Edgar Filing: SandRidge Permian Trust

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Non-accelerated filer

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Smaller reporting company

Form 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

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

For the fiscal year ended December 31, 2011

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

For the transition period from to

Commission File Number: 001-35274

SANDRIDGE PERMIAN TRUST

(Exact name of registrant as specified in its charter)


Delaware		45-6276683
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

The Bank of New York Mellon Trust Company, N.A., Trustee 919 Congress Avenue, Suite 500 Austin, Texas		78701
(Address of principal executive offices)		(Zip Code)

(855) 802-1092

(Registrant’s telephone number, including area code)

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


Title of Each Class		Name of Each Exchange on Which Registered
Common Units of Beneficial Interest		New York Stock Exchange

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 ¨ 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 ¨ 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 ¨

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 ¨ No ¨

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 ¨ No x

The aggregate market value of Common Units of Beneficial Interest in SandRidge Permian Trust held by non-affiliates on June 30, 2011, the last business day of the registrant’s most recently completed second fiscal quarter is not applicable as the registrant’s equity was not traded as of June 30, 2011. As of March 19, 2012, 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

SANDRIDGE PERMIAN TRUST

2011 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS


Item		Page

PART I

1.	Business		1

1A.	Risk Factors		18

1B.	Unresolved Staff Comments		33

2.	Properties		33

3.	Legal Proceedings		33

4.	Mine Safety Disclosures		33

PART II

5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities		34

6.	Selected Financial Data		34

7.	Trustee’s Discussion and Analysis of Financial Condition and Results of Operations		34

7A.	Quantitative and Qualitative Disclosures about Market Risk		38

8.	Financial Statements and Supplementary Data		38

9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		39

9A.	Controls and Procedures		39

9B.	Other Information		39

PART III

10.	Directors, Executive Officers and Corporate Governance		40

11.	Executive Compensation		40

12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		40

13.	Certain Relationships and Related Transactions and Director Independence		41

14.	Principal Accounting Fees and Services		41

PART IV

15.	Exhibits and Financial Statement Schedules		42

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 14.

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 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. Our 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 our 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.

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 managed 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 the Royalty Interests in specified oil and natural gas properties in the Permian Basin located in Andrews County, Texas (the “Underlying Properties”). These 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”), consisting of approximately 17,500 gross acres (15,900 net acres) in the counties where the Underlying Properties are located.

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, including natural gas liquids, 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 including natural gas liquids, 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.

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 managed 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 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.

Initial Public Offering. Through an initial public offering (“IPO”) 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 IPO, 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, 2011, there were 52,500,000 Trust units, consisting of 39,375,000 common and 13,125,000 subordinated units, issued and outstanding. The common and subordinated units have identical rights and privileges, except with respect to their rights to receive distributions. See “— Distributions” below.

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 will be required to pay Texas franchise tax each year at a maximum effective rate of 0.7% of its gross income apportioned to Texas in the prior year.

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, 2015. In the event of delays, SandRidge will have until March 31, 2016 to fulfill its drilling obligation. 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 will be 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 will receive 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 $229.7 million as of December 31, 2011.

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 (discussed 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,

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, 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 oil fixed price swaps.

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.

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, ad valorem 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 and natural gas prices received;

•

volume of oil 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 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. After such time, the common units 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 and as included in the final prospectus filed with the SEC by the Trust pursuant to Rule 424(b) under the Securities Act on August 12, 2011.


Period (1)	Subordination Threshold(2)		Incentive Threshold(2)

2011
Fourth quarter(3)		0.39		0.59

2012
First quarter		0.42		0.63
Second quarter		0.44		0.66
Third quarter		0.47		0.70
Fourth quarter		0.49		0.74

2013
First quarter		0.51		0.77
Second quarter		0.53		0.80
Third quarter		0.56		0.84
Fourth quarter		0.58		0.87

2014
First quarter		0.61		0.91
Second quarter		0.63		0.95
Third quarter		0.65		0.98
Fourth quarter		0.66		0.98

2015
First quarter		0.64		0.96
Second quarter		0.61		0.92
Third quarter		0.56		0.85
Fourth quarter		0.54		0.81

2016
First quarter		0.53		0.80
Second quarter		0.52		0.78
Third quarter		0.51		0.77
Fourth quarter		0.50		0.75

2017
First quarter		0.49		0.74

(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.

(3)	A distribution of $0.553523 per unit was declared on February 2, 2012 and paid on February 29, 2012. See Note 8 to the financial statements contained in Item 8 of this report for the details of the distribution.

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 to pay such expenses. 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.

Properties

As of December 31, 2011, the Trust’s properties consisted of Royalty Interests in (a) the Initial Wells, (b) 188 wells (equivalent to approximately 195 Trust Development Wells under the development agreement) that were drilled and perforated for completion between April 1, 2011 and December 31, 2011 (the “Additional Drilled Wells” and, together with the Initial Wells, the “Drilled Wells”) and (c) the equivalent of approximately 693 Trust Development Wells to be drilled (the “Remaining Development Wells”). The following table presents the number of Initial Wells, Trust Development Wells drilled and Remaining Development Wells as of August 16, 2011, the date of the Royalty Interests conveyance, and December 31, 2011.


	Initial Wells		Trust Development Wells Drilled(1)		Remaining Development Wells		Total
August 16, 2011		517		92		796		1,405
December 31, 2011		517		195		693		1,405

(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%. In certain circumstances, SandRidge may also receive Trust Development Well credit for horizontal wells drilled to such formation.

The Royalty Interests were derived from 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. In 2010, production from the Permian Basin accounted for approximately 17% of total U.S. crude oil production, making this basin the second largest oil producing area in the continental U.S. after the Gulf of Mexico. The Permian Basin has been producing oil for over 80 years resulting in cumulative production of approximately 29 billion barrels.

Proved Reserves

The following estimates of net proved oil and natural gas reserves are based on reserve reports as of December 31, 2011 prepared by independent petroleum engineers. The PV-10 and Standardized Measure shown in the table below are not intended to represent the current market value of estimated oil and natural gas reserves attributable to the Royalty Interests at December 31, 2011. The reserve report as of December 31, 2011 was based on SandRidge’s drilling schedule and the average price during the 12-month period ended December 31, 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 and natural gas reserves in this report were estimated by Netherland, Sewell & Associates, Inc. (“Netherland Sewell”). 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 Netherland Sewell. Members of SandRidge’s Reservoir Engineering Department consulted regularly with Netherland Sewell during the reserve estimation process to review properties, assumptions, and any new data available. SandRidge’s internal reserve estimates and methodologies were compared to Netherland Sewell’s estimates and conclusions before the reserve estimates were included in Netherland Sewell’s report. Additionally, SandRidge’s senior management reviewed and approved the reserve report contained herein.

Internal Controls. SandRidge’s Executive Vice President — 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 Mechanical Engineering with over 30 years of practical industry experience, including over 25 years of estimating and evaluating reserve information. In addition, SandRidge’s Executive Vice President — Reservoir Engineering has been a certified professional engineer in the state of Oklahoma since 1988 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 department currently has a total of 19 full-time employees, comprised of eight degreed engineers and 11 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.

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 President, independently from all other operating divisions.

•

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

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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.

Netherland Sewell. Netherland Sewell estimated all of the proved reserve information in this report, in accordance with the definitions and guidelines of the SEC and, with the exception of the exclusion of future income taxes to which the Trust is not subject, in conformity with the Accounting Standards Codification Topic 932, Extractive Activities — Oil and Gas. Netherland Sewell are independent petroleum engineers, geologists, geophysicists, and petrophysicists; Netherland Sewell does not own an interest in these properties and are not employed on a contingent basis.

The qualifications of the technical person at Netherland Sewell primarily responsible for overseeing the firm’s preparation of the Trust’s reserve estimates include:

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more than 30 years of practical experience in petroleum engineering and almost 15 years estimating and evaluating reserve information;

•

a registered professional engineer in the states of Texas, Louisiana and Wyoming; and

•

a Bachelor of Science Degree in Civil Engineering and a Masters Degree in Business Administration.

These qualifications meet or exceed the Society of Petroleum Engineers standard requirements to be a professionally qualified Reserve Estimator and Auditor.

A summary of the Trust’s proved oil and natural gas reserves, all of which are located in the continental United States, is presented below as of December 31, 2011:


Estimated Proved Reserves(1)
Developed
Oil (MBbls)(2)		8,309.9
Natural gas (MMcf)		2,243.9

Total proved developed (MBoe)		8,683.9
Undeveloped
Oil (MBbls)(2)		12,440.5
Natural gas (MMcf)		4,926.6

Total proved undeveloped (MBoe)		13,261.6
Total Proved
Oil (MBbls)(2)		20,750.4
Natural gas (MMcf)		7,170.5

Total proved (MBoe)		21,945.5

PV-10 (in millions)(3)	$	946.4
Standardized Measure of Discounted Net Cash Flows (in millions)(4)	$	942.9

(1)

Determined using a 12-month average of the first day of the month prices for oil and natural gas for the year ended December 31, 2011 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.


	Weighted average wellhead prices				Index prices
	Oil (per Bbl)		Natural gas (per Mcf)		Oil (per Bbl)		Natural gas (per Mcf)
December 31, 2011	$	88.03	$	2.94	$	92.71	$	4.12

(2)	Includes natural gas liquids.

(3)

PV-10 is the present value of estimated future net revenue to be generated from the production of proved reserves, discounted using an annual discount rate of 10%, 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:


	December 31, 2011
	(in millions)
Standardized Measure of Discounted Net Cash Flows (4)	$	942.9
Present value of future income tax discounted at 10%		3.5

PV-10	$	946.4

(4)

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 oil and natural gas reserves are those quantities of oil 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.

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. Proved undeveloped reserves associated with the Royalty Interests at the date of conveyance, August 16, 2011, totaled 16.1 MMBoe. During the period from the date of the Royalty Interests conveyance, to December 31, 2011, SandRidge drilled 103 Trust Development Wells, resulting in the conversion of approximately 3.1 MMBoe of proved undeveloped reserves to proved developed reserves. The Trust did not bear any costs associated with drilling these wells. At December 31, 2011, 91 of these wells were classified as proved developed producing properties with the remaining wells still in progress. Under the terms of the development agreement, SandRidge is obligated to drill, or cause to be drilled, the Remaining Development Wells by March 31, 2015. In the event of delays, SandRidge will have until March 31, 2016 to fulfill its drilling obligation.

Production and Price History

The following tables set forth information regarding the net oil and natural gas production attributable to the Royalty Interests and certain price and cost information for the year ended December 31, 2011. The oil and natural gas volumes attributable to the Royalty Interests and related revenues and expenses for the year ended December 31, 2011 (included in SandRidge’s November 2011 net revenue distributions to the Trust) represent oil and natural gas production from April 1, 2011 to August 31, 2011.


Production Data
Oil (MBbls)(1)		453
Natural gas (MMcf)		120
Combined equivalent volumes (MBoe)		473
Average daily combined equivalent volumes (MBoe/d)		3

Average Prices(2)
Oil (per Bbl)(1)	$	89.13
Natural gas (per Mcf)	$	3.44
Combined equivalent (per Boe)	$	86.24

Expenses (per Boe)
Post-production	$	0.05
Production taxes	$	4.14

Total expenses	$	4.19

(1)	Includes natural gas liquids.

(2)	Reported prices represent realized average prices based on revenues received in cash and do not give effect to derivative contract settlements or post-production expenses.

Productive Wells

The following table sets forth as of December 31, 2011 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.

Oil

Natural Gas

Total

Gross

Net

Gross

Net

Gross

Net

Productive Wells

693

389.2

—

693

389.2

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, 2011:

Developed Acreage

Undeveloped Acreage

Gross

Net

Gross

Net

Acreage within the AMI subject to the Royalty Interests

12,132

11,693

5,182

4,209

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, 2011 the expiration periods of the gross and net acres that are subject to leases in the undeveloped acreage summarized in the above table.


	Acres Expiring
Twelve Months Ending	Gross		Net
December 31, 2012		401		155
December 31, 2013		400		257
December 31, 2014		160		20
December 31, 2015 and later		—		—
Other(1)		4,221		3,777

Total		5,182		4,209

(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 the period from August 16, 2011, the date of the Royalty Interests conveyance, to December 31, 2011. 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, 2011, there were 19 gross (9.5 net) wells subject to the Royalty Interests drilling or awaiting completion.


	2011
	Gross		Percent			Net		Percent
Completed Wells
Development
Productive		90		100	%		45.7		100	%
Dry		—		0	%		—		0	%

Total		90		100	%		45.7		100	%
Exploratory
Productive		—		0	%		—		0	%
Dry		—		0	%		—		0	%

Total		—		0	%		—		0	%
Total
Productive		90		100	%		45.7		100	%
Dry		—		0	%		—		0	%

		90		100	%		45.7		100	%

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 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 and natural gas production attributable to SandRidge’s remaining interest in the Underlying Properties.

SandRidge sells oil 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 2011, one customer individually accounted for more than 10% of total revenue attributable to the Royalty Interests. 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 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 customer.


	2011
	Sales		% of Revenue
	(in thousands)
Enterprise Crude Oil LLC	$	35,558.6		87.2	%

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 Development Wells. Prior to the drilling of a Remaining 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 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.

Oil 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 and natural gas.

Future price fluctuations for oil and natural gas will directly impact Trust distributions, estimates of reserves attributable to the Trust’s 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 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 maximum 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 availability, terms and cost of transportation significantly affect sales of oil and natural gas. 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. Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. The Federal Energy Regulatory Commission’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 and natural gas are not currently regulated and are made at market prices. Although oil 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 and natural gas prices might be proposed, what proposals, if any, might actually be enacted by Congress or state legislatures, and what effect, if any, the proposals might have on the operations of the Underlying Properties cannot be predicted.

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 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.

The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, 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, air quality compliance or remediation requirements 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.

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 U.S. 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 they incur. Materials used and generated in the course of operations with respect to the Underlying Properties may be regulated as hazardous substances. 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 many of the other wastes associated with the exploration, production and 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 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 gas exploration and production wastes from operations.

Air Emissions. The Clean Air Act, as amended, 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 to satisfy its obligations to the Trust. In July 2011, the EPA proposed a range of new regulations that would establish new air emission controls for oil and natural gas production and natural gas processing, including, among other things, a new source performance standard for volatile organic compounds that would apply to newly hydraulically fractured wells, existing wells that are re-fractured, compressors, pneumatic controllers, condensate and crude oil storage tanks, and natural gas processing plants. The EPA is under a court order to finalize these proposed regulations by April 3, 2012.

Water Discharges. The Federal Water Pollution Control 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 the Clean Water Act and analogous state laws, permits must be obtained to discharge produced waters and sand, drilling fluids, drill cuttings and other substances related to the oil and 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. 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 in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws 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. The EPA’s rules relating to emissions of GHGs from stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent the EPA from implementing, or requiring state environmental agencies to implement, the rules. In addition, the EPA has adopted rules requiring the reporting of GHG emissions from onshore oil and natural gas production 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, some scientists have concluded that 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; if any such effects were to occur, they 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 almost one-half of the states have begun taking actions to control and/or reduce emissions of GHGs, primarily through the planned development 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 next six years, through 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.

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 hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in SandRidge’s operations and that this information be provided to employees, state and local government authorities and citizens. The Trustee believes that SandRidge is in substantial compliance with all applicable laws and regulations relating to worker health and safety.

State Regulation. Texas regulates 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. The effect of these regulations may limit the number of Trust Development Wells that may be drilled, impact the locations at which Trust Development Wells may be drilled and restrict 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. 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 process. The U.S. Department of the Interior is considering disclosure requirements and other mandates for hydraulic fracturing on federal lands. In addition, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. Certain states 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 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 the state level, such legal requirements could cause project delays and make it more difficult or costly to perform fracturing to stimulate production from the Underlying Properties. These delays or additional costs could adversely affect the determination of whether a well is commercially viable. In addition, if hydraulic fracturing is regulated at the 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. Restrictions on hydraulic fracturing could also reduce the amount of oil or natural gas that is ultimately produced in commercial quantities from the Underlying Properties. In addition, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. Moreover, the EPA announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. In addition, the U.S. Department of Energy has conducted an investigation of practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods and the U.S. Government Accountability Office has investigated how hydraulic fracturing might adversely affect water resources. Additionally, certain members of Congress have called upon 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. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms. All of the acreage and 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.

Bcf. Billion cubic feet of natural gas.

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 2011 of $92.71/ Bbl for oil and $4.12/ Mcf for natural gas, the ratio of economic value of oil to gas was approximately 22 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. Developed oil and natural gas reserves are 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.

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.

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 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 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 and natural gas reserves. Those quantities of oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for 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 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.

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 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.

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 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 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 Remaining Development Wells (including the drilling schedule of third-party operators that may drill the Remaining 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 Remaining 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:

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

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unusual or unexpected geological formations and miscalculations;

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shortages of or delays in obtaining equipment and qualified personnel;

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

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equipment malfunctions, failures or accidents;

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

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lack of available capacity on interconnecting transmission pipelines;

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lack of adequate electrical infrastructure;

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unexpected operational events and drilling conditions;

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pipe or cement failures and casing collapses;

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pressures, fires, blowouts and explosions;

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lost or damaged drilling and service tools;

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loss of drilling fluid circulation;

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

•

natural disasters;

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environmental hazards, such as oil 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;

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oil and natural gas property title problems; and

•

market limitations for oil and natural gas.

In the event that drilling of the Remaining 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.

Oil 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 and natural gas. The markets for these commodities are very volatile. Oil 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:

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

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the price of foreign imports;

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U.S. and worldwide political and economic conditions;

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

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weather conditions and seasonal trends;

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

•

technological advances affecting energy consumption and energy supply;

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

•

natural disasters and other acts of force majeure;

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domestic and foreign governmental regulations and taxation;

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energy conservation and environmental measures; and

•

the price and availability of alternative fuels.

For oil, from January 1, 2008 through December 31, 2011, the highest monthly settled price on the New York Mercantile Exchange (“NYMEX”) was $140.00 per Bbl and the lowest was $41.68 per Bbl. For natural gas, from January 1, 2008 through December 31, 2011, the highest monthly NYMEX settled price was $13.11 per MMBtu (one million British Thermal Units) and the lowest was $2.84 per MMBtu. In addition, the market price of oil and natural gas is generally higher in the winter months than during other months of the year due to increased demand for oil and natural gas for heating purposes during the winter season.

Lower oil and natural gas prices will reduce proceeds to which the Trust is entitled and may ultimately reduce the amount of oil 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 and 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 and 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 and natural gas in commercially economic quantities. This could result in termination of the portion of the Royalty Interests relating to the abandoned well or property, and SandRidge would have no obligation to drill a replacement well. In addition, lower oil 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 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 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.”

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 and natural gas in an exact way and estimating reserves is inherently uncertain. As discussed below, the process of estimating oil 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 reserves shown in the Prospectus. This could result in actual production and revenues for the Underlying Properties being materially less than estimated amounts.

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 and natural gas based on factors and assumptions that include:

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

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

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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.

Estimates of the target distributions to unitholders, Subordination Thresholds and Incentive Thresholds are based on assumptions that are inherently subjective and are subject to significant business, economic, financial, legal, regulatory and competitive risks and uncertainties that could cause actual cash distributions to differ materially from those estimated.

The estimates of target distributions to unitholders, 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 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 those estimated. For example, these estimates have assumed that oil and natural gas production is sold at prices consistent with settled NYMEX prices for April through June 2011, and 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 assume that the Remaining Development Wells will be drilled on SandRidge’s current anticipated schedule; however, the drilling of the Remaining Development Wells may be delayed, the Remaining Development Wells may be drilled at locations with higher post-production expenses and applicable taxes and actual production volumes may be significantly lower than the levels assumed in preparing the estimates. 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 the anticipated drilling schedule for the Remaining 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 estimated and determined could cause actual distributions to fall below the target distribution amounts and/or Subordination Thresholds in later periods. A cash distribution to Trust unitholders below the target distribution amount or the Subordination Threshold 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 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. Depending on the prices at which volumes attributable to the Trust are sold, the common units may receive a distribution that is below the Subordination Threshold.

Quarterly cash distributions will be 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.

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

Production of oil 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 Remaining 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 Remaining 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 will be operated for oil 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 and natural gas production from the Underlying Properties.

The amount of oil 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 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. In particular, the system SandRidge intends to use to compress and process the natural gas produced from certain of the Underlying Properties could be near its capacity and may not be able to process all of the natural gas produced from the Underlying Properties. 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.

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, the Trustee believes a drilling title opinion to identify defects in title to the leasehold will be obtained. 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 Remaining 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 be operated by third parties unrelated to SandRidge. Such third-party operators may not have the operational expertise of SandRidge within the AMI. 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 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 and natural gas reserves estimated to be attributable to the Underlying Properties of the Trust 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 and natural gas from the Underlying Properties. The oil and natural gas reserves attributable to the Underlying Properties are depleting assets, which means that the reserves of oil and natural gas attributable to the Underlying Properties will decline over time as will the quantity of oil 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 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.

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 will depend 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 oil or natural gas. 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 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:

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

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

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the Trust’s liability for Texas franchise tax;

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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

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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 73% of the expected production and approximately 78% of the expected revenues upon which the target distributions were based from January 1, 2012 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 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 Remaining 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 managed by a Trustee who cannot be replaced except at a special meeting of Trust unitholders.

The business and affairs of the Trust are managed 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.

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

SandRidge owns an aggregate of 2,875,000 common units and 13,125,000 subordinated 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 or on any trading market that may develop. On March 14, 2012, SandRidge sold approximately 2.0 million of its Trust common units in a transaction pursuant to Rule 144 under the Securities Act. The Trust has granted registration rights to SandRidge, which, if exercised, would facilitate sales of Trust units by SandRidge to the public.

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:

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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 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.

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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, 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.

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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.

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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.

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.

Pursuant to the terms of the development agreement, 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 Development Wells, and it expects to operate such wells until completion of its drilling obligation. As of December 31, 2011, SandRidge is also the operator of all of the Drilled Wells. 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, which will require it to make capital expenditures over the next several years at the same time it plans to drill the Remaining 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 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 Development Wells, the Trust would be able to foreclose on 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, 2011, approximately $229.7 million, which amount will be reduced proportionately as each Remaining 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 recoverable at any given time, and such interests may be worth considerably less. The process of foreclosing on such collateral may be expensive and time-consuming and delay the drilling and completion of the Remaining 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 will not be 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 and natural gas production and associated activities, such as fires, leaks, explosions, mechanical problems, major equipment failures, blowouts, uncontrollable flow of oil, 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 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 or feasibility of conducting operations on the properties.

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 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. Further, in light of the explosion and fire on the drilling rig Deepwater Horizon in the Gulf of Mexico, as well as recent incidents involving the release of oil and natural gas and fluids as a result of drilling activities in the United States, there has been a variety of regulatory initiatives at the federal and state levels to restrict oil and natural gas drilling operations in certain locations. Any increased regulation or suspension of oil and natural gas exploration and production, or revision or reinterpretation of existing laws and regulations, that arises out of these incidents or otherwise 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 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 there under 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, state and federal 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, regional 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 concentration 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; impose 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 or 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 on 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 if the operations were in compliance with all applicable laws at the time those actions were taken. 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 for contamination even in the absence of non-compliance, with environmental laws and regulations or for personal injury, natural resource damage 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. 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 of 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 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. 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 rules relating to emissions of GHGs from stationary sources of emissions are currently subject to a number of political and legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent EPA from implementing, or requiring state environmental agencies to implement, the rules. In addition, the EPA has adopted rules requiring the reporting of GHG emissions from onshore oil and natural gas production facilities in the United States on an annual basis. Both houses of Congress have from time to time considered legislation to reduce emissions of GHGs and almost one-half of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of GHGs. 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, some scientists have concluded that 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; if any such effects were to occur, they could have an adverse effect on the Underlying Properties.

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. Hydraulic fracturing is used extensively to stimulate production from the Underlying Properties. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process 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 on the Underlying Properties. 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 process. Certain states 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 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 or regulate hydraulic fracturing are adopted, such legal requirements could cause project delays and make it more difficult or costly to perform fracturing to stimulate production from the Permian Basin. 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 and natural gas that is ultimately able to produce in commercial quantities from the Underlying Properties.

In addition, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. Moreover, the EPA announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. In addition, the U.S. Department of Energy is conducting an investigation of practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. Also, the U.S. Department of the Interior is considering disclosure requirements or other mandates for hydraulic fracturing on federal lands. Additionally, 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. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal 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.

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 pay additional 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 will be required to pay Texas franchise tax each year at a maximum effective rate of 0.7% of its gross income apportioned to Texas in the prior year. 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 generally to 3.8% of the lesser of such excess or the individual’s net investment income, which appears to include 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. In addition, absent new legislation extending the current rates, beginning January 1, 2013, the highest marginal U.S. federal income tax rate applicable to ordinary income and long-term capital gains of individuals will increase to 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.

The Trust may 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, 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 the Trust’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 the Trust’s counsel expressed in the Prospectus or the positions the Trust takes. A court may not agree with some or all of the conclusions of the Trust’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 non-U.S. persons may result in adverse tax consequences to them.

Investment in Trust units by non-U.S. persons raises issues unique to them. For example, 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. If a unitholder is a non-U.S. person, the unitholder should consult a tax advisor before investing in the 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.

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, the Trust’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. The Trust’s counsel has not rendered an opinion regarding the treatment of a unitholder where Trust units are loaned to a short seller to cover a short sale of Trust units; therefore, 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 could receive two Schedules K-1) for one calendar year. The IRS has recently 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 tax year

in which the termination occurs. 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.

In recent years, the Obama administration’s budget proposals and other proposed legislation have included elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production. If enacted into law, these provisions would eliminate certain tax preferences applicable to taxpayers engaged in the exploration or production of natural resources. These changes include, but are not limited to (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for U.S. production activities and (iv) the increase in the amortization period from two years to seven years for geophysical costs paid or incurred in connection with the exploration for or development of, oil and gas within the United States. It is unclear whether any such changes will be enacted and, if so, when any such changes would become effective.

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.

PART II

Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.

The Trust units commenced trading on the New York Stock Exchange (“NYSE”) on August 11, 2011, under the symbol “PER.” Prior to August 11, 2011, there was no established public trading market for the Trust units. 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:


	High		Low		Distributions Per Unit
Calendar Quarter 2011
Fourth Quarter	$	22.85	$	14.88	$	0.722746
Third Quarter	$	19.36	$	16.43		N/A
Second Quarter		N/A		N/A		N/A
First Quarter		N/A		N/A		N/A

On March 19, 2012, there were two record unitholders of the Trust’s common units.

Distributions

The Trust makes quarterly cash distributions of substantially all of its cash receipts, after deducting amounts for the Trust’s administrative expenses, cash reserves withheld by the Trustee, ad valorem tax and Texas franchise tax, on or about 60 days following the completion of each quarter, through (and including) the quarter ending March 31, 2031.

Equity Compensation Plans

The Trust does not have any employees and, therefore, does not maintain any equity compensation plans.

Recent Sales of Unregistered Securities

None.

Purchases of Securities

There were no purchases of Trust units by the Trust or any affiliated purchaser during the fourth quarter of 2011.

Item

6. Selected Financial Data

The information presented below should be read in conjunction with “Trustee’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this report and the financial statements and notes thereto contained in “Financial Statements and Supplementary Data” in Item 8 of this report. The following information is not necessarily indicative of future results. The following tables set forth financial information regarding the Trust (in thousands, except per unit data).


	Year Ended December 31, 2011
Total revenues	$	42,630
Distributable income	$	38,619

Distributable income per unit	$	0.735607
Trust units outstanding		52,500
	As of December 31, 2011
Total assets	$	528,525
Trust corpus	$	528,525

Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations

Introduction

The following discussion and analysis is intended to help the reader understand the Trust’s business, financial condition, results of operations, liquidity and capital resources. This discussion and analysis should be read in conjunction with other sections of this report, including: “Business” in Item 1, “Selected Financial Data” in Item 6 and “Financial Statements and Supplementary Data” in Item 8. The discussion and analysis relate to the following subjects:

•

Results of Trust Operations

•

Liquidity and Capital Resources

•

Critical Accounting Policies and Estimates

•

Off-balance Sheet Arrangements

Results of Trust Operations

Results of the Trust for the Year Ended December 31, 2011

The primary factors affecting the Trust’s revenues and costs are the quantity of oil and natural gas production attributable to the Royalty Interests, the prices received for such production and amounts paid or received as net settlements under the derivatives agreement and the Trust’s derivative contracts with unaffiliated third parties. Royalty income, post-production expense, certain taxes and derivative settlements are recorded on a cash basis when net revenue distributions are received by the Trust from SandRidge and net derivative settlements are received from the Trust’s derivative counterparties. Information regarding the Trust’s production, pricing and costs for the year ended December 31, 2011, consisting of the November 2011 net revenue distribution and net derivative settlements, is presented below.


	Year Ended December 31, 2011(1)
Production data
Oil (MBbl)(2)		453
Natural gas (MMcf)		120
Combined equivalent volumes (MBoe)		473

Average prices
Oil (per Bbl)(2)	$	89.13
Natural gas (per Mcf)	$	3.44
Combined equivalent (per Boe)	$	86.24

Average prices — including impact of derivative settlements and post-production expenses
Oil (per Bbl)(2)(3)	$	91.70
Natural gas (per Mcf)	$	3.25
Combined equivalent (per Boe)	$	88.65

Production taxes (per Boe)	$	4.14

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

(2)	Includes natural gas liquids.

(3)	Includes impact of derivative settlements attributable to production from April 1, 2011 to August 31, 2011.

Royalty Income. Royalty income received during the year ended December 31, 2011 totaled $40.8 million based upon production attributable to the Royalty Interests of 453 MBbls of oil and 120 MMcf of natural gas for the period from April 1, 2011 to August 31, 2011. Average prices received for oil and natural gas production, excluding the impact of derivative settlements and post-production expenses, during the year ended December 31, 2011 were $89.13 per Bbl of oil and $3.44 per Mcf of natural gas.

Derivative Settlements. The Trust’s derivatives contracts reduce the Trust’s exposure to commodity price volatility attributable to a portion of production from the Royalty Interests through March 31, 2015 through the use of oil fixed price swaps. Net cash settlements received related to the Trust’s derivative contracts for the year ended December 31, 2011 were approximately $1.8 million, including $1.1 million received from SandRidge and the counterparty related to production from the Royalty Interests from April 1, 2011 to August 31, 2011, which effectively increased the average price received for oil by $2.57 per Bbl to $91.70 per Bbl for that period. Additionally, in November 2011 the Trust received $0.7 million related to production from the Royalty Interests in September 2011 from the counterparty to the novated contracts. Derivative settlements related to September 2011 production were included in the Trust’s February 2012 quarterly distribution.

Post-Production Expenses. The Trust bears post-production expenses attributable to production from the Royalty Interests. Post-production expenses generally consist of costs incurred to gather, store, compress, transport, process, treat, dehydrate and market the oil and natural gas produced. Post-production expenses for the year ended December 31, 2011 totaled approximately $22,000.

Production Taxes. Production taxes are calculated as a percentage of oil and natural gas revenues, excluding the effects of derivative settlements and net of any applicable tax credits. Production taxes for the year ended December 31, 2011 totaled $2.0 million, or $4.14 per Boe, and were approximately 4.8% of royalty income.

Texas Franchise Tax. The Trust did not make any Texas franchise tax payments during the year ended December 31, 2011. The Trust’s estimated 2011 Texas franchise tax liability of approximately $0.2 million will be paid during 2012.

Distributable Income. Distributable income for the year ended December 31, 2011 was $38.6 million, which included a $1.1 million reduction to establish a cash reserve for the payment of future Trust expenses. The amount of the cash reserve was equivalent to the sum of the Trust’s estimated annual administrative expenses, or approximately $1.0 million, and the Trust administrative expenses expected to be incurred and paid before the quarterly distribution in February 2012, or approximately $0.1 million.

Distributable income for the year ended December 31, 2011 of $38.6 million was higher than the target of $34.6 million for the period primarily due to the receipt of $0.7 million in derivative settlements related to September 2011 production and higher than anticipated oil and natural gas production for the period from April 1, 2011 to August 31, 2011, partially offset by lower than anticipated oil prices. Actual production volumes of 453 MBbl of oil and 120 MMcf of natural gas for the period from April 1, 2011 to August 31, 2011 exceeded assumed production of 424 MBbl of oil and 107 MMcf of natural gas used in preparing the target distribution level for the period. The average price received for oil produced from April 1, 2011 to August 31, 2011, including the impact of derivative settlements attributable to those production periods, was $91.70 per Bbl compared to $96.53 per Bbl assumed in preparing the target distribution level for the period. The average price received for natural gas produced from April 1, 2011 to August 31, 2011, including the impact of post-production expenses of approximately $22,000, was $3.25 per Mcf of natural gas compared to $3.17 per Mcf assumed in preparing the target distribution level for the period.

Liquidity and Capital Resources

The Trust’s principal sources of liquidity and capital are cash flow generated from the Royalty Interests and the Trust’s derivative contracts, and borrowings to fund administrative expenses, including any amounts borrowed under SandRidge’s loan commitment described in Note 5 to the financial statements contained in Part II, Item 8 of this report. The Trust’s primary uses of cash are distributions to Trust unitholders, including, if applicable, incentive distributions to SandRidge, payment of amounts owed under the Trust’s derivative contracts, payment of Trust administrative expenses, including any reserves established by the Trustee for future liabilities, payment of applicable taxes and payment of expense reimbursements to SandRidge for out-of-pocket expenses incurred on behalf of the Trust.

Administrative expenses include payments to the Trustee and the Delaware Trustee as well as a quarterly fee of $75,000 to SandRidge pursuant to an administrative services agreement. Each quarter, the Trustee determines the amount of funds available for distribution. Available funds are the excess cash, if any, received by the Trust from the sale of oil and natural gas production attributable to the Royalty Interests that quarter over the Trust’s expenses for the quarter, subject in all cases to the subordination and incentive provisions previously described. 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 to pay such expenses. 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.

Under the derivatives agreement, SandRidge pays the Trust amounts it receives from its counterparty and the Trust pays SandRidge any amounts that SandRidge is required to pay such counterparty. Additionally, the Trust receives payment directly from its counterparty to the contracts novated to the Trust by SandRidge and is required to pay any amounts owed under those contracts directly to the counterparty. Significant payments by the Trust to SandRidge or the counterparty to the novated contracts could reduce or eliminate distributions paid to unitholders.

Under the conveyances granting the Royalty Interests, the Trust does not have any capital requirements related to drilling wells or any other operating and capital costs related to the wells.

Trust Distributions to Unitholders. During the year ended December 31, 2011, the Trust’s distributions to unitholders were as follows:

Covered Production
Period

Date
Declared

Date Paid

Total
Distribution
Paid

(in millions)

Calendar Quarter 2011

First Quarter

N/A

Second Quarter

N/A

Third Quarter

N/A

Fourth Quarter

April 1 – August 31

October 28

November 30

37.9

On February 29, 2012, the Trust paid a cash distribution of $0.553523 per unit covering production for the period from September 1, 2011 to November 30, 2011. The distribution totaled $29.1 million and was made to record unitholders as of February 14, 2012.

Contractual Obligations

A summary of the Trust’s contractual obligations as of December 31, 2011 is provided in the following table:


	Payments Due by Year
	2012		2013		2014		2015		2016		After 2016		Total
	(in thousands)
Administrative services fee	$	300.0	$	300.0	$	300.0	$	300.0	$	300.0	$	4,275.0	$	5,775.0
Trustee Administrative fee		150.0		150.0		150.0		150.0		150.0		2,137.5		2,887.5
Collateral agency fee		15.0		15.0		15.0		15.0		—		—		60.0
Delaware Trustee fee		2.4		2.4		2.4		2.4		2.4		36.0		48.0

Total	$	467.4	$	467.4	$	467.4	$	467.4	$	452.4	$	6,448.5	$	8,770.5

Pursuant to the terms of the administrative services agreement with SandRidge, the Trust is obligated to pay SandRidge an annual administrative services fee of $300,000 for accounting, tax preparation, bookkeeping, informational and hedge management services to be performed by SandRidge on behalf of the Trust throughout the life of the Trust. Pursuant to the trust agreement, the Trust is obligated to pay the Trustee an annual administrative fee of $150,000 until April 1, 2017 after which the fee will be adjusted annually for inflation by no more than plus or minus 3% in any one year through 2030, and the Trust is obligated to pay the Delaware Trustee an annual fee of $2,400, throughout the life of the Trust. Additionally, pursuant to the terms of the collateral agency agreement, the Trust pays an annual fee of $15,000 to the collateral agent through 2015.

Critical Accounting Policies and Estimates

The financial statements of the Trust are significantly affected by its basis of accounting and estimates related to the Royalty Interests and proved reserves, as summarized below.

Basis of Accounting. The financial statements of the Trust differ from financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) as the Trust records revenues when cash is received rather than when earned and expenses when paid rather than when incurred and may also establish certain cash reserves for contingencies, which would not be accrued in financial statements prepared in accordance with GAAP. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the SEC as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts. Amortization and any impairment of the royalty interests are charged directly to trust corpus. Because the Trust’s financial statements are prepared on a modified cash basis, most accounting pronouncements are not applicable to the Trust’s financial statements.

Oil and Natural Gas Reserves. The proved oil and natural gas reserves for the Royalty Interests are estimated by independent petroleum engineers. Estimates of proved reserves are based on the quantities of oil and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions, however, there are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, rates of production and timing of development expenditures, including many factors beyond the Trust’s control. Estimating reserves is very complex and relies on assumptions and subjective interpretations of available geologic, geophysical, engineering and production data, and the accuracy of reserve estimates is a function of the quality and quantity of available data, engineering and geological interpretation and judgment. In addition, as a result of volatility of changing market conditions, commodity prices will vary from period to period, causing estimates of proved reserves to vary, as well as causing estimates of future net revenues to vary. Estimates of proved reserves are key components of the Trust’s most significant financial estimates as discussed further below.

Amortization of Investment in Royalty Interests. Amortization of investment in royalty interests is calculated on a units-of-production basis, whereby the Trust’s cost basis is divided by the proved reserves attributable to the Royalty Interests to derive an amortization rate per reserve unit. The rate of recording amortization is dependent upon the estimate of total proved reserves for the Royalty Interests, which incorporates various assumptions and future projections. If the estimates of total proved reserves decline significantly, the rate at which the Trust records amortization would increase, reducing trust corpus. Such a decline in reserves may result from lower commodity prices, which may make it uneconomic for SandRidge to develop or produce the Underlying Properties. Changes in reserve quantity estimates are dependent on future economic and operational conditions and cannot be predicted.

Impairment of Investment in Royalty Interests. The investment in royalty interests is assessed to determine whether net capitalized cost is impaired whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Potential impairments of the investment in royalty interests are determined by comparing the net capitalized costs of investment in royalty interests to undiscounted future net revenues attributable to the Trust’s interest in the proved oil and natural gas reserves of the Underlying Properties. The Trust provides a write-down to the extent that the net capitalized costs exceed the fair value of the Royalty Interests, which is determined using net discounted future cash flows of the oil and natural gas reserves attributable to the Royalty Interests. Different pricing assumptions or discount rates could result in a different calculated impairment. Any such write-down would be charged directly to trust corpus and would not reduce distributable income.

Refer to Note 1 to the financial statements included in Item 8 of this report for the Trust’s significant accounting policies.

Off-balance sheet arrangements

As of December 31, 2011, the Trust had no off-balance sheet arrangements.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

The discussion in this section provides information about commodity derivative contracts, the benefits and obligations of which SandRidge has passed to the Trust pursuant to a derivatives agreement effective August 1, 2011. Under the derivatives agreement, SandRidge pays the Trust amounts it receives from its counterparty under certain of its derivative contracts with a third party, and the Trust pays SandRidge any amounts that SandRidge is required to pay its counterparty under such derivative contracts. Substantially concurrent with the execution of the derivatives agreement, SandRidge novated certain of the derivative contracts underlying the derivatives agreement to the Trust. As a party to these contracts, the Trust receives payment directly from the counterparty, and is required to pay any amounts owed directly to the counterparty. To secure its obligations under these novated contracts, the Trust entered into a collateral agency agreement and has granted the counterparty a lien on the Royalty Interests. Under the collateral agency agreement, the Trust will pay 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 commodity derivative contracts underlying the derivatives agreement are settled in cash and do not require the actual delivery of a commodity at settlement. Fixed price swap contracts are settled based upon NYMEX prices. The contracts underlying the derivatives agreement cover a portion of the anticipated future sales volumes of oil production from the Initial Wells as well as a portion of the anticipated future production from the Trust Development Wells through March 31, 2015. See Note 6 to the financial statements contained in Item 8 of this report for notional and price information of the Trust’s open oil derivative contracts at December 31, 2011. The Trust received net settlement proceeds of approximately $1.8 million related to the derivatives agreement and the Trust’s derivative contracts with a third party during the year ended December 31, 2011.

Commodity Price Risk. Because the Trust’s primary asset and source of income is the Royalty Interests, which generally entitles the Trust to receive a portion of the net proceeds from sales of oil and natural gas production from the Underlying Properties, the Trust’s most significant market risk relates to the prices received for oil and natural gas production. The derivative contracts described above are intended to mitigate a portion of the variability of oil prices received for the Trust’s share of production from the Underlying Properties.

Credit Risk. A portion of the Trust’s liquidity is concentrated in the derivative contracts described above. The use of derivative contracts, including the arrangement between the Trust and SandRidge, involves the risk that SandRidge or its counterparty or the Trust’s unaffiliated counterparty will be unable to meet their obligations under the contracts. The Trust’s counterparty under the derivatives agreement is SandRidge, whose sole current counterparty is an institution with a corporate credit rating equal to or better than an “investment grade” credit rating. The sole current counterparty to the derivative contracts novated by SandRidge to the Trust is also an institution with a corporate credit rating of at least an “investment grade” credit rating. SandRidge is not required to pay the Trust to the extent of payment defaults by SandRidge’s counterparty.

Item 8. Financial Statements and Supplementary Data

The Trust’s financial statements required by this item are included in this report beginning on page F-1.

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

None.

Item 9A. Controls and Procedures

This annual report on Form 10-K does not include a report of the Trustee’s assessment regarding internal control over financial reporting or an attestation report of the Trust’s registered public accounting firm due to a transition period established by the rules of the SEC for newly public companies.

Evaluation of Disclosure Controls and Procedures. The Trustee conducted an evaluation of the Trust’s disclosure controls and procedures as defined in Rules 13a-15 and 15d-15 under the Securities Act designed to ensure that information required to be disclosed by the Trust in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Based on this evaluation, the Trustee has concluded that the disclosure controls and procedures of the Trust are effective as of the end of the period covered by this report. In its evaluation of disclosure controls and procedures, the Trustee has relied, to the extent considered reasonable, on information provided by SandRidge.

Due to the nature of the Trust as a passive entity and in light of the contractual arrangements pursuant to which the Trust was created, including the provisions of (i) the trust agreement, (ii) the administrative services agreement, (iii) the development agreement and (iv) the conveyances granting the Royalty Interests, the Trustee’s disclosure controls and procedures related to the Trust necessarily rely on (A) information provided by SandRidge, including information relating to result of operations, the status of drilling of the Trust Development Wells, the costs and revenues attributable to the Trust’s interests under the conveyance and other operating and historical data, plans for future operating and capital expenditures, reserve information, information relating to projected production, and other information relating to the status and results of operations of the Underlying Properties and the Royalty Interests, and (B) conclusions and reports regarding reserves by the Trust’s independent reserve engineers.

Changes in Internal Control over Financial Reporting. There were no changes in the Trust’s internal control over financial reporting during the quarter ended December 31, 2011 that have materially affected, or are reasonably likely to materially affect, the Trust’s internal control over financial reporting. The Trustee notes for purposes of clarification that it has no authority over, has not evaluated and makes no statement concerning, the internal control over financial reporting of SandRidge.

Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The Trust has no directors or executive officers. The Trustee is a corporate trustee that may be removed by the affirmative vote of the holders of not less than a majority of the outstanding Trust units, excluding Trust units held by SandRidge, at a special meeting of the Trust unitholders at which a quorum is present.

Section 16(a) Beneficial Ownership Reporting Compliance

The Trust has no directors or officers. Accordingly, only holders of more than 10% of the Trust’s units are required to file with the SEC initial reports of ownership of units and reports of changes in such ownership pursuant to Section 16 under the Securities Exchange Act of 1934. Based solely on a review of these reports, the Trustee is not aware of any person having failed to file on a timely basis the reports required by section 16(a) of the Exchange Act during the most recent fiscal year or prior fiscal years. In making this statement, the Trustee has relied upon examination of the copies of Forms 3, 4 and 5, to the extent there were any, provided to the Trust.

Audit Committee and Nominating Committee

Because the Trust does not have a board of directors, it does not have an audit committee, an audit committee financial expert or a nominating committee.

Code of Ethics

The Trust does not have a principal executive officer, principal financial officer, principal accounting officer or controller and, therefore, has not adopted a code of ethics applicable to such persons.

Item 11. Executive Compensation

During the year ended December 31, 2011, the Trustee and the Delaware Trustee received administrative fees from the Trust pursuant to the trust agreement. The Trust does not have any executive officers, directors or employees. Because the Trust does not have a board of directors, it does not have a compensation committee.

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

(a) Security Ownership of Certain Beneficial Owners.

The following table sets forth certain information regarding the beneficial ownership of the Trust units as of March 19, 2012 by each person who, to the Trustee’s knowledge, beneficially owns more than 5% of the outstanding Trust units.


Name and Address of Beneficial Owner	Title of Class		Amount and Nature of Beneficial Ownership			Percent of Class
SandRidge Energy, Inc.		Common units		2,875,000	(1)		7.3	%
123 Robert S. Kerr Avenue
Oklahoma City, OK 73102		Subordinated units		13,125,000	(1)		100.0	%

Goldman Sachs Asset Management		Common units		2,390,000			6.1	%
200 West Street
New York, NY 10282

(1)	All 2,875,000 common units and 13,125,000 subordinated units beneficially owned by SandRidge are held of record by its wholly owned subsidiary, SandRidge Exploration and Production, LLC.

At the end of the fourth full calendar quarter following SandRidge’s satisfaction of its drilling obligation to the trust, the subordinated units will automatically convert into common units on a one-for-one basis. The subordinated units constitute 25% of the total number of units outstanding. As of March 19, 2012, SandRidge owned 30.5% of the total Trust units outstanding.

(b) Security Ownership of Management.

Not applicable.

The registrant knows of no arrangement, including any pledge by any person of securities of the registrant or any of its parents, the operation of which may at a subsequent date result in a change of control of the registrant.

Item 13. Certain Relationships and Related Transactions and Director Independence

In conjunction with the conveyance of the Royalty Interests to the Trust, the Trust entered into the development agreement and the administrative services agreement with SandRidge and/or one of its wholly owned subsidiaries on August 16, 2011, effective April 1, 2011. Additionally, on August 16, 2011, the Trust entered into the derivatives agreement with SandRidge, which was effective August 1, 2011, and the registration rights agreement with SandRidge. The Trust makes certain payments to SandRidge, the Trustee and the Delaware Trustee pursuant to the trust agreement, the administrative services agreement and the derivatives agreement. Descriptions of these agreements are included in the “— Business” section of Part 1, Item 1; in the “Trustee’s Discussion and Analysis of Financial Condition and Results of Operations” section of Part II, Item 7; and in Note 6 to the financial statements included in Item 8 of this report. In addition, the description of the IPO included in Part 1, Item 1 — Business of this report is hereby incorporated by reference.

Director Independence

The Trust does not have a board of directors. Further, the Trust relies on an exemption from the director independence requirements of the New York Stock Exchange set forth in Rule 10A-3(c)(7) under the Securities Exchange Act of 1934, applicable to listed issuers organized as trusts that do not have a board of directors.

Item 14. Principal Accounting Fees and Services

The Trust does not have an audit committee. Any pre-approval and approval of all services performed by the principal auditor or any other professional service firms and related fees are granted by the Trustee.

The following table presents fees for professional audit services rendered by PricewaterhouseCoopers LLP for the audit of the Trust’s financial statements for 2011 and fees billed for other services rendered by PricewaterhouseCoopers LLP.


Audit fees(1)	$	225,000
Audit-related fees		—
Tax fees		285,000
All other fees		—

Total fees	$	510,000

(1)	Fees for audit services in 2011 consisted of the audit of the Trust’s annual financial statements and reviews of the Trust’s quarterly financial statements.

PART IV

Item 15. Exhibits and Financial Statement Schedules

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

(1)

Financial Statements

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

(2)

Financial Statement Schedules

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

(3)

Exhibits

Reference is made to the Exhibit Index.

INDEX TO FINANCIAL STATEMENTS


	Page(s)
Report of Independent Registered Public Accounting Firm		F-2
Statement of Assets and Trust corpus at December 31, 2011		F-3
Statement of Distributable Income for the Year Ended December 31, 2011		F-4
Statement of Changes in Trust Corpus for the Year Ended December 31, 2011		F-5
Notes to Financial Statements		F-6

F-1

Report of Independent Registered Public Accounting Firm

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

We have audited the accompanying statement of assets and trust corpus of SandRidge Permian Trust (the “Trust”) as of December 31, 2011, and the related statement of distributable income and statement of changes in trust corpus for the year then ended. These financial statements are the responsibility of trustee. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the assets and trust corpus of the Trust at December 31, 2011, and its distributable income and changes in trust corpus for the year then ended, on the basis of accounting described in Note 2.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Tulsa, Oklahoma

March 26, 2012

F-2

SANDRIDGE PERMIAN TRUST

STATEMENT OF ASSETS AND TRUST CORPUS

DECEMBER 31, 2011

(In thousands, except unit data)


ASSETS
Cash and cash equivalents	$	1,815
Investment in royalty interests		549,831
Less: accumulated amortization		(23,121	)

Net investment in royalty interests		526,710

Total assets	$	528,525

TRUST CORPUS
Trust corpus, 39,375,000 common units and 13,125,000 subordinated units issued and outstanding at December 31, 2011	$	528,525

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

F-3

SANDRIDGE PERMIAN TRUST

STATEMENT OF DISTRIBUTABLE INCOME

FOR THE YEAR ENDED DECEMBER 31, 2011

(In thousands, except unit and per unit data)


Revenues
Royalty income	$	40,795
Derivative settlements, net		1,835

Total revenues		42,630

Expenses
Post-production expenses		22
Ad valorem taxes		225
Production taxes		1,959
Trust administrative expenses		666
Cash reserves withheld, net of amounts used for current Trust expenses		1,139

Total expenses		4,011

Distributable income available to unitholders	$	38,619

Distributable income per unit (52,500,000 units issued and outstanding)	$	0.735607

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

F-4

SANDRIDGE PERMIAN TRUST

STATEMENT OF CHANGES IN TRUST CORPUS

FOR THE YEAR ENDED DECEMBER 31, 2011

(In thousands)


Trust corpus, beginning of year	$	—
Initial Trust funding		1
Issuance of Trust units		580,635
Conveyance of royalty interests		549,831
Consideration paid for conveyance of royalty interests		(580,635	)
Amortization of investment in royalty interests		(23,121	)
Net cash reserves withheld		1,139
Distributable income		38,619
Distributions paid or payable to unitholders		(37,944	)

Trust corpus, end of year	$	528,525

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

F-5

SANDRIDGE PERMIAN TRUST

NOTES TO FINANCIAL STATEMENTS

1. Organization of the Trust

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

The Trust 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 August 16, 2011). These Royalty Interests were derived from SandRidge’s interests in specified oil and natural gas properties located in Andrews County, Texas (the “Underlying Properties”). As of December 31, 2011, these properties consisted of (a) 517 oil and natural gas wells developed as of April 1, 2011, including 21 wells awaiting completion at that time (the “Initial Wells”), (b) 188 wells (equivalent to approximately 195 development wells under the development agreement described below) that were drilled and perforated for completion between April 1, 2011 and December 31, 2011 (the “Additional Drilled Wells” and, together with the Initial Wells, the “Drilled Wells”) and (c) the equivalent of approximately 693 oil and natural gas development wells to be drilled (the “Remaining Development Wells” and, together with the Additional Drilled Wells, the “Trust Development Wells”) in an area of mutual interest (“AMI”). As specified in the development agreement executed by the Trust with SandRidge (see Note 6), SandRidge is credited for having drilled one full Trust Development Well if the well is drilled and perforated for completion to the Grayburg/San Andres formation and SandRidge’s net revenue interest in the well is equal to 69.3%. The actual number of wells required to be drilled may increase or decrease in proportion to SandRidge’s net revenue interest in each well.

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 managed by the Trustee. The trust agreement generally limits the Trust’s business activities to owning the Royalty Interests and entering into derivative contracts on a limited basis and activities reasonably related thereto, including activities required or permitted by the terms of the conveyances related to the Royalty Interests.

The 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 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 and natural gas production attributable to SandRidge’s net revenue interest in the Trust Development Wells beginning on April 1, 2011, the effective date of the conveyance.

The Trust is not responsible for any costs related to the drilling of the Trust Development Wells or any other operating or capital costs related to the Underlying Properties. The Trust’s cash receipts with respect to the Royalty Interests in the Underlying Properties are determined after deducting post-production costs and any applicable taxes associated with the Royalty Interests. Post-production costs generally consist of costs incurred to gather, store, compress, transport, process, treat, dehydrate and market the oil, including natural gas liquids and natural gas produced. The Trust’s distributable income is adjusted for amounts received and paid under the Trust’s derivative contracts as discussed further in Note 6, and is reduced by the Trust’s cash reserves withheld by the Trustee and general and administrative expenses when paid.

Through an initial public offering (“IPO”) 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 IPO, 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, 2011, there were 52,500,000 Trust units, consisting of 39,375,000 common and 13,125,000 subordinated units, issued and outstanding. The common and subordinated units have identical rights and privileges, except with respect to their rights to receive distributions as described below.

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

F-6

SANDRIDGE PERMIAN TRUST

NOTES TO FINANCIAL STATEMENTS

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

2. Significant Accounting Policies

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

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

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

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

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

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

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

F-7

SANDRIDGE PERMIAN TRUST

NOTES TO FINANCIAL STATEMENTS

The investment in royalty interests is assessed to determine whether net capitalized cost is impaired whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If an assessment is necessary, an impairment would be indicated when the net capitalized costs of investment in royalty interests exceeds undiscounted future net revenues attributable to the Trust’s interest in the proved oil and natural gas reserves of the Underlying Properties. The Trust will provide a write-down to the extent that the net capitalized costs exceed the fair value of the proved oil and natural gas reserves attributable to the Royalty Interests. Any such write-down would be charged directly to trust corpus and would not reduce distributable income.

Derivative Financial Instruments. The Trust has entered into derivative contracts to manage risks related to oil price volatility. See Note 6. The Trust uses the cash method to account for derivative instruments, under which it records benefits or obligations from derivative contracts when such benefits are received or obligations are paid. The fair market values and changes in the fair market value of the derivative contracts are not included in the accompanying financial statements as the statements are presented on a modified cash basis. The Trust received net settlement proceeds of approximately $1.8 million related to its derivative contracts during the year ended December 31, 2011, including $0.7 million related to September 2011 production that was included in the Trust’s February 2012 distribution. See Note 8 for further discussion of the February 2012 distribution.

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

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

The use of hedging transactions involves the risk that the counterparties may be unable to meet the financial terms of the transactions. The counterparties to the contracts novated to the Trust by SandRidge have an “investment grade” credit rating. SandRidge, on behalf of the Trust, monitors on an ongoing basis the credit rating of the hedging counterparties. The Trust has a master netting agreement with its derivative contract counterparties, which allows the Trust to net amounts due from and owed to the same counterparty. As a result of the netting provision, the Trust’s maximum amount of loss under the hedging transaction due to credit risk is limited to the net amount due from the counterparties under the derivatives. As of December 31, 2011, the counterparty to the contracts novated to the Trust by SandRidge consisted of one financial institution. The Trust is not required to post additional collateral under the derivative contract.

3. Income Taxes

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

4. Distributions to Unitholders

The Trust makes quarterly cash distributions of substantially all of its cash receipts, after deducting amounts for the Trust’s administrative expenses and cash reserves withheld by the Trustee, ad valorem 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. Subsequent distributions each cover a three-month period. Distributions to unitholders are recorded when declared. During the year ended December 31, 2011, the Trust’s distributions to unitholders were as follows:

F-8

SANDRIDGE PERMIAN TRUST

NOTES TO FINANCIAL STATEMENTS


	Covered Production Period	Date Declared	Date Paid	Total Distribution Paid	Distribution Per Unit
				(in millions)
Calendar Quarter 2011
First Quarter	N/A	N/A	N/A	N/A	N/A
Second Quarter	N/A	N/A	N/A	N/A	N/A
Third Quarter	N/A	N/A	N/A	N/A	N/A
Fourth Quarter	April 1 –August 31	October 28	November 30	$37.9	$0.722746

5. Loan Commitment

Pursuant to the trust agreement, if at any time the Trust’s cash on hand (including available cash reserves) is not sufficient to pay the Trust’s ordinary course administrative expenses as they become due, SandRidge will loan funds to the Trust necessary to pay such expenses. Any funds loaned by SandRidge pursuant to this commitment will be limited to the payment of current accounts payable or other obligations to trade creditors in connection with obtaining goods or services or the payment of other accrued current liabilities arising in the ordinary course of the Trust’s business, and may not be used to satisfy Trust indebtedness, or to make distributions. If SandRidge loans funds pursuant to this commitment, unless SandRidge agrees otherwise, no further distributions will be made to unitholders (except in respect of any previously determined quarterly cash distribution amount) until such loan is repaid. Any such loan will be on an unsecured basis, and the terms of such loan will be substantially the same as those which would be obtained in an arm’s length transaction between SandRidge and an unaffiliated third party. As of December 31, 2011, there was no such loan outstanding with SandRidge.

6. Related Party Transactions

Trustee Administrative Fee. Under the terms of the trust agreement, the Trust pays an annual administrative fee of $150,000 to the Trustee, which will be adjusted for inflation by no more than 3% in any year, beginning in 2017. The Trustee waived its administrative fee for the second quarter of 2011. During 2011, the Trust paid the Trustee’s and the Delaware Trustee’s legal expenses incurred in forming the Trust, as well as the Trustee’s acceptance fee in the amount of $10,000. The Trustee’s administrative fees paid during the year ended December 31, 2011 totaled $47,500.

Registration Rights Agreement. On August 16, 2011, 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.

Development Agreement. On August 16, 2011, 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, 2015. In the event of delays, SandRidge will have until March 31, 2016 to fulfill its drilling obligation. Additionally, SandRidge agreed not to drill and complete, or allow another person within its control to drill and complete, any other well in the AMI, other than (a) the Trust Development Wells, (b) up to five horizontal wells to test the results of horizontal drilling in the AMI and (c) wells that were spud and temporarily abandoned on or before March 31, 2011, until SandRidge has fulfilled its drilling obligation. The Trust will not own any interests in the five test horizontal wells, if they are drilled, and such wells will not count toward SandRidge’s drilling obligation.

A wholly owned subsidiary of SandRidge granted to the Trust a lien (“Drilling Support Lien”) covering its interest in the AMI (except its interest in the Initial Wells) in order to secure the estimated amount of the drilling costs for the Trust’s interests in the undeveloped Underlying Properties. The initial amount recoverable by the Trust pursuant to the Drilling Support Lien could not exceed approximately $295.0 million, subject to adjustment as described below. As SandRidge fulfills its drilling obligation over time, the total amount that may be recovered is proportionately reduced and the Trust Development Wells drilled and perforated for completion are released from the lien. If SandRidge does not fulfill its drilling obligation by March 31, 2016, the Trust may foreclose on any remaining interest in the AMI that is subject to the Drilling Support Lien. Any amounts actually recovered in a foreclosure action would be applied to the completion of SandRidge’s drilling obligation and would not result in a distribution to the Trust’s unitholders. As of December 31, 2011, SandRidge had drilled and perforated for completion approximately 195 equivalent Trust Development Wells, and, accordingly, the maximum amount potentially recoverable under the Drilling Support Lien had been reduced to approximately $229.7 million.

F-9

SANDRIDGE PERMIAN TRUST

NOTES TO FINANCIAL STATEMENTS

Administrative Services Agreement. On August 16, 2011, 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 (discussed 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. SandRidge agreed to waive its administrative services fee for the second quarter of 2011. During the year ended December 31, 2011, the Trust paid $75,000 to SandRidge for administrative service fees and approximately $36,000 in reimbursement of expenses.

Derivatives Agreement. On August 16, 2011, the Trust entered into a derivatives agreement with SandRidge, effective August 1, 2011, that provides the Trust with the economic effect of certain oil derivative contracts entered into between SandRidge and a third party. Under the derivatives agreement, SandRidge pays the Trust amounts it receives from its counterparty and the Trust pays SandRidge any amounts that SandRidge is required to pay such counterparty. Substantially concurrent with the execution of the derivatives agreement, SandRidge novated certain of the derivative contracts underlying the derivatives agreement to the Trust. As a party to these contracts, the Trust receives payment directly from the counterparty and is required to pay any amounts owed directly to the counterparty. To secure its obligations under these novated contracts, the Trust entered into a collateral agency agreement and granted the counterparty a lien on the Royalty Interests. Under the collateral agency agreement, the Trust pays a $15,000 annual fee to the collateral agent. Under the derivatives agreement, as Trust Development Wells are drilled, SandRidge has the right, under certain circumstances, to assign or novate to the Trust additional derivative contracts. The Trust’s derivative contracts consist of fixed price swaps.

The following tables present as of December 31, 2011 the notional amount and weighted average fixed price of the open contracts underlying the derivatives agreement, including the contracts that were subsequently novated to the Trust. The combined volume in the tables below reflects the total volume of oil derivative contracts for the Trust.

Oil Contracts Underlying the Derivatives Agreement


	Notional (MBbl)		Weighted Avg. Fixed Price
Contract Period
January 2012 — December 2012		687		$102.20
January 2013 — December 2013		921		$102.84
January 2014 — December 2014		1,100		$101.75
January 2015 — March 2015		232		$100.90

Oil Contracts Underlying the Derivatives Agreement and Subsequently Novated to the Trust


	Notional (MBbl)		Weighted Avg. Fixed Price
Contract Period
January 2012 — December 2012		466		$102.20
January 2013 — December 2013		368		$102.84
January 2014 — December 2014		311		$101.75
January 2015 — March 2015		71		$100.90

7. Major Customers

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

F-10

SANDRIDGE PERMIAN TRUST

NOTES TO FINANCIAL STATEMENTS


	2011
	Sales		% of Revenue
	(in thousands)
Enterprise Crude Oil LLC	$	35,558.6		87.2	%

8. Subsequent Events

On February 2, 2012, the Trust declared a cash distribution of $0.553523 per unit covering production for the three-month period from September 1, 2011 to November 30, 2011 for record unitholders as of February 14, 2012. The distribution was paid on February 29, 2012. Distributable income for September 1, 2011 to November 30, 2011 was calculated as follows (in thousands, except for unit and per unit amounts):


Revenues
Royalty income	$	29,166
Derivative settlements, net(1)		2,464

Total revenues		31,630


Expenses
Post-production expenses		40
Production taxes		1,401
Cash reserves withheld by Trustee(2)		1,129

Total expenses		2,570

Distributable income available to unitholders	$	29,060

Distributable income per unit (52,500,000 units issued and outstanding)	$	0.553523

(1)	Includes approximately $0.7 million in derivative settlements related to September 2011 production received in November 2011.

(2)	Includes amounts withheld for annual Trust administrative expenses.

9. Supplemental Information on Oil and Natural Gas Producing Activities

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


			For the period
	Modified Cash Basis(1)		April 1, 2011 to August 16, 2011			September 1, 2011 to December 31, 2011		Accrual Basis(2)
Production Data
Oil (MBbls)(3)		453.0		(394.3	)		454.8		513.5
Natural Gas (MMcf)		119.9		(105.5	)		117.0		131.4
Combined equivalent volumes (MBoe)		473.0		(411.8	)		474.2		535.4

Royalty Income (in thousands)	$	40,795	$	(36,007	)	$	39,642	$	44,430
Expenses (in thousands):
Post-production costs		22		(18	)		33		37
Ad valorem taxes		225		(202	)		170		193
Production taxes		1,959		(1,729	)		1,897		2,127

	$	38,589	$	(34,058	)	$	37,542	$	42,073

F-11

SANDRIDGE PERMIAN TRUST

NOTES TO FINANCIAL STATEMENTS

(1)	Oil and natural gas volumes attributable to the Royalty Interests and related revenues and expenses included in SandRidge’s November 2011 net revenue distributions to the Trust. Represents oil and natural gas production from April 1, 2011 to August 31, 2011.

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

(3)	Includes natural gas liquids.

Capitalized Costs Related to Oil and Natural Gas Producing Activities

The Trust’s capitalized costs consisted of the following at December 31, 2011 (in thousands):


Investment in royalty interests
Proved(1)	$	549,831
Unproved		—

Total investment in royalty interests		549,831
Less accumulated amortization		(23,121	)

Net investment in royalty interests	$	526,710

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

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

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

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

The Trust’s results of operations from oil and natural gas producing activities for the year ended December 31, 2011 are shown in the following table (in thousands):


Revenues(1)	$	44,430
Expenses(1)(2)
Post-production costs		37
Ad valorem taxes		193
Production taxes		2,127
Amortization expense(3)		23,121

Income before income taxes		18,952
Income taxes(4)		156

Results for oil and natural gas producing activities (excluding general and administrative costs and derivative settlements of the Trust)	$	18,796

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

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

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

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

Oil and Natural Gas Reserve Quantities (Unaudited)

Proved oil and natural gas reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, based on prices used to estimate reserves, from a

F-12

SANDRIDGE PERMIAN TRUST

NOTES TO FINANCIAL STATEMENTS

given date forward from known reservoirs, and under existing economic conditions, operating methods, and government regulation before the time of which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Proved developed reserves are proved reserves expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively large major expenditure is required for recompletion.

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

The Trustee believes the geoscience and engineering data examined provides reasonable assurance that the proved reserves are economically producible in future years from known reservoirs, and under existing economic conditions, operating methods and governmental regulations. Estimates of proved reserves are subject to change, either positively or negatively, as additional information is available and contractual and economic conditions change.

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

The summary below presents changes in the Trust’s estimated reserves during the year ended December 31, 2011.


	Oil (MBbls)			Natural Gas (MMcf)(1)
Proved developed and undeveloped reserves
As of December 31, 2010		—			—
Conveyance of Royalty Interests by SandRidge		20,740.4			4,912.1
Revisions of previous estimates		523.5			2,389.8
Extensions and discoveries		—			—
Production(2)		(513.5	)		(131.4	)

As of December 31, 2011		20,750.4			7,170.5

Proved developed reserves(3)
As of December 31, 2011		8,309.9			2,243.9
Proved undeveloped reserves(3)
As of December 31, 2011		12,440.5			4,926.6

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

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

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

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

Standardized Measure of Discounted Future Net Cash Flows (Unaudited)

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

•

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

•

pricing is applied based upon 12-month average market prices at December 31, 2011. The calculated weighted average per unit prices for the Trust’s proved reserves and future net revenues were $88.03 per barrel of oil and $2.94 per Mcf of natural gas; and

•

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

•

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

F-13

SANDRIDGE PERMIAN TRUST

NOTES TO FINANCIAL STATEMENTS

The summary below presents the Trust’s future net cash flows relating to proved oil and natural gas reserves at December 31, 2011 based on the standardized measure (in thousands).


Future cash inflows from production	$	1,847,669
Future production costs(1)		(133,432	)
Future income taxes		(6,467	)

Undiscounted future net cash flows		1,707,770
10% annual discount		(764,941	)

Standardized measure of discounted future net cash flows	$	942,829

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

The following table represents the Trust’s estimate of changes in the standardized measure of discounted future net cash flows from proved reserves during the year ended December 31, 2011 (in thousands):

Changes in the Standardized Measure of Discounted Future Net Cash Flows

Associated with Proved Oil and Natural Gas Reserves


Present value as of December 31, 2010	$	—
Changes during the year
Conveyance of Royalty Interests by SandRidge		835,383
Revenues less post-production and other costs		(42,073	)
Net changes in prices, production and other costs		62,394
Revisions of previous quantity estimates		24,964
Accretion of discount		35,024
Net changes in income taxes		(3,571	)
Timing differences and other(1)		30,707

Net change for the year		942,829

Present value as of December 31, 2011	$	942,829

(1)	Changes in timing differences and other are related to revisions in the estimated timing of production and development.

10. Quarterly Financial Results (Unaudited)

The Trust’s operating results for each calendar quarter of 2011 is summarized below (in thousands, except per unit data).


	First Quarter		Second Quarter		Third Quarter		Fourth Quarter(1)
Royalty income	$	—	$	—	$	—	$	40,795
Distributable income available to unitholders	$	—	$	—	$	—	$	38,619
Distributable income per unit	$	—	$	—	$	—	$	0.735607

(1)	Includes proceeds attributable to production from the Royalty Interests from April 1, 2011 to August 31, 2011.

F-14

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


SANDRIDGE PERMIAN TRUST.

By		/s/ Michael J. Ulrich
		Michael J. Ulrich Vice President The Bank of New York Mellon Trust Company, N.A., as Trustee of SandRidge Permian Trust

March 26, 2012

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

EXHIBIT INDEX


		Incorporated by Reference
Exhibit No.	Exhibit Description	Form		SEC File No.		Exhibit		Filing Date		Filed Herewith

3.1	Certificate of Trust of SandRidge Permian Trust		S-1		333-174492		3.1		08/02/2011

3.2	Trust Agreement of SandRidge Permian Trust, dated May 12, 2011		S-1		333-174492		4.1		08/02/2011

3.3	Amended and Restated Trust Agreement, dated as of August 16, 2011, by and among SandRidge Energy, Inc., The Bank of New York Mellon Trust Company, N.A., and The Corporation Trust Company		8-K		001-35274		4.1		08/19/2011

10.1	Perpetual Overriding Royalty Interest Conveyance (PDP), by and between SandRidge Exploration and Production, LLC and SandRidge Permian Trust		8-K		001-35274		10.3		08/19/2011

10.2	Perpetual Overriding Royalty Interest Conveyance (Development), by and between SandRidge Exploration and Production, LLC and SandRidge Permian Trust		8-K		001-35274		10.4		08/19/2011

10.3	Assignment of Overriding Royalty Interest, by and between Mistmada Oil Company and SandRidge Permian Trust		8-K		001-35274		10.5		08/19/2011

10.4	Term Overriding Royalty Interest Conveyance (PDP), by and between SandRidge Exploration and Production, LLC and Mistmada Oil Company		8-K		001-35274		10.1		08/19/2011

10.5	Term Overriding Royalty Interest Conveyance (Development), by and between SandRidge Exploration and Production, LLC and Mistmada Oil Company		8-K		001-35274		10.2		08/19/2011

10.6	Administrative Services Agreement, by and between SandRidge Energy, Inc. and SandRidge Permian Trust		8-K		001-35274		10.6		08/19/2011

10.7	Development Agreement, by and between SandRidge Energy, Inc., SandRidge Exploration and Production, LLC and SandRidge Permian Trust		8-K		001-35274		10.7		08/19/2011

10.8	Deed of Trust, dated as of August 16, 2011, by and between SandRidge Exploration and Production, LLC and SandRidge Permian Trust		8-K		001-35274		10.9		08/19/2011

10.9	Derivatives Agreement, by and between SandRidge Energy, Inc. and SandRidge Permian Trust		8-K		001-35274		10.8		08/19/2011

10.10	Registration Rights Agreement, dated as of August 16, 2011, by and between SandRidge Energy, Inc. and SandRidge Permian Trust		8-K		001-35274		10.10		08/19/2011

23.1	Consent of Netherland, Sewell & Associates, Inc.										*

31.1	Section 302 Certification										*

32.1	Section 906 Certification										*

99.1	Report of Netherland, Sewell & Associates, Inc.										*