the Emergency Planning and Community Right-to-Know Act, also known as Title III of the federal Superfund Amendment and Reauthorization Act, businesses that store threshold amounts of chemicals that are subject to OSHA’s Hazardous Communication Standard must submit information to state and local authorities in order to facilitate emergency planning and response. That information is generally available to the public.

State and Local Regulation. The Underlying Properties are subject to state and other local regulations applicable to the drilling for, and the production and gathering of, oil and natural gas, including requirements relating to drilling permits, the location, spacing and density of wells, unitization and pooling of interests, the method of drilling, casing and equipping of wells, the protection of fresh water sources, the orderly development of common sources of supply of oil and natural gas, the operation of wells, allowable rates of production, the use of fresh water in oil and natural gas operations, saltwater injection and disposal operations, the plugging and abandonment of wells and the restoration of surface properties, the prevention of waste of oil and natural gas resources, the protection of the correlative rights of oil and natural gas owners and, where necessary to avoid unfair, unjust or discriminatory service, the fees, terms and conditions for the gathering of natural gas. These regulations may affect the number and location of Trust Development Wells and the amounts of oil and natural gas that may be produced from the Underlying Properties. Realized prices for the first sale of oil and natural gas are not subject to state regulation in Texas.

Hydraulic Fracturing. Oil and natural gas may be recovered from the Underlying Properties through the use of hydraulic fracturing, combined with sophisticated drilling. Hydraulic fracturing, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and gas commissions. However, the EPA has asserted federal regulatory authority over certain hydraulic fracturing practices not currently employed with respect to the Underlying Properties. In August 2012, the EPA issued final Clean Air Act regulations governing performance standards, including for the capture of air emissions released during hydraulic fracturing. However, in January 2013 the EPA submitted an unopposed motion to the United States Court of Appeals for the D.C. Circuit seeking to stay legal challenges to the Clean Air Act regulations while it reconsiders portions of the new rules. Also, federal legislation previously was introduced, but not enacted, to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In May 2012, the Bureau of Land Management within the U.S. Department of the Interior issued a proposed rule containing disclosure requirements and other mandates for hydraulic fracturing on federal lands, but in January 2013 it announced that it would be submitting a revised rule proposal. That revised proposed rule was published for public comment in May 2013.  The Department of Interior is now analyzing the comments and is expected to promulgate a final rule sometime in 2014 or 2015. Certain states, including Texas, have adopted regulations that require disclosure of the chemicals utilized in the hydraulic fracturing process that have imposed, or that could impose, more stringent permitting, disclosure, disposal and well construction requirements on hydraulic fracturing operations. For example, in December 2011, the Railroad Commission of Texas finalized regulations requiring public disclosure of all chemicals in fluids used in the hydraulic fracturing process. Local ordinances or other regulations may regulate or prohibit the performance of well drilling in general and hydraulic fracturing in particular. If new laws or regulations that significantly restrict hydraulic fracturing are adopted at either the state or federal level, fracturing activities with respect to the Underlying Properties could become subject to additional permit requirements or operational restrictions and also to associated permitting delays and potential increases in costs. These delays or additional costs could adversely affect the determination of whether a well is commercially viable. Restrictions on hydraulic fracturing could also reduce the amount of oil, NGLs or natural gas that is ultimately produced in commercial quantities from the Underlying Properties. In addition to asserting regulatory authority, a number of federal entities are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. In April 2012, President Obama issued an executive order that established a working group for the purpose of coordinating policy, information sharing and planning across federal agencies and offices regarding “unconventional natural gas production,” including hydraulic fracturing. In December 2012, the EPA issued an initial progress report on a study begun in 2011 of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a draft final report expected to be issued for peer review and comment in late 2014. The EPA has also announced an intent to propose by 2014 effluent limit guidelines that waste water from shale gas extraction operations must meet before going to a treatment plant; the agency also projects that it will publish an Advance Notice of Proposed Rulemaking regarding the Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Additionally, a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices, and certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources; the SEC to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing; and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. The studies and initiatives described above, depending on their degree of pursuit and any meaningful results obtained, could spur efforts to further regulate hydraulic fracturing under the Safe Drinking Water Act or other regulatory mechanisms. All of the acreage and

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undeveloped reserves within the AMI are subject to hydraulic fracturing procedures as the process is required to economically develop the Grayburg/San Andres formation.

Glossary of Oil and Natural Gas Terms

The following is a description of the meanings of some of the oil and natural gas industry terms used in this report.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to oil or other liquid hydrocarbons.

Boe. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil. Although an equivalent barrel of condensate or natural gas may be equivalent to a barrel of oil on an energy basis, it is not equivalent on a value basis as there may be a large difference in value between an equivalent barrel and a barrel of oil. For example, based on the commodity prices used to prepare the estimate of the Trust’s reserves at year-end 2013 of $93.42/ Bbl for oil and $3.67 / Mcf for natural gas, the ratio of economic value of oil to gas was approximately 25 to 1, even though the ratio for determining energy equivalency is 6 to 1.

Boe/d. Barrels of oil equivalent per day.

Btu or British thermal unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas, or in the case of a dry well, the reporting to the appropriate authority that the well has been abandoned.

Developed acreage. The number of acres that are assignable to productive wells.

Developed oil and natural gas reserves. Reserves of any category that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and natural gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to (i) gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building and relocating public roads, gas lines and power lines, to the extent necessary in developing the proved reserves, (ii) drill and equip development wells, development-type stratigraphic test wells and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly, (iii) acquire, construct and install, production facilities such as leases, flow lines, separators, treaters, heaters, manifolds, measuring devices and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems, and (iv) provide improved recovery systems.

Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry well. An exploratory, development or extension well that proves to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geological barriers, or both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas of interest, etc.

Fixed price swaps. The Trust receives a fixed price for the contract and pays a floating market price over a specified period for a contracted volume.

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

MBbls. Thousand barrels of oil or other liquid hydrocarbons.

MBbls/d. Thousand barrels of oil or other liquid hydrocarbons per day.

MBoe. Thousand barrels of oil equivalent.

Mcf. Thousand cubic feet of natural gas.

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MMBbls. Million barrels of oil or other liquid hydrocarbons.

MMBoe. Million barrels of oil equivalent.

MMBtu. Million British Thermal Units.

MMcf. Million cubic feet of natural gas.

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

Net revenue interests. A share of production after all burdens, such as royalty and overriding royalty interest, have been deducted from the working interest.

NGL. Natural gas liquids, such as ethane, propane, butanes and natural gasoline that are extracted from natural gas production streams.

Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Texas regulations require plugging of abandoned wells.

Present value of future net revenues (“PV-10”). The present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, calculated in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation and without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization. PV-10 is calculated using an annual discount rate of 10%.

Production costs.

(i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and natural gas produced. Examples of production costs (sometimes called lifting costs) are:

(A) Costs of labor to operate the wells and related equipment and facilities.

(B) Repairs and maintenance.

(C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

(D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

(E) Severance taxes.

(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining and marketing activities. To the extent that the support equipment and facilities are used in oil and natural gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

Productive well. A well that is found to be capable of producing oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

Proved developed reserves. Reserves that are both proved and developed.

Proved oil, NGL and natural gas reserves. Those quantities of oil, NGLs and natural gas that, 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 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 a reservoir considered 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 natural 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 as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty.

Where direct observation from well penetrations has defined a highest known oil 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.

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Reserves that 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. Reserves that are both proved and undeveloped.

PV-10. See “Present value of future net revenues” above.

Reserves. Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market, and all permits and financing required to implement the project.

Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e. absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e. potentially recoverable resources from undiscovered accumulations).

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.

Standardized measure or standardized measure of discounted future net cash flows. The present value of estimated future cash inflows from proved oil and natural gas reserves, less future development and production costs and future income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized Measure differs from PV-10 because Standardized Measure includes the effect of future income taxes on future net revenues.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or natural gas regardless of whether such acreage contains proved reserves.

Undeveloped oil, NGL and natural gas reserves. Reserves of any category 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.

(i) Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations are classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

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Item 1A.                 Risk Factors

Risks Related to the Units

Drilling for and producing oil and natural gas on the Underlying Properties are high risk activities with many uncertainties that could delay the anticipated drilling schedule for the remaining Trust Development Wells and adversely affect future production from the Underlying Properties. Any such delays or reductions in production could decrease cash that is available for distribution to unitholders.

The drilling and completion of the remaining Trust Development Wells are subject to numerous risks beyond the Trust’s and SandRidge’s control, including risks that could delay or change the current drilling schedule for the Trust Development Wells (including the drilling schedule of third-party operators that may drill the remaining Trust Development Wells) and the risk that drilling will not result in commercially viable oil and natural gas production. Drilling for oil and natural gas can be unprofitable if dry wells are drilled and if productive wells do not produce sufficient revenues to return a profit. SandRidge’s and any third-party operators’ decisions to develop or otherwise exploit certain areas within the AMI will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. The estimated costs of drilling, completing and operating wells are uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. A Trust Development Well that is successfully completed may not pay out the capital costs spent to drill it. Drilling and production operations on the Underlying Properties may be curtailed, delayed or canceled as a result of various factors, including the following:

·                  delays imposed by or resulting from compliance with regulatory requirements including permitting;

·                  unusual or unexpected geological formations and miscalculations;

·                  shortages of or delays in obtaining equipment and qualified personnel;

·                  shortages of or delays in obtaining water for hydraulic fracturing operations;

·                  equipment malfunctions, failures or accidents;

·                  lack of available gathering facilities or delays in construction of gathering facilities;

·                  lack of available capacity on interconnecting transmission pipelines;

·                  lack of adequate electrical infrastructure and water disposal capacity;

·                  unexpected operational events and drilling conditions;

·                  pipe or cement failures and casing collapses;

·                  pressures, fires, blowouts and explosions;

·                  lost or damaged drilling and service tools;

·                  loss of drilling fluid circulation;

·                  uncontrollable flows of oil, NGLs, natural gas, brine, water or drilling fluids;

·                  natural disasters;

·                  environmental hazards, such as oil, NGL and natural gas leaks, pipeline ruptures and discharges of toxic gases or well fluids;

·                  adverse weather conditions, such as extreme cold, fires caused by extreme heat or lack of rain and severe storms or tornadoes;

·                  reductions in oil and natural gas prices;

·                  oil and natural gas property title problems; and

·                  market limitations for oil and natural gas.

In the event that drilling of the Trust Development Wells is delayed or the Initial Wells or Trust Development Wells have lower than anticipated production due to one of the factors above or for any other reason, cash distributions to unitholders may be reduced. In addition, wells drilled in the Permian Basin in the AMI typically produce a large volume of water, which requires the drilling of saltwater disposal wells. SandRidge’s inability to drill these wells or otherwise dispose of the water produced from the Initial Wells and Trust Development Wells in an efficient manner could delay production and therefore the Trust’s receipt of proceeds from the Royalty Interests.

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Oil, NGL and natural gas prices fluctuate due to a number of factors that are beyond the control of the Trust and SandRidge, and lower prices could reduce proceeds to the Trust and cash distributions to unitholders.

The Trust’s reserves and quarterly cash distributions are highly dependent upon the prices realized from the sale of oil, NGLs and natural gas. The markets for these commodities are very volatile. Oil, NGL and natural gas prices can fluctuate widely in response to a variety of factors that are beyond the control of the Trust and SandRidge. These factors include, among others:

·                  regional, domestic and foreign supply of, and demand for, oil, NGLs and natural gas, as well as perceptions of supply of, and demand for, oil, NGLs and natural gas;

·                  the price of foreign imports;

·                  U.S. and worldwide political and economic conditions;

·                  the level of demand, and perceptions of demand, for oil, NGLs and natural gas;

·                  weather conditions and seasonal trends;

·                  anticipated future prices of oil, NGLs and natural gas, alternative fuels and other commodities;

·                  technological advances affecting energy consumption and energy supply;

·                  the proximity, capacity, cost and availability of pipeline infrastructure, treating, transportation and refining capacity;

·                  natural disasters and other acts of force majeure;

·                  domestic and foreign governmental regulations and taxation;

·                  energy conservation and environmental measures; and

·                  the price and availability of alternative fuels.

For oil, from January 1, 2010 through December 31, 2013, the highest monthly settled price on the New York Mercantile Exchange (“NYMEX”) was $113.93 per Bbl and the lowest was $71.92 per Bbl. For natural gas, from January 1, 2010 through December 31, 2013, the highest monthly NYMEX settled price was $5.81 per MMBtu (one million British Thermal Units) and the lowest was $2.04 per MMBtu. In addition, the market price of oil and natural gas is generally lower in the summer months than during the winter months of the year due to decreased demand for oil and natural gas for heating purposes during the summer season.

Lower oil, NGL and natural gas prices will reduce proceeds to which the Trust is entitled and may ultimately reduce the amount of oil, NGLs and natural gas that is economic to produce from the Underlying Properties. As a result, SandRidge or any third-party operator of any of the Underlying Properties could determine during periods of low oil, NGL or natural gas prices to shut in or curtail production from wells on the Underlying Properties. In addition, the operator of the Underlying Properties could determine during periods of low oil, NGL or natural gas prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, SandRidge or any third-party operator may abandon, at its cost, any well or property if it reasonably believes that the well or property can no longer produce oil, NGLs and natural gas in commercially economic quantities. This could result in termination of the portion of the Royalty Interest relating to the abandoned well or property, and SandRidge would have no obligation to drill a replacement well. In addition, lower oil, NGL and natural gas prices could make it more likely that leases in the undeveloped acreage will expire at the end of their respective primary terms as a result of the failure to establish production from such leasehold acreage in commercially paying quantities prior to such date. The volatility of oil, NGL and natural gas prices also reduces the accuracy of target distributions to Trust unitholders. For a discussion of certain risks related to the Trust’s hedging arrangements, see ‘‘—The hedging arrangements for the Trust cover only a portion of the production attributable to the Trust, and such contracts limit the Trust’s ability to benefit from commodity price increases for hedged volumes above the corresponding hedge price.’’

Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the Trust and the value of the Trust units.

The value of the Trust units and the amount of future cash distributions to the Trust unitholders will depend upon, among other things, the accuracy of the reserves estimated to be attributable to the Royalty Interests. It is not possible to accurately measure underground accumulations of oil, NGLs and natural gas in an exact way and estimating reserves is inherently uncertain. As discussed below, the process of estimating oil, NGL and natural gas reserves requires interpretations of available technical data and many assumptions. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of the Trust’s reserves. This could result in actual production and revenues for the Underlying Properties being materially less than estimated amounts.

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In order to prepare the estimates of reserves attributable to the Underlying Properties and the Trust, production rates and the timing of development expenditures must be projected. In so doing, available geological, geophysical, production and engineering data must be analyzed. The extent, quality and reliability of this data can vary.

In addition, petroleum engineers are required to make subjective estimates of underground accumulations of oil, NGLs and natural gas based on factors and assumptions that include:

·                  historical production from the area compared with production rates from other producing areas;

·                  oil and natural gas prices, production levels, Btu content, production expenses, transportation costs, severance and excise taxes and capital expenditures; and

·                  the assumed effect of governmental regulation.

Changes in these assumptions or actual production costs incurred and results of actual development could materially decrease reserve estimates. Estimates of reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes, and other factors. As with all drilling programs, there is a risk that the quality of the target reservoir is less than that assumed for purposes of the Trust’s reserve reports. Under the development agreement, SandRidge receives credit for drilling a Trust Development Well if the well is drilled for completion in the AMI within the Grayburg/San Andres formation, even if such well does not successfully produce hydrocarbons. As a result, unitholders may not receive the benefit of the total amount of proved undeveloped reserves reflected in the Trust’s reserve reports, even if SandRidge has satisfied its drilling obligation.

In certain circumstances the Trust may have to make cash payments under the hedging arrangements and these payments could be significant.

If oil or natural gas prices rise, the Trust may be obligated to make cash payments to SandRidge or the Trust’s hedge counterparties, which could, in certain circumstances, be significant. Swap contracts underlying the derivatives agreement between SandRidge and the Trust and swap contracts entered into between the Trust and unaffiliated hedge counterparties provide the Trust with the right to receive from SandRidge or the hedge counterparties, as applicable, the excess of the fixed price specified in the hedge contract over a floating market price, multiplied by the volume of production hedged. If the floating market price exceeds the specified fixed price, the Trust must pay SandRidge or its hedge counterparties, as applicable, this difference in price multiplied by the volume of production hedged, even if the production attributable to the Royalty Interests is insufficient to cover the volume of production specified in the applicable hedge contracts. Accordingly, if the production attributable to the Royalty Interests is less than the volume hedged and the floating market price exceeds the specified fixed price, the Trust will have to make payments against which it will have insufficient offsetting cash receipts from the sale of production attributable to the Royalty Interests. Furthermore, if one or more of the purchasers of the production attributable to the Underlying Properties defaults on a payment obligation, the Trust may have insufficient cash receipts to make payments under the hedging arrangements. If these payments become too large, the Trust’s liquidity and cash available for distribution may be adversely affected. In addition, the Trust’s obligations to the counterparties under its direct hedge contracts are secured by a first priority lien on the Royalty Interests. If the Trust fails to make any required payments to its unaffiliated hedge counterparties, these counterparties will have a right to foreclose on the Royalty Interests and may sell the Royalty Interests in order to satisfy the Trust’s payment obligations.

Target distributions, Subordination Thresholds and Incentive Thresholds are based on assumptions made in mid-2011 that, when made, were inherently subjective and subject to significant business, economic, financial, legal, regulatory and competitive risks and uncertainties that could cause actual cash distributions to differ materially from the target.

The target distributions, Subordination Thresholds and Incentive Thresholds, as set forth in the Prospectus and described below in Part II Item 7, Trustee’s Discussion and Analysis of Financial Conditions and Results of Operations, were based on SandRidge’s calculations, and SandRidge did not receive an opinion or report on such calculations from any independent accountants, financial advisers, or engineers. Such calculations were based on assumptions made in mid-2011 about drilling, production, oil and natural gas prices, hedging activities, capital expenditures, expenses, tax rates and production tax credits under state law, the location of Trust Development Wells and other matters that were inherently uncertain and were subject to significant business, economic, financial, legal, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from the target. For example, the targets have assumed that oil and natural gas production would be sold at prices consistent with settled NYMEX prices for April through June 2011, and monthly NYMEX forward pricing as of July 15, 2011 for the remainder of the period ending March 31, 2014, and assumed price increases after March 31, 2014 of 2.5% annually, capped at $120.00 per Bbl of oil in 2023 and $7.00 per MMBtu of natural gas in 2022, respectively. However, actual sales prices may be significantly lower. Additionally, these estimates assumed that the Trust Development Wells would be drilled on SandRidge’s anticipated drilling schedule. However, to date, more Development Wells have been drilled than the number contemplated by SandRidge’s original drilling schedule. Further, the drilling of the Trust Development Wells may be delayed, Trust Development Wells may be drilled at locations with higher post-

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production expenses and applicable taxes and actual production volumes may be significantly lower than estimated. Further, after wells are completed, production operations may be curtailed, delayed or terminated as a result of a variety of risks and uncertainties, including those described above under “—Drilling for and producing oil and natural gas on the Underlying Properties are high risk activities with many uncertainties that could delay or change the anticipated drilling schedule for the remaining Trust Development Wells and adversely affect future production from the Underlying Properties. Any such delays or reductions in production could decrease cash that is available for distribution to unitholders.”

Furthermore, neither the target distribution nor the Subordination Threshold for each quarter during the subordination period necessarily represents the actual cash distributions unitholders will receive. To the extent actual production volumes or sales prices of oil and natural gas differ from the assumptions used to generate the target distributions, the actual distributions unitholders receive may be lower than the target distribution and the Subordination Threshold for the applicable quarter. For example, drilling of the Trust Development Wells ahead of the schedule assumed when the target distribution amounts were determined could cause actual distributions to fall below the target distribution amounts or Subordination Thresholds in later periods. Cash distributions to Trust unitholders below the target distribution amounts or the Subordination Thresholds may materially adversely affect the market price of the Trust units.

The subordination of certain Trust units held by SandRidge does not assure that unitholders will in fact receive any specified return on investment in the Trust.

Although SandRidge will not be entitled to receive any distribution on its subordinated units unless there is enough cash for all of the common units to receive a distribution equal to the Subordination Threshold for such quarter (which is 20% below the target distribution level for the corresponding quarter), the subordinated units constitute only a 25% interest in the Trust, and this feature does not guarantee that common units will receive a distribution equal to the Subordination Threshold, or any distribution at all. Additionally, the subordination period will terminate and the subordinated units will automatically convert into common units on a one-for-one basis, following which they will no longer be subject to the Subordination Thresholds at the end of the fourth full calendar quarter following SandRidge’s satisfaction of its drilling obligation with respect to the Trust Development Wells. Depending on the prices at which volumes attributable to the Trust are sold, the common units may receive distributions that are below the Subordination Threshold.

Quarterly cash distributions are made by the Trust based on the proceeds received by the Trust pursuant to the Royalty Interests for the preceding calendar quarter. If a quarterly cash distribution is lower than the target distribution amount or Subordination Threshold for any quarter, the common units will not be entitled to receive any additional distributions nor will the units be entitled to arrearages in any future quarter.

For Trust Development Wells drilled on properties where SandRidge is not the operator, SandRidge will rely on third-party operators to drill the Trust Development Wells, and for those Trust Development Wells where SandRidge is the operator, SandRidge may rely on third-party servicers to conduct the drilling operations.

SandRidge owns a majority working interest in substantially all of the locations on which it expects to drill the Trust Development Wells, and it expects to operate such wells during the subordination period. For Trust Development Wells drilled on properties where SandRidge is not the operator, however, SandRidge will rely on third-party operators to drill the Trust Development Wells. In addition, where SandRidge is the operator of a Trust Development Well, it may rely on third-party servicers to perform the necessary drilling operations. The ability of third-party servicers to perform such drilling operations will depend on those servicers’ financial condition and economic performance and access to capital, which in turn will depend upon the supply and demand for oil and natural gas, prevailing economic conditions and financial, business and other factors. The failure of a third-party servicer to adequately perform operations could delay drilling or completion or reduce production from the Underlying Properties and the cash available for distribution to Trust unitholders. If the Trust Development Wells take longer to be drilled and perforated for completion than currently anticipated, this may delay revenue earned from the production of oil and natural gas by such wells. The revenues distributable to the Trust and the amount of cash distributable to the Trust unitholders would similarly be delayed.

Because SandRidge does not have a majority working interest in the non-operated properties comprising the Underlying Properties, SandRidge may not be able to remove the operator in the event of poor or untimely performance. If the Trust Development Wells take longer to be drilled than currently anticipated, this may delay revenue attributable to the production of oil and natural gas by such wells. The revenues distributable to the Trust and the amount of cash distributable to the Trust unitholders would similarly be delayed.

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Production of oil, NGLs and natural gas on the Underlying Properties could be materially and adversely affected by severe or unseasonable weather.

Production of oil, NGLs and natural gas on the Underlying Properties could be materially and adversely affected by severe weather. Repercussions of severe weather conditions may include:

· evacuation of personnel and curtailment of operations;

· weather-related damage to drilling rigs or other facilities, resulting in suspension of operations;

· inability to deliver materials to worksites; and

· weather-related damage to pipelines and other transportation facilities.

In addition, hydraulic fracturing operations require significant quantities of water. Any diminished access to water for use in hydraulic fracturing, whether due to usage restrictions or drought or other weather conditions, could curtail operations on the Underlying Properties or otherwise result in delays in operations or increased costs.

Shortages or increases in costs of equipment, services and qualified personnel could delay the drilling of the Trust Development Wells and result in a reduction in the amount of cash available for distribution.

The demand for qualified and experienced personnel to conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling rigs and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher oil and natural gas prices generally stimulate demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. Shortages of field personnel and equipment or price increases could significantly hinder SandRidge’s ability to satisfy its drilling obligation and delay completion of the Trust Development Wells, which would reduce future distributions to Trust unitholders.

Due to the Trust’s lack of industry and geographic diversification, adverse developments in the Trust’s existing area of operation could adversely impact its financial condition, results of operations and cash flows and reduce its ability to make distributions to the unitholders.

The Underlying Properties are being and will be operated for oil, NGL and natural gas production only and are focused exclusively in the Permian Basin in Andrews County, Texas. This concentration could disproportionately expose the Trust’s interests to operational and regulatory risk in that area. Due to the lack of diversification in industry type and location of the Trust’s interests, adverse developments in the oil and natural gas market or the area of the Underlying Properties, including, for example, transportation or treatment capacity constraints, curtailment of production or treatment plant closures for scheduled maintenance, could have a significantly greater impact on the Trust’s financial condition, results of operations and cash flows than if the Royalty Interests were more diversified.

The generation of proceeds for distribution by the Trust depends in part on access to and the operation of gathering, transportation and processing facilities. Limitations in the availability of those facilities could interfere with sales of oil, NGL and natural gas production from the Underlying Properties.

The amount of oil, NGLs and natural gas that may be produced and sold from any well to which the Underlying Properties relate is subject to curtailment in certain circumstances, such as by reason of weather conditions, pipeline interruptions due to scheduled and unscheduled maintenance, failure of tendered oil, NGLs and natural gas to meet quality specifications of gathering lines or downstream transporters, excessive line pressure which prevents delivery, physical damage to the gathering system or transportation system or lack of contracted capacity on such systems. The curtailments may vary from a few days to several months. In many cases, SandRidge is provided limited notice, if any, as to when production will be curtailed and the duration of such curtailments. If SandRidge is forced to reduce production due to such a curtailment, the revenues of the Trust and the amount of cash distributions to the Trust unitholders would similarly be reduced due to the reduction of proceeds from the sale of production.

Some of the Trust Development Wells on the Underlying Properties may be drilled in locations that currently are not serviced by natural gas gathering and transportation pipelines or locations in which existing gathering and transportation pipelines do not have sufficient capacity to transport additional production. As a result, the natural gas production from certain Trust Development Wells might not be able to be sold until the necessary gathering systems and/or transportation pipelines are constructed or until the necessary transportation capacity on an interstate pipeline is obtained. Any delay in the expansion of such system or the construction or expansion of any other natural gas gathering systems beyond the currently estimated construction schedules, or a delay in the procurement of additional transportation capacity would delay the receipt of any proceeds that may be associated with the natural gas production from the Trust Development Wells.

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Title deficiencies with respect to the Underlying Properties could adversely affect SandRidge’s rights to production from the Underlying Properties.

The existence of title deficiencies with respect to the Underlying Properties could reduce the value or render properties worthless, thus adversely affecting the distributions to unitholders. SandRidge does not obtain title insurance covering oil, gas and mineral leaseholds. Additionally, undeveloped leasehold acreage has greater risk of title defects than developed acreage.

Drilling title opinions on all of the Underlying Properties have not yet been obtained. Prior to drilling of a Trust Development Well, SandRidge expects to obtain a drilling title opinion to identify defects in title to the leasehold. Frequently, as a result of title examinations, certain curative work may be required to correct identified title defects, and such curative work entails time and expense. The inability or failure to cure title defects could render some locations undrillable or cause the Trust to lose its rights to some or all production from some of the Underlying Properties, which could result in a reduction in proceeds available for distribution to unitholders and the value of the Trust units if a comparable additional location to drill a Trust Development Well cannot be identified.

The Trust is passive in nature and has no voting rights in SandRidge, managerial, contractual or other ability to influence SandRidge, or control over the field operations of, sale of oil and natural gas from, or development of, the Underlying Properties.

Trust unitholders have no voting rights with respect to SandRidge and, therefore, have no managerial, contractual or other ability to influence SandRidge’s activities or operations of the Underlying Properties. In addition, some of the Trust Development Wells may, at some point, be operated by third parties unrelated to SandRidge. Such third-party operators may not have the operational expertise of SandRidge. Oil and natural gas properties are typically managed pursuant to an operating agreement among the working interest owners in the properties. The typical operating agreement contains procedures whereby the owners of the aggregate working interest in the property designate one of the interest owners to be the operator of the property. Under these arrangements, the operator is typically responsible for making all decisions relating to drilling activities, sale of production, compliance with regulatory requirements and other matters that affect the property. The failure of an operator to adequately perform operations could reduce production from the Underlying Properties and cash available for distribution to unitholders. Neither the Trustee nor the Trust unitholders has any contractual or other ability to influence or control the field operations of, sale of oil and natural gas from, or future development of, the Underlying Properties.

The oil, NGL and natural gas reserves estimated to be attributable to the Royalty Interests are depleting assets and production from those reserves will diminish over time. Furthermore, the Trust is precluded from acquiring other oil and natural gas properties or royalty interests to replace the depleting assets and production.

The proceeds payable to the Trust from the Royalty Interests are derived from the sale of the production of oil, NGLs and natural gas from the Underlying Properties. The oil, NGL and natural gas reserves attributable to the Royalty Interests are depleting assets, which means that the reserves of oil and natural gas attributable to the Royalty Interests will decline over time as will the quantity of oil, NGLs and natural gas produced from the Underlying Properties.

Future maintenance may affect the quantity of proved reserves that can be economically produced from the Underlying Properties to which the wells relate. The timing and size of these projects will depend on, among other factors, the market prices of oil, NGLs and natural gas. With the exception of SandRidge’s commitment to drill the Trust Development Wells, SandRidge has no contractual obligation to make capital expenditures on the Underlying Properties in the future. Furthermore, for properties on which SandRidge is not designated as the operator, SandRidge has no control over the timing or amount of those capital expenditures. SandRidge also has the right to non-consent and not participate in the capital expenditures on properties for which it is not the operator, in which case SandRidge and the Trust will not receive the production resulting from such capital expenditures. If SandRidge or other operators of the wells to which the Underlying Properties relate do not implement maintenance projects when warranted, the future rate of production decline of proved reserves may be higher than the rate currently expected by SandRidge or estimated in the Trust’s reserve report.

The trust agreement provides that the Trust’s business activities are generally limited to owning the Royalty Interests and entering into the hedging arrangements and activities reasonably related thereto, including activities required or permitted by the terms of the conveyances related to the Royalty Interests. As a result, the Trust is not permitted to acquire other oil and gas properties or royalty interests to replace the depleting assets and production attributable to the Trust.

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An increase in the differential between the price realized by SandRidge for oil and natural gas produced from the Underlying Properties and the NYMEX or other benchmark price of oil or natural gas could reduce the proceeds to the Trust and therefore the cash distributions by the Trust and the value of Trust units.

The prices received for oil and natural gas production usually fall below benchmark prices such as NYMEX. The difference between the price received and the benchmark price is called a differential. The amount of the differential depends on a variety of factors, including discounts based on the quality and location of hydrocarbons produced, Btu content and post-production costs. These factors can cause differentials to be volatile from period to period. Sellers of production have little or no control over the factors that determine the amount of the differential, and cannot accurately predict differentials for natural gas or crude oil. Increases in the differential between the realized price of oil or natural gas and the benchmark price for oil or natural gas could reduce the proceeds to the Trust and therefore the cash distributions made by the Trust and the value of the Trust units. The target distributions were prepared (a) for natural gas using an assumed negative differential of 28% from NYMEX futures prices for natural gas, and (b) for oil using an assumed negative differential of $4.27 per barrel from NYMEX futures prices for oil.

The amount of cash available for distribution by the Trust is reduced by post-production costs and applicable taxes associated with the Royalty Interests, Trust expenses and incentive distributions payable to SandRidge.

The Royalty Interests and the Trust bear certain costs and expenses that reduce the amount of cash received by or available for distribution by the Trust to the holders of the Trust units. These costs and expenses include the following:

·                  the Trust’s share of the costs incurred by SandRidge to gather, store, compress, transport, process, treat, dehydrate and market the oil, NGLs and natural gas (excluding costs of marketing services provided by SandRidge);

·                  the Trust’s share of applicable taxes, including property taxes and taxes on the production of oil, NGLs and natural gas;

·                  the Trust’s liability for Texas franchise tax;

·                  Trust administrative expenses, including fees paid to the Trustee and the Delaware Trustee, the annual administrative services fee payable to SandRidge, tax return and Schedule K-1 preparation and mailing costs, independent auditor fees and registrar and transfer agent fees, and costs associated with annual and quarterly reports to unitholders; and

·                  any amounts owed to counterparties under hedging arrangements.

In addition, the amount of funds available for distribution to unitholders is reduced by the amount of any cash reserves maintained by the Trustee in respect of anticipated future Trust administrative expenses.

Further, during the subordination period, SandRidge is entitled to receive a quarterly incentive distribution from the Trust equal to 50% of the amount by which cash available to be paid to all unitholders exceeds the Incentive Threshold for the applicable quarter.

The amount of post-production costs, taxes and expenses borne by the Trust and incentive distributions payable to SandRidge may vary materially from quarter-to-quarter. The extent by which the costs and expenses of the Trust are higher or lower in any quarter will directly decrease or increase the amount received by the Trust and available for distribution to the unitholders. Historical post-production costs and taxes, however, may not be indicative of future post-production costs and taxes.

The hedging arrangements for the Trust cover only a portion of the oil and natural gas production attributable to the Trust, and such contracts limit the Trust’s ability to benefit from commodity price increases for hedged volumes above the corresponding hedge price.

The Trust has entered into oil hedge contracts with unaffiliated counterparties. Additionally, pursuant to the derivatives agreement, SandRidge has provided the Trust with the effect of certain oil hedge contracts that it entered into with third parties. Under the combined hedging arrangements, approximately 68% of the expected production and approximately 73% of the expected revenues upon which the target distributions were based from January 1, 2014 through March 31, 2015 have been hedged. The remaining estimated production of oil and natural gas during that time and all production after such time will not be hedged to protect against the price risks inherent in holding interests in oil, a commodity that is frequently characterized by significant price volatility. Furthermore, while the use of hedging arrangements limits the downside risk of price declines, they may also limit the Trust’s ability to benefit from increases in oil prices above the hedge price on the portion of the production attributable to the Royalty Interests that is hedged.

The Trust’s receipt of any payments due to it based on the Trust’s hedge contracts with unaffiliated hedge counterparties and the derivatives agreement with SandRidge depends upon the financial position of the Trust’s unaffiliated hedging counterparties, SandRidge and SandRidge’s hedging counterparties. The Trust’s sole current counterparty under its hedge contracts with unaffiliated third parties is Morgan Stanley Capital Group Inc. The Trust’s counterparty under the derivatives agreement is SandRidge, whose sole current counterparty is also Morgan Stanley Capital Group Inc. In the event that the counterparty to the oil hedge contracts defaults on its obligations to make payments under such contracts, the cash distributions to the Trust unitholders would likely be materially reduced as the hedge payments are intended to provide additional cash to the Trust during periods of lower oil prices. SandRidge will not be required to make payments to the Trust under the derivatives agreement to the extent of payment defaults by SandRidge’s hedge contract counterparty. Except in limited circumstances involving the restructuring of an existing hedge, the Trust has no ability

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to terminate its hedge contracts or enter into additional hedges of its own. See ‘‘—SandRidge’s ability to satisfy its obligations to the Trust depends on its financial position, and in the event of a default by SandRidge in its obligation to drill the Trust Development Wells, or in the event of SandRidge’s bankruptcy, it may be expensive and time-consuming for the Trust to exercise its remedies.’’

The Trust is administered by a Trustee who cannot be replaced except at a special meeting of Trust unitholders.

The business and affairs of the Trust are administered by the Trustee. A unitholder’s voting rights are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of Trust unitholders or for an annual or other periodic re-election of the Trustee. The trust agreement provides that the Trustee may only be removed and replaced by the holders of a majority of the outstanding Trust units, excluding Trust units held by SandRidge, voting in person or by proxy at a special meeting of Trust unitholders at which a quorum is present called by either the Trustee or the holders of not less than 10% of the outstanding Trust units. As a result, it may be difficult for public unitholders to remove or replace the Trustee without the cooperation of holders of a substantial percentage of the outstanding Trust units.

Trust unitholders have limited ability to enforce provisions of the Royalty Interests, and SandRidge’s liability to the Trust is limited.

The trust agreement permits the Trustee and the Trust to sue SandRidge or any other future owner of the Underlying Properties to enforce the terms of the conveyances creating the Royalty Interests. If the Trustee does not take appropriate action to enforce provisions of these conveyances, a Trust unitholder’s recourse would be limited to bringing a lawsuit against the Trustee to compel the Trustee to take specified actions. The trust agreement expressly limits a Trust unitholder’s ability to directly sue SandRidge or any other party other than the Trustee. As a result, Trust unitholders will not be able to sue SandRidge or any future owner of the Underlying Properties to enforce the Trust’s rights under the conveyances. Furthermore, the Royalty Interest conveyances provide that, except as set forth in the conveyances, SandRidge will not be liable to the Trust for the manner in which it performs its duties in operating the Underlying Properties as long as it acts in good faith and, to the fullest extent permitted by law, will owe no fiduciary duties to the Trust or the unitholders.

Courts outside of Delaware may not recognize the limited liability of the Trust unitholders provided under Delaware law.

Under the Delaware Statutory Trust Act, Trust unitholders are entitled to the same limitation of personal liability extended to stockholders of private corporations for profit under the General Corporation Law of the State of Delaware. However, courts in jurisdictions outside of Delaware may not give effect to such limitation.

The sale of trust units by SandRidge could have an adverse impact on the trading price of the common units.

As of February 21, 2014, SandRidge, through SandRidge E&P, owned 13,125,000 subordinated units and no common units. All of the subordinated units will automatically convert into common units at the end of the subordination period. SandRidge may sell Trust units in the public or private markets, and any such sales could have an adverse impact on the price of the common units. On March 14, 2012 and September 9, 2013 and January 9, 2014, SandRidge E&P sold 2,000,000, 1,050,000 and 1,825,000 respectively of its common units in transactions pursuant to Rule 144 under the Securities Act. On October 24, 2012, pursuant to the registration rights agreement, the Trust and SandRidge filed a registration statement on Form S-3 registering the offering by SandRidge Exploration and Production, LLC of 2,875,000 common units. The registration statement was effective immediately upon filing. Although SandRidge does not hold any common units at present, subordinated units it currently owns will convert to common units the fourth full quarter after its drilling obligation to the Trust has been fulfilled.

SandRidge could have interests that conflict with the interests of the Trust and Trust unitholders.

As a working interest owner in the Underlying Properties, SandRidge could have interests that conflict with the interests of the Trust and the Trust unitholders. For example:

·                  Notwithstanding its drilling obligation to the Trust, SandRidge’s interests may conflict with those of the Trust and the Trust unitholders in situations involving the development, maintenance, operation or abandonment of the Underlying Properties. Additionally, SandRidge may, consistent with its obligation to act as a reasonably prudent operator, abandon a well that is uneconomic or not generating revenues from production in excess of its operating costs, even though such well is still generating revenue for the Trust unitholders. Subsequent to fulfilling its drilling obligation, SandRidge may make decisions with respect to expenditures and decisions to allocate resources on projects in other areas that adversely affect the Underlying Properties, including reducing expenditures on these properties, which could cause oil, NGL and natural gas production to decline at a faster rate and thereby result in lower cash distributions by the Trust in the future.

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·                  Following the satisfaction of its drilling obligation to the Trust, SandRidge may, without the consent or approval of the Trust unitholders, sell all or any part of its retained interest in the Underlying Properties, if the Underlying Properties are sold subject to and burdened by the Royalty Interests. Such sale may not be in the best interests of the Trust and Trust unitholders. For example, any purchaser may lack SandRidge’s experience in the Permian Basin or its creditworthiness.

·                  Following the satisfaction of its drilling obligation to the Trust, SandRidge may, without the consent or approval of the Trust unitholders, require the Trust to release Royalty Interests with an aggregate value of up to $5.0 million during any 12-month period in connection with a sale by SandRidge of a portion of its retained interest in the Underlying Properties. The fair value received by the Trust for such Royalty Interests may not fully compensate the Trust for the value of future production attributable to the Royalty Interests disposed of.

·                  SandRidge is permitted under the conveyance agreements creating the Royalty Interests to enter into new processing and transportation contracts without obtaining bids from or otherwise negotiating with any independent third parties, and SandRidge will deduct from the Trust’s proceeds any charges under such contracts attributable to production from the Trust properties.

·                  SandRidge can sell its Trust units regardless of the effects such sale may have on common unit prices or on the Trust itself. Additionally, SandRidge can vote its Trust units in its sole discretion.

In addition, SandRidge has agreed that, 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 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 arms’ length transaction between SandRidge and an unaffiliated third party. If SandRidge provides such funds to the Trust, it would become a creditor of the Trust and its interests as a creditor could conflict with the interests of unitholders. Finally, as hedge manager to the trust, SandRidge has the ability to negotiate the terms of any novation, assignment or transfer of any hedge contract to which SandRidge is a party.

SandRidge may sell all or a portion of the Underlying Properties, subject to and burdened by the Royalty Interests, after satisfying its drilling obligation to the Trust; any such purchaser could have a weaker financial position and/or be less experienced in oil and natural gas development and production than SandRidge.

Unitholders will not be entitled to vote on any sale of the Underlying Properties if the Underlying Properties are sold subject to and burdened by the Royalty Interests and the Trust will not receive any proceeds from any such sale. The purchaser would be responsible for all of SandRidge’s obligations relating to the Royalty Interests on the portion of the Underlying Properties sold, and SandRidge would have no continuing obligation to the Trust for those properties. Additionally, SandRidge may enter into farmout or joint venture arrangements with respect to the wells burdened by the Trust’s Royalty Interest. Any purchaser, farmout counterparty or joint venture partner could have a weaker financial position and/or be less experienced in oil and natural gas development and production than SandRidge. Finally, as hedge manager to the trust, SandRidge has the ability to negotiate the terms of any novation, assignment or transfer of any hedge contract to which SandRidge is a party.

SandRidge’s ability to satisfy its obligations to the Trust depends on its financial position, and in the event of a default by SandRidge in its obligation to drill the Trust Development Wells, or in the event of SandRidge’s bankruptcy, it would be expensive and time-consuming for the Trust to exercise its remedies.

Pursuant to the terms of the development agreement between SandRidge and the Trust, SandRidge is obligated to drill, or cause to be drilled, the Trust Development Wells at its own expense. SandRidge owns a majority working interest in substantially all of the locations on which it expects to drill the remaining Trust Development Wells, and it expects to operate such wells until completion of its drilling obligation. As of December 31, 2013, SandRidge is also the operator of all of the Initial Wells together with the wells drilled as Trust Development Wells through December 31, 2013. The conveyances provide that SandRidge is obligated to market, or cause to be marketed, the oil and natural gas production related to the Underlying Properties. Additionally, SandRidge is the counterparty to the Trust’s derivatives agreement and has certain obligations to the Trust under the agreement. In the event that SandRidge defaults on its obligation to make payments under the derivatives agreement, the cash distributions to the Trust unitholders may be materially reduced as these payments are intended to provide additional cash to the Trust during periods of lower oil and natural gas prices. Due to the Trust’s reliance on SandRidge to fulfill these numerous obligations, the value of the Royalty Interests and its ultimate cash available for distribution is highly dependent on SandRidge’s performance.

SandRidge has other drilling obligations, including a drilling obligation to another royalty trust, which will require it to make capital expenditures over the next several years at the same time it plans to drill the remaining Trust Development Wells. SandRidge’s ability to satisfy its drilling obligation to the Trust will depend on, among other things, the availability of sufficient funds and drilling rigs. More generally, SandRidge’s ability to satisfy its drilling obligation to the Trust and to perform these obligations depends on its future financial condition and economic performance and access to capital, which in turn depends upon the supply and demand for oil

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and natural gas, prevailing economic conditions and financial, business and other factors, many of which are beyond SandRidge’s control.

In the event that SandRidge defaults on its obligation to drill the remaining Trust Development Wells, the Trust would be entitled to foreclose on the lien granted to the trust by SandRidge E&P in order to secure the estimated amount of the drilling costs for the Trust’s interests in the undeveloped Underlying Properties (the “Drilling Support Lien”) to the extent of SandRidge’s remaining interests in the undeveloped portions of the AMI. However, the maximum amount the Trust can recover in such a foreclosure or other action was, as of December 31, 2013, approximately $68.0 million, which amount will be reduced proportionately as each remaining Trust Development Well is drilled and perforated for completion. The value of SandRidge’s interests in the undeveloped portions of the AMI secured by the Drilling Support Lien may not be equal to the amount potentially recoverable at any given time, and such interests may be worth considerably less. The process of foreclosing on such collateral would be expensive and time-consuming and would delay the drilling and completion of the remaining Trust Development Wells; such delays and expenses would reduce Trust distributions by reducing the amount of proceeds available for distribution. Any amounts actually recovered in a foreclosure action would be applied to completion of SandRidge’s drilling obligation, would not result in any distribution to the Trust unitholders and may be insufficient to drill the number of wells needed for the Trust to realize the full value of the Development Well Royalty Interest. Furthermore, the Trust would have to seek a new party to perform the drilling and operations of the wells. The Trust may not be able to find a replacement driller or operator, and it may not be able to enter into a new agreement with such replacement party on favorable terms within a reasonable period of time.

SandRidge is not required to maintain a segregated account for proceeds payable to the Trust. The proceeds of the Royalty Interests may be commingled, for a period of time, with proceeds of SandRidge’s retained interest in the Underlying Properties for the period of time between SandRidge’s sale of hydrocarbons attributable to the Royalty Interests and the quarterly payment to the Trust of its share of proceeds. It is possible that the Trust may not have adequate facts to trace its entitlement to funds in the commingled pool of funds and that other persons may, in asserting claims against SandRidge’s retained interest, be able to assert claims to the proceeds that should be delivered to the Trust. If there is an event of default under SandRidge’s credit facility, SandRidge must keep its accounts with banks that enter into control agreements with the administrative agent under the credit facility, which would permit the administrative agent to direct payment of funds in such accounts during the pendency of an event of default. In addition, during any bankruptcy of SandRidge, it is possible that payments of the royalties may be delayed or deferred. During the pendency of any SandRidge bankruptcy proceedings, the Trust’s ability to foreclose on the Drilling Support Lien, and the ability to collect cash payments being held in SandRidge’s accounts that are attributable to production from the Trust properties, may be stayed by the bankruptcy court. Delay in realizing on the collateral for the Drilling Support Lien is possible, and it cannot be guaranteed that a bankruptcy court would permit such foreclosure. It is possible that the bankruptcy would also delay the execution of a new agreement with another driller or operator. If the Trust enters into a new agreement with a drilling or operating partner, the new partner might not achieve the same levels of production or sell oil and natural gas at the same prices as SandRidge was able to achieve.

Oil and natural gas wells are subject to operational hazards that can cause substantial losses. SandRidge maintains insurance; however, SandRidge may not be adequately insured for all such hazards.

There are a variety of operating risks inherent in oil, NGL and natural gas production and associated activities, such as fires, leaks, explosions, mechanical problems, major equipment failures, blowouts, uncontrollable flow of oil, NGLs, natural gas, water or drilling fluids, casing collapses, abnormally pressurized formations and natural disasters. The occurrence of any of these or similar accidents that temporarily or permanently halt the production and sale of oil, NGLs and natural gas at any of the Underlying Properties will reduce Trust distributions by reducing the amount of proceeds available for distribution.

Additionally, if any of such risks or similar accidents occur, SandRidge could incur substantial losses as a result of injury or loss of life, severe damage or destruction of property, natural resources and equipment, regulatory investigation and penalties and environmental damage and clean-up responsibility. If SandRidge experiences any of these problems, its ability to conduct operations and perform its obligations to the Trust could be adversely affected. While SandRidge maintains insurance coverage it deems appropriate for these risks with respect to the Underlying Properties, SandRidge’s operations may result in liabilities exceeding such insurance coverage or liabilities not covered by insurance. If a well is damaged, SandRidge would have no obligation to drill a replacement well or make the Trust whole for the loss.

The operation of the Underlying Properties is subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner and feasibility of conducting operations on the properties, which in turn could negatively impact trust distributions, estimated and actual future net revenues to the trust and estimates of reserves attributable to the Trust’s interests.

Oil and natural gas exploration, production, transportation and treatment operations are subject to complex and stringent laws and regulations. In order to conduct operations in compliance with these laws and regulations, numerous permits, approvals and

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certificates are required from various federal, state and local governmental authorities. Compliance with these existing laws and regulations may require the incurrence of substantial costs by SandRidge or other operators of the Underlying Properties. Additionally, there has been a variety of regulatory initiatives at the federal and state levels to further regulate oil and natural gas operations in certain locations. Any increased regulation or suspension of oil and natural gas operations, or revision or reinterpretation of existing laws and regulation, could result in delays and higher operating costs. Such costs or significant delays could have a material adverse effect on the operation of the Underlying Properties, which in turn could negatively impact Trust distributions, estimated and actual future net revenues to the Trust and estimates of reserves attributable to the Trust’s interests.

Laws and regulations governing oil and natural gas exploration and production may also affect production levels. SandRidge is required to comply with federal and state laws and regulations governing conservation matters, including provisions related to the unitization or pooling of the oil and natural gas properties; the establishment of maximum rates of production from wells; the spacing of wells; and the plugging and abandonment of wells. These and other laws and regulations can limit the amount of oil and natural gas SandRidge can produce from its wells, limit the number of wells it can drill, or limit the locations at which it can conduct drilling operations, which in turn could negatively impact Trust distributions, estimated and actual future net revenues to the Trust and estimates of reserves attributable to the Trust’s interests.

New laws or regulations, or changes to existing laws or regulations may unfavorably impact SandRidge, could result in increased operating costs and could have a material adverse effect on SandRidge’s financial condition and results of operations. For example, Congress has recently considered, and may continue to consider, legislation that, if adopted in its proposed form, would subject companies involved in oil and natural gas exploration and production activities to, among other items, additional regulation of and restrictions on hydraulic fracturing of wells, and the elimination of most U.S. federal tax incentives and deductions available to oil and natural gas exploration and production activities. In addition, the Dodd-Frank Wall Street Reform and Consumer Protection Act and rules promulgated thereunder could reduce trading positions in the energy futures markets and materially reduce hedging opportunities for SandRidge, which could adversely affect its revenues and cash flows during periods of low commodity prices, and which could adversely affect the ability to restructure the hedges when it might be desirable to do so.

Additionally, federal and state regulatory authorities may expand or alter applicable pipeline safety laws and regulations, compliance with which may require increased capital costs on the part of SandRidge and third-party downstream oil and natural gas transporters. These and other potential regulations could increase SandRidge’s operating costs, reduce SandRidge’s liquidity, delay SandRidge’s operations, increase direct and third-party post production costs associated with the Trust’s interests or otherwise alter the way SandRidge conducts its business, which could have a material adverse effect on SandRidge’s financial condition, results of operations and cash flows and which could reduce cash received by or available for distribution, including any amounts paid by SandRidge for transportation on downstream interstate pipelines.

The operation of the Underlying Properties is subject to environmental laws and regulations that could adversely affect the cost, manner or feasibility of conducting operations or result in significant costs and liabilities.

The oil and natural gas exploration and production operations on the Underlying Properties are subject to stringent and comprehensive federal, state, and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that are applicable to operations of the Underlying Properties, including the acquisition of permits before conducting drilling; water withdrawal or waste disposal activities; the restriction of types, quantities and concentrations of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the imposition of regulations designed to protect employees from exposure to hazardous substances; and the imposition of substantial liabilities for pollution resulting from operations. Numerous governmental authorities, such as the EPA and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions. Failure to comply with these laws and regulations may result in litigation; the assessment of administrative, civil and criminal penalties; the imposition of investigatory or remedial obligations; and the issuance of injunctions limiting or preventing some or all operations relating to the Underlying Properties.

There is inherent risk of incurring significant environmental costs and liabilities in the performance of operations at the Underlying Properties due to the handling of petroleum hydrocarbons and wastes, because of air emissions and wastewater discharges related to its operations, and as a result of historical industry operations and waste disposal practices. Under certain environmental laws and regulations, an operator could be subject to joint and several strict liability for the investigation, removal or remediation of previously released materials or property contamination regardless of whether the operator was responsible for the release or contamination or whether the operations were in compliance with all applicable laws at the time the release or contamination occurred. Private parties, including the owners of properties upon which wells are drilled and facilities where petroleum hydrocarbons or wastes are taken for reclamation or disposal may also have the right to pursue legal actions to enforce compliance, as well as to seek damages

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for contamination even in the absence of non-compliance, with environmental laws and regulations or for personal injury or property damage.

In addition, the risk of accidental spills or releases could expose an operator to significant liabilities that could have a material adverse effect on its financial condition or results of operations. Certain laws related to oil spills impose joint and several strict liability, without regard to fault, for all containment and oil removal costs and a variety of public and private damages including, but not limited to, the costs of responding to a release of oil, natural resource damages, and economic damages suffered by persons adversely affected by an oil spill. Although defenses exist to the liability imposed by those laws, they are limited. If an oil discharge or substantial threat of discharge were to occur, an operator may be liable for costs and damages, which costs and damages could be material to its results of operations and financial position.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly construction, drilling, water management, completion, waste handling, storage, transport, disposal or cleanup requirements could require significant expenditures by SandRidge to attain and maintain compliance and may otherwise have a material adverse effect on the results of operations, competitive position or financial condition of SandRidge. SandRidge may not be able to recover some or any these costs from insurance. As a result of the increased cost of compliance, SandRidge may decide to discontinue drilling. Additionally, permitting delays may inhibit SandRidge’s ability to drill the remaining Trust Development Wells on schedule.

Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that SandRidge produces while the physical effects of climate change could disrupt SandRidge’s production and cause SandRidge to incur significant costs in preparing for or responding to those effects.

In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present a danger to public health and the environment because such gases are contributing to warming of the Earth’s atmosphere and other climatic changes. These findings allow the agency to adopt and implement regulations that restrict emissions of GHGs under existing provisions of the Clean Air Act. Accordingly, the EPA has adopted rules that require a reduction in emissions of GHGs from motor vehicles and also trigger Clean Air Act construction and operating permit review for GHG emissions from certain stationary sources. The EPA’s endangerment finding and GHG rules were upheld by the United States Court of Appeals for the D.C. Circuit in a June 2012 decision, and a petition for review of the case by the entire D.C. Circuit was denied in December 2012.

The EPA also has adopted rules requiring the reporting of GHG emissions from onshore oil and natural gas production and processing facilities in the United States on an annual basis. SandRidge believes it has complied with all applicable reporting requirements to date. However, the adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, SandRidge’s equipment and operations could require SandRidge to incur additional costs to reduce emissions of GHGs associated with its operations or could adversely affect demand for the oil and natural gas that it produces. Finally, to the extent increasing concentrations of GHG in the Earth’s atmosphere may produce climate change that could have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events such events could have a material adverse effect on the Underlying Properties, and potentially subject SandRidge to greater regulation.

In addition, Congress has considered legislation to reduce emissions of GHGs and more than half of the states have begun taking actions to control and/or reduce emissions of GHGs, primarily through the adoption of a climate change action plan, completion of GHG emission inventories and/or regional GHG cap and trade programs. Any future federal laws or implemented regulations that may be adopted to address GHG emissions could require SandRidge to incur increased operating costs, adversely affect demand for the oil and natural gas that the SandRidge produces and have a material adverse effect on SandRidge’s business, financial condition and results of operations.

Federal and state legislative and regulatory initiatives as well as governmental reviews relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect the level of production from the Underlying Properties.

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations, such as shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing is typically regulated by state oil and gas commissions; however, the EPA has asserted federal regulatory authority over certain hydraulic fracturing practices, including the use of diesel, kerosene and similar compounds in fracturing fluid. In August 2012, the EPA issued final Clean Air Act regulations governing performance standards, including standards for the capture of air emissions released during hydraulic fracturing. However, in January 2013 the EPA submitted an unopposed motion to the United States Court of Appeals for the D.C. Circuit seeking to stay legal challenges to the Clean Air Act regulations while the EPA reconsiders portions of the new rules. Also, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing

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process. In May 2012, the Bureau of Land Management within the U.S. Department of the Interior issued a proposed rule containing disclosure requirements and other mandates for hydraulic fracturing on federal lands, but in January 2013 it announced that it would be submitting a revised proposed rule. That revised proposed rule was published for public comment in May 2013.  The Department of Interior is now analyzing the comments and is expected to promulgate a final rule sometime in 2014 or 2015.

Certain states in which SandRidge operates, including Texas, and municipalities have adopted, or are considering adopting, regulations that have imposed, or that could impose, more stringent permitting, disclosure, disposal and well construction requirements on exploration and production activities. For example, in February 2012, the Railroad Commission of Texas implemented the Fracturing Disclosure Rule, requiring public disclosure of all the chemicals in fluids used in the hydraulic fracturing process. Local ordinances or other regulations may regulate or prohibit the performance of well drilling in general and hydraulic fracturing in particular. If new laws or regulations that significantly restrict or regulate hydraulic fracturing are adopted at either the state or the federal level, the Company’s fracturing activities could become subject to additional permit requirements, reporting requirements or operational restrictions and also to associated permitting delays, or additional costs could adversely affect the determination of whether a well is commercially viable. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that ultimately can be produced in commercial quantities from the Underlying Properties.

In addition to asserting regulatory authority, a number of federal entities are analyzing, or have been requested to review, a variety of environmental issues associated with unconventional natural gas production, including hydraulic fracturing. In April 2012, President Obama issued an executive order that established a working group for the purpose of coordinating policy, information sharing, and planning among federal agencies and offices regarding “unconventional natural gas production,” including hydraulic fracturing. In December 2012, the EPA issued an initial progress report on a study begun in 2011 of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a draft final report expected to be issued for peer review and comment in late 2014. The EPA has also announced its intent to propose by 2014 effluent limit guidelines that waste water from shale gas extraction operations must meet before going to a treatment plant; the agency also projects that it will publish an Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Additionally, a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices, and certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources; the SEC to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing; and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. Bills previously have been introduced in both the Senate and the House of Representatives to, among other things, amend the federal Safe Drinking Water Act to repeal provisions that exempt hydraulic fracturing operations from restrictions that otherwise would apply to underground injection of fluids or propping agents. The studies and initiatives described above, depending on their degree of pursuit and any meaningful results obtained, could spur efforts to further regulate hydraulic fracturing under the Safe Drinking Water Act or other regulatory mechanisms.

The Trust is subject to the requirements of the Sarbanes-Oxley Act of 2002, which may impose cost and operating challenges on it.

The Trust is subject to certain of the requirements of the Sarbanes-Oxley Act of 2002 which requires, among other things, maintenance by the Trust of, and reports regarding the effectiveness of, a system of internal control over financial reporting. Complying with these requirements may pose operational challenges and may cause the Trust to incur unanticipated expenses. Any failure by the Trust to comply with these requirements could lead to a loss of public confidence in the Trust’s internal controls and in the accuracy of the Trust’s publicly reported results.

Tax Risks Related to the Units

The Trust’s tax treatment depends on its status as a partnership for U.S. federal income tax purposes. If the U.S. Internal Revenue Service (“IRS”) were to treat the Trust as a corporation for U.S. federal income tax purposes, then its cash available for distribution to unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in the Trust units depends largely on the Trust being treated as a partnership for U.S. federal income tax purposes. The Trust has not requested, and does not plan to request, a ruling from the IRS, on this or any other tax matter affecting it.

It is possible in certain circumstances for a publicly traded trust otherwise treated as a partnership, such as the Trust, to be treated as a corporation for U.S. federal income tax purposes. In addition, a change in current law could cause the Trust to be treated as a corporation for U.S. federal income tax purposes or otherwise subject it to federal taxation as an entity.

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If the Trust were treated as a corporation for U.S. federal income tax purposes, it would pay federal income tax on its taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely be required to also pay state income tax on its taxable income at the corporate tax rate of such state. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to unitholders without first being subjected to taxation at the entity level. Because additional tax would be imposed upon the Trust as a corporation, its cash available for distribution to unitholders would be substantially reduced. Therefore, treatment of the Trust as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the Trust unitholders, likely causing a substantial reduction in the value of the Trust units.

The trust agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects the Trust to additional amounts of entity-level taxation for state or local income tax purposes, the Subordination Threshold amounts, Incentive Threshold amounts and target distribution amounts may be adjusted to reflect the impact of that law on the Trust.

If the Trust were subjected to a material amount of additional entity-level taxation by individual states, it would reduce the Trust’s cash available for distribution to unitholders.

The Trust is 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. This rate of tax is subject to change by new legislation at any time.

Changes in current state law may subject the Trust to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation.

Additional imposition of such taxes may substantially reduce the cash available for distribution to unitholders and, therefore, negatively impact the value of an investment in Trust units. The trust agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects the Trust to additional amounts of entity-level taxation for state or local income tax purposes, the Subordination Threshold amounts, Incentive Threshold amounts and target distribution amounts may be adjusted to reflect the impact of that law on the Trust.

The tax treatment of an investment in Trust units could be affected by recent and potential legislative changes, possibly on a retroactive basis.

The Health Care and Education Reconciliation Act of 2010 includes a provision that, in taxable years beginning after December 31, 2012, subjects an individual having adjusted gross income in excess of $200,000 (or $250,000 for married taxpayers filing joint returns) to an additional “Medicare tax” equal to 3.8% of the lesser of such excess or the individual’s net investment income. For this purpose, net investment income generally includes interest income and royalty income derived from investments such as the Trust units as well as any net gain from the disposition of Trust units. Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income and long-term capital gains of individuals is 39.6% and 20%, respectively. Moreover, these rates are subject to change by new legislation at any time.

Current law may change so as to cause the Trust to be treated as a corporation for U.S. federal income tax purposes or otherwise subject the Trust to entity-level taxation. Specifically, the present U.S. federal income tax treatment of publicly traded partnerships, including the Trust, or an investment in the Trust units may be modified by administrative, legislative or judicial interpretation at any time. For example, at the federal level, legislation has been proposed in the past that would have eliminated partnership tax treatment for certain publicly traded partnerships. Although such legislation would not have applied to the Trust as it was proposed, it could be reintroduced in a manner that does apply to the Trust.

The trust agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects the Trust to taxation as a corporation or otherwise subjects it to entity-level taxation for U.S. federal income tax purposes, Subordination Threshold amounts, the Incentive Threshold amounts and the target distribution amounts may be adjusted to reflect the impact of that law on the Trust.

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The Trust has adopted and may continue to adopt positions that may not conform to all aspects of existing Treasury Regulations. If the IRS contests the tax positions the Trust takes, the value of the Trust units may be adversely affected, the cost of any IRS contest will reduce the Trust’s cash available for distribution and income, gains, losses and deductions may be reallocated among Trust unitholders.

If the IRS contests any of the U.S. federal income tax positions the Trust takes or has taken, the value of the Trust units may be adversely affected because the cost of any IRS contest will reduce the Trust’s cash available for distribution and income, gain, loss and deduction may be reallocated among Trust unitholders. For example, the Trust generally prorates its items of income, gain, loss and deduction between transferors and transferees of the Trust units each quarter based upon the record ownership of the Trust units on the quarterly record date in such quarter, instead of on the basis of the date a particular Trust unit is transferred. Although simplifying conventions are contemplated by the Internal Revenue Code, and most publicly traded partnerships use similar simplifying conventions, the use of these methods may not be permitted under existing Treasury Regulations.

The Trust has not requested a ruling from the IRS with respect to its treatment as a partnership for U.S. federal income tax purposes or any other matter affecting the Trust. The IRS may adopt positions that differ from the conclusions of SandRidge’s counsel or from the positions the Trust takes. It may be necessary to resort to administrative or court proceedings to attempt to sustain some or all of the conclusions of SandRidge’s counsel or the positions the Trust takes. A court may not agree with some or all of the conclusions of SandRidge’s counsel or positions the Trust takes. Any contest with the IRS may materially and adversely impact the market for the Trust units and the price at which they trade. In addition, the Trust’s costs of any contest with the IRS will be borne indirectly by the Trust unitholders because the costs will reduce the Trust’s cash available for distribution.

Each unitholder is required to pay taxes on the unitholder’s share of the Trust’s income even if a unitholder does not receive cash distributions from the Trust equal to the unitholder’s share of the Trust’s taxable income.

Because the Trust unitholders are treated as partners to whom the Trust allocates taxable income that could be different in amount than the cash the Trust distributes, each unitholder may be required to pay any federal income taxes and, in some cases, state and local income taxes on the unitholder’s share of the Trust’s taxable income even if a unitholder may not receive cash distributions from the Trust equal to the unitholder’s share of the Trust’s taxable income or even equal to the actual tax liability that results from that income.

Tax gain or loss on the disposition of the Trust units could be more or less than expected.

If a unitholder sells its Trust units, the unitholder will recognize a gain or loss equal to the difference between the amount realized and the unitholder’s tax basis in those Trust units. Because distributions in excess of a unitholder’s allocable share of the Trust’s net taxable income decrease the unitholder’s tax basis in its Trust units, the amount, if any, of such prior excess distributions with respect to the Trust units unitholders sell will, in effect, become taxable income to unitholders if unitholders sell such Trust units at a price greater than the unitholder’s tax basis in those Trust units, even if the price the unitholder receives is less than the unitholder’s original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depletion recapture.

The ownership and disposition of Trust units by tax-exempt organizations and non-U.S. persons may result in adverse tax consequences to them.

Tax-Exempt Organizations.  Employee benefit plans and most other organizations exempt from U.S. federal income tax including individual retirement accounts (known as IRAs) and other retirement plans are subject to U.S. federal income tax on unrelated business taxable income. Because all of the income of the Trust is expected to be royalty income, interest income, hedging income and gain from the sale of real property, none of which is expected to be unrelated business taxable income, any such organization exempt from U.S. federal income tax is not expected to be taxable on income generated by ownership of Trust units so long as neither the property held by the Trust nor the Trust units are debt-financed property within the meaning of Section 514(b) of the Internal Revenue Code. However, investors should consult their own tax advisors.

Non-U.S. Persons.  Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons may be required to file U.S. federal income tax returns and pay tax on their share of the Trust’s taxable income or proceeds from the sale of trust units.

The Trust treats each purchaser of Trust units as having the same economic attributes without regard to the actual Trust units purchased. The IRS may challenge this treatment, which could adversely affect the value of the Trust units.

Due to a number of factors, including the Trust’s inability to match transferors and transferees of Trust units, the Trust may adopt positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely alter the tax effects of an investment in Trust units. It also could affect the timing of tax benefits or the amount of gain from a unitholder’s sale of Trust units and could have a negative impact on the value of the Trust units or result in audit adjustments to a unitholder’s tax returns.

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The Trust prorates its items of income, gain, loss and deduction between transferors and transferees of the Trust units each quarter based upon the record ownership of the Trust units on the quarterly record date, in such quarter, instead of on the basis of the date a particular Trust unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among the Trust unitholders.

The Trust generally prorates its items of income, gain, loss and deduction between transferors and transferees of the Trust units based upon the record ownership of the Trust units on the quarterly record date in such quarter instead of on the basis of the date a particular Trust unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations, and, accordingly, SandRidge’s counsel is unable to opine as to the validity of this method. If the IRS were to challenge the Trust’s proration method, the Trust may be required to change its allocation of items of income, gain, loss and deduction among the Trust unitholders and the costs to the Trust of implementing and reporting under any such changed method may be significant.

A Trust unitholder whose Trust units are loaned to a “short seller” to cover a short sale of Trust units may be considered as having disposed of those Trust units. If so, he would no longer be treated for tax purposes as a partner with respect to those Trust units during the period of the loan and may recognize gain or loss from the disposition.

Because a Trust unitholder whose Trust units are loaned to a “short seller” to cover a short sale of Trust units may be considered as having disposed of the loaned Trust units, he may no longer be treated for tax purposes as a partner with respect to those Trust units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of the Trust’s income, gains, losses or deductions with respect to those Trust units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those Trust units could be fully taxable as ordinary income. Trust unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from loaning their Trust units.

The Trust may adopt certain valuation methodologies that may affect the income, gain, loss and deduction allocable to the Trust unitholders. The IRS may challenge this treatment, which could adversely affect the value of the Trust units.

The U.S. federal income tax consequences of the ownership and disposition of Trust units will depend in part on the Trust’s estimates of the relative fair market values, and the initial tax bases of the Trust’s assets. Although the Trust may from time to time consult with professional appraisers regarding valuation matters, the Trust will make many of the relative fair market value estimates itself. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by Trust unitholders might change, and Trust unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

The sale or exchange of 50% or more of the Trust’s capital and profits interests during any 12-month period will result in the termination of the Trust’s partnership status for U.S. federal income tax purposes.

The Trust will be considered to have technically terminated for U.S. federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in its capital and profits within a 12-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same Trust unit within any 12-month period will be counted only once. The Trust’s termination would, among other things, result in the closing of its taxable year for all Trust unitholders, which would result in the Trust filing two tax returns (and the Trust unitholders would receive two Schedules K-1) for one calendar year. However, the IRS announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership will be required to provide only a single Schedule K-1 to unitholders for the short taxable years that result from the technical termination. In the case of a unitholder reporting on a taxable year other than a calendar year ending December 31, the closing of the Trust’s taxable year as a result of any technical termination may also result in more than twelve months of the Trust’s taxable income being includable in his or her taxable income for the year of termination. A technical termination would not affect the Trust’s classification as a partnership for U.S. federal income tax purposes, but instead, the Trust would be treated as a new partnership for tax purposes. If treated as a new partnership, the Trust must make new tax elections and could be subject to penalties if the Trust is unable to determine that a technical termination occurred.

Certain U.S. federal income tax preferences currently available with respect to oil and natural gas production may be eliminated as a result of future legislation.

The Obama administration’s budget proposals in recent years, including the budget proposal for fiscal year 2014, have included provisions eliminating certain key U.S. federal income tax preferences currently available to oil and gas exploration and production activities. Specifically, the 2014 budget proposes to repeal the percentage depletion allowance for oil and gas properties, including the

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Royalty Interests that are perpetual, in which case only cost depletion would be available. If this proposal were enacted into law, it could negatively impact the value of the Trust units.

Item 1B.                        Unresolved Staff Comments

None.

Item 2.                                  Properties

Information regarding the Trust’s properties is included in Item 1 of this report. Also, refer to Note 9 to the financial statements included in Item 8 of this report.

Item 3.                                  Legal Proceedings

None.

Item 4.                                  Mine Safety Disclosures

Not applicable.

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PART II

Item 5.                                  Market for Common Units of the Trust, Related Unitholder Matters and Issuer Purchases of Common Units.

The Trust units are listed on the New York Stock Exchange (“NYSE”) under the symbol “PER.” The range of high and low sales prices for the Trust’s common units for the periods indicated, as reported by the NYSE, and distributions per unit made by the Trust during the corresponding periods are as follows: