SandRidge Mississippian Trust I - Annual Report: 2013 (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, 2013

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

For the transition period from to

Commission File Number: 001-35122

SANDRIDGE MISSISSIPPIAN TRUST I

(Exact name of registrant as specified in its charter)

Delaware		27-6990649
(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)

(512) 236-6531

(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 o No x

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer	o		Accelerated filer	x
Non-accelerated filer	o (Do not check if smaller reporting company)		Smaller reporting company	o

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

The aggregate market value of Common Units of Beneficial Interest of the Trust held by non-affiliates on June 28, 2013 (the last business day of its most recently completed second quarter) was approximately $285.2 million based on the closing price as quoted on the New York Stock Exchange. As of March 7, 2014, 21,000,000 Common Units and 7,000,000 Subordinated Units of Beneficial Interest in SandRidge Mississippian Trust I were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: None

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SANDRIDGE MISSISSIPPIAN TRUST I

2013 ANNUAL REPORT ON FORM 10-K

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Item		Page

	PART I
1.	Business	1
1A.	Risk Factors	19
1B.	Unresolved Staff Comments	31
2.	Properties	31
3.	Legal Proceedings	31
4.	Mine Safety Disclosures	32

	PART II
5.	Market for Common Units of the Trust, Related Unitholder Matters and Issuer Purchases of Common Units	33
6.	Selected Financial Data	34
7.	Trustee’s Discussion and Analysis of Financial Condition and Results of Operations	35
7A.	Quantitative and Qualitative Disclosures about Market Risk	41
8.	Financial Statements and Supplementary Data	41
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	41
9A.	Controls and Procedures	41
9B.	Other Information	42

	PART III
10.	Directors, Executive Officers and Corporate Governance	43
11.	Executive Compensation	43
12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	43
13.	Certain Relationships and Related Transactions and Director Independence	44
14.	Principal Accounting Fees and Services	44

	PART IV
15.	Exhibits and Financial Statement Schedules	45

All references to “we,” “us,” “our,” or the “Trust” refer to SandRidge Mississippian Trust I. 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 Mississippian formation in Oklahoma 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 16.

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FORWARD-LOOKING STATEMENTS

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

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PART I

Item 1. Business

General

SandRidge Mississippian Trust I is a statutory trust formed on December 30, 2010 under the Delaware Statutory Trust Act pursuant to a trust agreement by and among SandRidge, as Trustor, The Bank of New York Mellon Trust Company, N.A., as Trustee (the “Trustee”), and The Corporation Trust Company, as Delaware Trustee (the “Delaware Trustee”). The Trust’s affairs are administered by the Trustee, which maintains its offices at 919 Congress Avenue, Austin, Texas 78701. The Trust does not have any employees.

Copies of reports filed by the Trust under the Exchange Act are made available as soon as reasonably practicable after such materials are filed with or furnished to the Securities and Exchange Commission (“SEC”). Certain information concerning the Trust and Trust units as well as a link to the Trust’s filings with the SEC may be obtained at the following web site location: sdt.investorhq.businesswire.com. 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 December 30, 2010 by and among SandRidge, the Trustee and the Delaware Trustee (as subsequently amended and restated as of April 12, 2011). Concurrent with the initial public offering described below, SandRidge conveyed to the Trust royalty interests in specified oil and natural gas properties in the Mississippian formation in Alfalfa, Garfield, Grant, Major and Woods counties in Oklahoma (the “Underlying Properties”). These Royalty Interests were derived from SandRidge’s interests in (a) 36 wells producing at December 31, 2010 and one additional well undergoing completion operations at that time (together, the “Initial Wells”) and (b) the equivalent of 123 horizontal development wells to be drilled in the Mississippian formation (“Trust Development Wells”) within an area of mutual interest (“AMI”). SandRidge was obligated to drill, or cause to be drilled, the Trust Development Wells on or before December 31, 2015, and was not permitted to drill and complete any well within the AMI for its own account until it had satisfied the drilling obligation to the Trust. As of April 2013, SandRidge had fulfilled its drilling obligation to the Trust. Accordingly, the AMI terminated effective April 2013. Consequently, no additional wells will be drilled for the Trust.

The Trust issued 28,000,000 Trust units and through an initial public offering in April 2011, the Trust sold 17,250,000 of its common units to the public for net proceeds, after payment of offering expenses, of approximately $336.9 million. The Trust delivered the net proceeds of the offering, along with 3,750,000 common units and 7,000,000 subordinated units, to certain wholly owned subsidiaries of SandRidge, in exchange for the conveyance of the Royalty Interests to the Trust. Upon completion of these transactions and as of December 31, 2013, there were 28,000,000 Trust units, consisting of 21,000,000 common and 7,000,000 subordinated units, issued and outstanding. SandRidge owned 528,063 Trust common units and 7,000,000 Trust subordinated units at December 31, 2013. The common and subordinated units have identical rights and privileges, except with respect to their rights to receive distributions. See “—Distributions” below.

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 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 was prohibited from selling any of the Underlying Properties subject to the Royalty Interest in the Trust Development Wells until it had satisfied its drilling obligation pursuant to the terms of the development agreement discussed below.

The Trust is passive in nature and neither the Trust nor the Trustee has any control over, or responsibility for, costs relating to the operation of the Underlying Properties. The business and affairs of the Trust are administered by the Trustee. However, the Trustee has no authority over or responsibility for, and no involvement with, any aspect of the oil and gas operations or other activities on the Underlying Properties. The trust agreement generally limits the Trust’s business activities to owning the Royalty Interests and any activity reasonably related to such ownership, including activities required or permitted by the terms of the conveyances related to the Royalty Interests and a derivatives agreement between the Trust and SandRidge.

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The Trust will dissolve and begin to liquidate on December 31, 2030 (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.

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.

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 April 12, 2011.

Development Agreement. The Trust entered into a development agreement with SandRidge, effective January 1, 2011, that obligated SandRidge to drill, or cause to be drilled, the Trust Development Wells by December 31, 2015. 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 the Trust Development Wells until SandRidge fulfilled its drilling obligation, which it did in the second quarter of 2013. The Trust was not responsible for any costs related to the drilling of the Trust Development Wells and is not responsible for 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 Trust released the Drilling Support Lien during 2013 subsequent to SandRidge’s fulfillment of its drilling obligation.

Administrative Services Agreement. The Trust entered into an administrative services agreement with SandRidge, effective January 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. For its services under the administrative services agreement, SandRidge receives an annual fee of $200,000, 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. The Trust entered into a derivatives agreement with SandRidge, effective April 1, 2011, that provides the Trust with the economic effect of certain oil and natural gas derivative contracts previously entered into by SandRidge with third parties. The underlying commodity derivative contracts cover volumes of oil and natural gas production through December 31, 2015. Under the derivatives agreement, SandRidge pays the Trust amounts it receives from its counterparties and the Trust pays SandRidge any amounts that SandRidge is required to pay such counterparties. The Trust did not bear any costs related to the establishment of the underlying contracts and does not have the ability to enter into its own derivative contracts. The commodity derivative contracts underlying the derivatives agreement consist of oil and natural gas fixed price swaps and natural gas collars. The hedging arrangements terminate on December 31, 2015.

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

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

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

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

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

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

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

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

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

Distributions

The Trust makes quarterly cash distributions of substantially all of its cash receipts, after deducting amounts for the Trust’s administrative expenses and cash reserves withheld by the Trustee, on or about 60 days following the completion of each quarter. The first distribution covered production for the five-month period from January 1, 2011 to May 31, 2011. The remaining distributions each cover production for a three-month period. The amount of Trust revenues and cash distributions to Trust unitholders depends on:

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

· oil, NGL and natural gas prices received;

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

· amounts realized and paid under the derivatives agreement;

· 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 7,000,000 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. 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”). On June 30, 2014, which is the end of the fourth full calendar quarter following SandRidge’s satisfaction of its drilling obligation with respect to the Trust Development Wells, the subordinated units will automatically convert into common units on a one-for-one basis and SandRidge’s right to receive incentive distributions will terminate. Distributions made to common units in respect of subsequent periods will no longer have the protection of the Subordination Threshold, and all Trust unitholders will share on a pro rata basis in the Trust’s distributions.

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

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

2013
Fourth quarter(3)	$	0.609	$	0.913

2014
First quarter	0.621		0.932
Second quarter	0.659		0.988

(1) Due to the timing of the payment of production proceeds to the Trust, each distribution covers production from a three-month period consisting of the first two months of the most recently ended quarter and the final month of the quarter preceding it.

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

(3) A distribution of $0.5003 per common unit was declared on January 30, 2014 and paid on February 28, 2014. Because income available for distribution on the Trust common units was $0.5003 per unit, which was below the Subordination Threshold of $0.6088 for the period, no distribution was paid on the subordinated units for the period. See Note 8 to the financial statements contained in Item 8 of this report for further discussion.

If at any time the Trust’s cash on hand (including available cash reserves) is not sufficient to pay the Trust’s ordinary course administrative expenses as they become due, the Trust may borrow funds from the Trustee or other lenders, including SandRidge, to pay such expenses. The Trustee does not intend to lend funds to the Trust. If such funds are borrowed, no further distributions will be made to unitholders (except in respect of any previously determined quarterly distribution amount) until the borrowed funds have been repaid.

Properties

As of December 31, 2013, the Trust’s properties consisted of Royalty Interests in (a) the Initial Wells and (b) 121 additional wells (equivalent to approximately 124 Trust Development Wells under the development agreement) that were drilled and perforated for completion between December 31, 2010 and June 30, 2013. The following table presents the number of Initial Wells, Trust Development Wells drilled and Trust Development Wells to be drilled at the dates shown.

	Initial Wells	Trust Development Wells Drilled(1)	Trust Development Wells To Be Drilled	Total
December 31, 2013	37	124	—	161
December 31, 2012	37	107	16	160
December 31, 2011	37	53	70	160

(1) SandRidge was credited for having drilled one full Trust Development Well if a well was drilled and perforated for completion with a minimum perforated length of 2,500 feet and SandRidge’s net revenue interest in the well is equal to 57.0%. For wells with a perforated length of less than 2,500 feet and for wells in which SandRidge had a net revenue interest greater or less than 57.0%, SandRidge received proportionate credit for such well.

The Royalty Interests are in properties producing from the Mississippian formation in Oklahoma. The Mississippian formation is an expansive carbonate hydrocarbon system located on the Anadarko Shelf in northern Oklahoma and Kansas. The top of the formation is encountered between 4,000 and 7,000 feet and lies stratigraphically between the Pennsylvanian-aged Morrow formation and the Devonian-aged Woodford Shale formation. The Mississippian formation can reach 1,000 feet in gross thickness and the targeted porosity zone is between 50 and 100 feet in thickness.

Proved Reserves

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

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

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

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

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

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

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

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

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

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

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

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

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

Cawley, Gillespie & Associates, Inc. (“Cawley Gillespie”)

· more than 26 years of practical experience in petroleum engineering and more than 24 years estimating and evaluating reserve information;

· a registered professional engineer in the state of Texas; and

· a Bachelor of Science Degree in Petroleum Engineering.

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

· more than 15 and 25 years of practical experience in petroleum engineering and over 10 and 20 years estimating and evaluating reserve information, respectively;

· (i) one professional geoscientist registered in the state of Texas and (ii) one professional engineer registered in the states of Texas and Louisiana, respectively; and

· (i) Bachelor of Science Degree in Geology and Master of Science Degree in Geology and (ii) Bachelor of Science Degree in Civil Engineering and Master’s Degree in Business Administration, respectively.

Reporting of Natural Gas Liquids. Natural gas liquids, or NGLs, are produced as a result of the processing of a portion of the Trust’s natural gas production stream. At December 31, 2013, NGLs comprised approximately 20% of the Trust’s total proved reserves on a barrel equivalent basis and represented volumes to be produced from properties where contracts are in place for the extraction and separate sale of NGLs. NGLs are products sold by the gallon. In reporting proved reserves and production of NGLs, production and reserves have been included in barrels. The extraction of NGLs in the processing of natural gas reduces the volume of natural gas available for sale. All production information related to natural gas is reported net of the effect of any reduction in natural gas volumes resulting from the processing and extraction of NGLs.

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

	December 31,
Estimated Proved Reserves(1)	2013		2012		2011
Developed
Oil (MBbls)	2,201.4		2,943.1		5,012.5
NGL (MBbls)	1,979.3		1,946.0		—
Natural gas (MMcf)	34,713.6		48,829.4		43,550.2
Total proved developed (MBoe)	9,966.3		13,027.3		12,270.9
Undeveloped
Oil (MBbls)	—		381.1		3,302.4
NGL (MBbls)	—		195.9		—
Natural gas (MMcf)	—		3,949.7		22,703.5
Total proved undeveloped (MBoe)	—		1,235.3		7,086.3
Total Proved
Oil (MBbls)	2,201.4		3,324.2		8,314.9
NGL (MBbls)	1,979.3		2,141.9		—
Natural gas (MMcf)	34,713.6		52,779.1		66,253.7
Total proved (MBoe)	9,966.3		14,262.6		19,357.2
PV-10 (in millions)(2)	$	174.4	$	234.3	$	508.3
Standardized Measure of Discounted Net Cash Flows (in millions)(2)	$	174.4	$	234.3	$	508.3

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

	Weighted average wellhead prices						Index prices
	Oil (per Bbl)		NGL (per Bbl)		Natural gas (per Mcf)		Oil (per Bbl)		Natural gas (per Mcf)
December 31, 2013	$	94.13	$	30.69	$	3.10	$	93.42	$	3.67
December 31, 2012	$	90.57	$	30.70	$	2.26	$	91.21	$	2.76
December 31, 2011	$	91.21	—		$	4.12	$	92.71	$	4.12

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

Proved reserves are those quantities of oil, NGLs and natural gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for estimation. To be classified as proved reserves, the project to extract the oil or natural gas must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

The area of a reservoir considered proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty.

Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty.

Reserves that can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir, or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. In determining the amount of proved reserves, the price used must be the average price during the 12-month period prior to the ending date of the period covered by the reserve report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved Undeveloped Reserves. During 2013, SandRidge drilled approximately 15 and completed two Trust Development Wells, resulting in the conversion of approximately 0.9 MMBoe of proved undeveloped reserves to proved developed reserves. At December 31, 2013, all of these wells were classified as proved developed producing properties. Additionally, proved undeveloped reserves decreased by approximately 0.3 MMBoe as a result of downward revisions due to well performance.

During 2012, SandRidge drilled 54 Trust Development Wells, resulting in the conversion of approximately 2.6 MMBoe of proved undeveloped reserves to proved developed reserves. At December 31, 2012, all 54 of these wells were classified as proved developed producing properties. Additionally, proved undeveloped reserves decreased by approximately 3.3 MMBoe as a result of downward revisions due to pricing and well performance during 2012 as additional information was obtained through the continued horizontal development of and production from the Mississippian formation during the period.

On April 12, 2011, royalty interests in Trust Development Wells were conveyed to the Trust. At that time, there were a total of 12.4 MMBoe of proved reserves associated with the Royalty Interests in such Trust Development Wells. By December 31, 2011, SandRidge had drilled 29 Trust Development Wells on proved undeveloped locations, resulting in the conversion of approximately 2.4MMBoe of proved undeveloped reserves to proved developed reserves. At December 31, 2011, 28 of these wells were classified as proved developed producing properties with the remaining well still in progress. In addition, there were four wells that were drilled yet to be classified as Trust Development Wells, resulting in the conversion of approximately 0.4 MMBoe of proved undeveloped reserves.

Under the terms of the development agreement, SandRidge was obligated to drill, or cause to be drilled, the Trust Development Wells by December 31, 2015. SandRidge fulfilled its drilling obligations to the Trust in April 2013. The Trust did not bear any costs associated with drilling the Trust Development Wells.

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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 each of the periods indicated.

	Year Ended December 31,
	2013(1)		2012(2)		2011(3)
Production Data
Oil (MBbls)(4)	513		665		444
Natural gas (MMcf)	5,551		5,918		3,388
Combined equivalent volumes (MBoe)	1,439		1,651		1,009
Average daily combined equivalent volumes (MBoe/d)	3.9		4.5		4.2
Average Prices
Oil (per Bbl)(4)	$	87.41	$	90.03	$	90.16
Natural gas (per Mcf)	$	3.71	$	3.23	$	4.69
Combined equivalent (per Boe)	$	45.50	$	47.83	$	55.43
Average Prices — including impact of derivative settlements and post-production expenses
Oil (per Bbl)(4)(5)	$	94.74	$	96.35	$	92.59
Natural gas (per Mcf)(5)	$	3.23	$	3.83	$	4.32
Combined equivalent (per Boe)	$	46.27	$	52.51	$	55.26
Expenses (per Boe)
Post-production	$	2.14	$	1.99	$	1.73
Production taxes	$	0.69	$	0.49	$	0.57
Total expenses	$	2.83	$	2.48	$	2.30

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

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

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

(4) Includes NGLs, which comprised approximately 1.4%, 0.1% and 0.0% of total production in 2013, 2012 and 2011, respectively.

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

Productive Wells

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

Oil

Natural Gas

Total

Gross

Net

Gross

Net

Gross

Net

Productive Wells

158

54.2

—

158

54.2

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Developed and Undeveloped Acreage

As of April 2013, SandRidge had drilled and perforated for completion approximately 124 equivalent Trust Development Wells, thus fulfilling its drilling obligation. Accordingly, the AMI terminated effective April 2013, and no additional wells will be drilled for the Trust.

Drilling Activity

The following table sets forth information with respect to wells completed within the AMI and subject to the Royalty Interests during each of the periods indicated. The information presented is not necessarily indicative of future performance, and should not be interpreted to present any correlation between the number of productive wells drilled and quantities or economic value of reserves found. Productive wells are those that produce commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return. Gross wells refer to the total number of wells in which the Trust had a royalty interest and net wells refer to gross wells multiplied by the Trust’s weighted average royalty interest percentage. SandRidge completed its drilling obligation to the Trust during the second quarter of 2013. As such, there were no wells subject to the Royalty Interests drilling or awaiting completion at December 31, 2013.

	2013						2012						2011(1)
	Gross	Percent		Net	Percent		Gross	Percent		Net	Percent		Gross	Percent		Net	Percent
Completed Wells
Development
Productive	19	100	%	5.0	100	%	57	100	%	15.7	100	%	35	100	%	11.5	100	%
Dry	—	0	%	—	0	%	—	0	%	—	0	%	—	0	%	—	0	%
Total	19	100	%	5.0	100	%	57	100	%	15.7	100	%	35	100	%	11.5	100	%
Exploratory
Productive	—	0	%	—	0	%	—	0	%	—	0	%	—	0	%	—	0	%
Dry	—	0	%	—	0	%	—	0	%	—	0	%	—	0	%	—	0	%
Total	—	0	%	—	0	%	—	0	%	—	0	%	—	0	%	—	0	%
Total
Productive	19	100	%	5.0	100	%	57	100	%	15.7	100	%	35	100	%	11.5	100	%
Dry	—	0	%	—	0	%	—	0	%	—	0	%	—	0	%	—	0	%
	19	100.0	%	5.0	100.0	%	57	100	%	15.7	100	%	35	100	%	11.5	100	%

(1) Represents wells completed within the AMI and subject to the Royalty Interests during the period from April 12, 2011, the date of the Royalty Interests conveyance, to December 31, 2011.

Marketing and Customers

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

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

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	2013
	Sales		% of Revenue
	(in thousands)
Plains All American, Inc.	$	27,394	41.9	%
Atlas Pipeline Mid-Continent Westok, LLC	$	22,772	34.8	%
Sunoco, Inc.	$	8,264	12.6	%

	2012
	Sales		% of Revenue
	(in thousands)
Sunoco, Inc.	$	20,966	26.5	%
Atlas Pipeline Mid-Continent Westok, LLC	$	19,024	24.1	%
Gavilon, LLC	$	18,275	23.1	%

	2011
	Sales		% of Revenue
	(in thousands)
Atlas Pipeline Mid-Continent Westok, LLC	$	15,501	27.7	%
Sunoco, Inc.	$	15,041	26.9	%
Shell Trading (US) Company	$	12,833	23.0	%
Gavilon, LLC	$	7,573	13.5	%

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. SandRidge acquired its interests in the Underlying Properties 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 to SandRidge by the lessee who originally obtained leases from the mineral owner, through farmout agreements that grant SandRidge 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 by SandRidge.

Competition and Markets

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

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

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

Seasonal Nature of Business

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

Insurance

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

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

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

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

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

Regulation

Oil and Natural Gas Regulations. The oil and natural gas industry is extensively regulated by numerous federal, state, local and regional authorities, as well as Native American tribes. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, and Native American tribes are authorized by statute to issue rules and regulations affecting the oil and natural gas industry and its individual members, some of which carry substantial penalties for noncompliance. Although the regulatory burden on the oil and natural gas industry increases the cost of doing business and, consequently, affects it profitability, these burdens generally do not affect SandRidge any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production. The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.

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

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

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

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure of decommissioning of production facilities and pipelines, and for site restorations, in areas where the Underlying Properties are located. For example, the United States Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration.

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

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

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

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

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

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

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

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

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

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

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

Endangered Species. The federal Endangered Species Act (‘‘ESA’’) restricts activities that may affect endangered or threatened species or their habitats. Operations of the Underlying Properties are in substantial compliance with the ESA. If endangered species are located in areas of the Underlying Properties where seismic surveys, development activities or abandonment operations may be conducted, the work could be prohibited or delayed or expensive mitigation may be required. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia on September 9, 2011, the U.S. Fish and Wildlife Service is required to consider listing more than 250 species as endangered under the ESA. Under the September 9, 2011 settlement, the federal agency is required to make a determination on listing of the species as endangered or threatened over the six-year period ending with the agency’s 2017 fiscal year. As a part of this settlement, on December 11, 2012, the Fish and Wildlife Service proposed to list the lesser prairie-chicken as threatened throughout its five-state range of New Mexico, Colorado, Texas, Oklahoma and Kansas. The final listing determination will be made no later than March 30, 2014. Parts of Oklahoma affected by this determination include areas where some of the Underlying Properties are located. The designation of previously unprotected species as threatened or endangered in areas where the Underlying Properties operations are located could cause SandRidge to incur increased costs arising from species protection measures or could result in limitations on exploration and production activities that could have an adverse impact on the ability to develop and produce reserves from the Underlying Properties. SandRidge is an active participant on various agency and industry committees that are developing or addressing various ESA and other federal and state agency programs to minimize potential impacts to its business and the Underlying Properties.

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

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

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

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Glossary of Oil and Natural Gas Terms

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

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

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

Boe/d. Barrels of oil equivalent per day.

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

Collars. Contain a fixed floor price (put) and a fixed ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, the Trust receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due.

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

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

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

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

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

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

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

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

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

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

MBbls. Thousand barrels of oil or other liquid hydrocarbons.

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

MBoe. Thousand barrels of oil equivalent.

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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.

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

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

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

Production costs.

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

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

(B) Repairs and maintenance.

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

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

(E) Severance taxes.

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

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

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

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

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Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir, or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

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

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

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

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

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

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

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

Undeveloped oil, NGL and natural gas reserves. Reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

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

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

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

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

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Item 1A. Risk Factors

Risks Related to the Units

Producing oil and natural gas from the Underlying Properties is a high risk activity with many uncertainties that could adversely affect future production from the Underlying Properties. Any such reductions in production could decrease cash that is available for distribution to unitholders.

Production operations on the Underlying Properties may be curtailed, delayed or canceled as a result of various factors, including the following:

· unusual or unexpected geological formations and miscalculations;

· equipment malfunctions, failures or accidents;

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

· lack of available capacity on interconnecting transmission pipelines;

· unexpected operational events;

· pipe or cement failures and casing collapses;

· pressures, fires, blowouts and explosions;

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

· natural disasters;

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

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

· reductions in oil and natural gas prices; and

· market limitations for oil and natural gas.

In the event that 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.

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

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

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

· the price of foreign imports;

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

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

· weather conditions and seasonal trends;

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

· technological advances affecting energy consumption and energy supply;

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

· natural disasters and other acts of force majeure;

· domestic and foreign governmental regulations and taxation;

· energy conservation and environmental measures; and

· the price and availability of alternative fuels.

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

Lower oil, NGL and natural gas prices will reduce proceeds to which the Trust is entitled and may ultimately reduce the amount of oil, NGLs and natural gas that is economic to produce from the Underlying Properties. As a result, SandRidge or any third-party operator of any of the Underlying Properties could determine during periods of low oil, NGL or natural gas prices to shut in or curtail production from wells on the Underlying Properties. In addition, the operator of the Underlying Properties could determine during periods of low oil, NGL or natural gas prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, SandRidge or any third-party operator may abandon, at its cost, any well or property if it reasonably believes that the well or property can no longer produce oil, NGLs and natural gas in commercially economic quantities. This could result in termination of the portion of the Royalty Interest relating to the abandoned well or property, and SandRidge would have no obligation to drill a replacement well. For a discussion of certain risks related to the Trust’s hedging arrangements, see ‘‘—The hedging arrangements for the Trust may not cover all of the production attributable to the Trust, and such contracts limit the Trust’s ability to benefit from commodity price increases for hedged volumes above the corresponding hedge price.’’

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

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

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

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

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

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

· the assumed effect of governmental regulation.

Changes in these assumptions or actual production costs incurred and results of actual development could materially decrease reserve estimates. Estimates of reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes, and other factors.

Reserve estimates for fields that do not have a lengthy production history are less reliable than estimates for fields with lengthy production histories. Less production history may contribute to less accurate estimates of reserves, future production rates and the timing of development expenditures. Of the 37 Initial Wells and 124 Trust Development Wells drilled through December 31, 2013, most have been operational for less than two years and estimated reserves vary substantially from well to well and are not directly correlated to perforated lateral length or completion technique. Although SandRidge and Cawley Gillespie, the independent third-party engineering firm that estimated the Trust’s reserves, analyzed historical production data from vertical wells drilled in the AMI since the 1940s, there can be no assurance that this data can accurately predict future production from horizontal wells. The lack of operational history for horizontal wells in the Mississippian formation may also contribute to the inaccuracy of estimates of reserves. A material and adverse variance of actual production, revenues and expenditures from those underlying reserve estimates would have a material adverse effect on the financial condition, results of operations and cash flows of the Trust and would reduce cash distributions to Trust unitholders. As with all horizontal drilling programs, there is a risk that some or all of a horizontal well could miss the target reservoir. As a result, the Trust may not receive the benefit of the total amount of reserves reflected in the reserve report, notwithstanding the fact that SandRidge has satisfied its drilling obligation.

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

If oil or natural gas prices rise, the Trust may be obligated to make cash payments to SandRidge which could, in certain circumstances, be significant. Swap contracts underlying the derivatives agreement between SandRidge and the Trust provide the Trust with the right to receive from SandRidge 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 this difference in price multiplied by the volume of production hedged, even if the production attributable to the Trust’s Royalty Interests is insufficient to cover the volume of production specified in the applicable hedge contracts. For example, if (a) the oil production attributable to the Royalty Interests in 2014 were to be less than 541 Mbls (the amount of oil production hedged in 2014) and (b) the market price for such production were to be higher than $98.90 or $101.75 (the prices fixed by the hedges for production in 2014), then the Trust would be obligated to pay the difference in price multiplied by the difference in production. Accordingly, if the production attributable to the Trust’s 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 may have insufficient offsetting cash receipts from the sale of production attributable to the Royalty Interests. The most recent reserve report estimates 2014 oil production of 259 MBbls, which is 282 MBbls less than the amount hedged in 2014. 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 to SandRidge under the derivatives agreement. In any of these events, the Trust’s liquidity and cash available for distribution may be adversely affected.

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

The target distributions, Subordination Thresholds and Incentive Thresholds, as set forth in the Prospectus and described below in Part II Item 7, Trustee’s Discussion and Analysis of Financial Conditions and Results of Operations, were based on SandRidge’s calculations, and SandRidge did not receive an opinion or report on such calculations from any independent accountants, financial advisers, or engineers. Such calculations were based on assumptions made in early 2011 about drilling, production, oil and natural gas prices, hedging activities, capital expenditures, expenses, tax rates and production tax credits under state law, the location of Trust Development Wells and other matters that were inherently uncertain and were subject to significant business, economic, financial, legal, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from the target. For example, the targets have assumed that oil and natural gas production would be sold at prices consistent with settled NYMEX prices for January, February and March 2011 and monthly NYMEX forward pricing as of March 18, 2011 for the remainder of the period ending December 31, 2013, and assumed price increases after December 31, 2013 of 2.5% annually, capped at $120.00 per Bbl of oil in 2025 and $7.00 per MMBtu of natural gas in 2022, respectively. However, actual sales prices may be significantly lower. Additionally, these estimates assumed that the Trust Development Wells would be drilled on SandRidge’s anticipated drilling schedule. However, SandRidge has fulfilled its drilling obligations to the Trust ahead of schedule, and no additional wells will be drilled. 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 “—Producing oil and natural gas from the Underlying Properties is a high risk activity with many uncertainties that could adversely affect future production from the Underlying Properties. Any such reductions in production could decrease cash that is available for distribution to unitholders.”

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

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

Through the distribution for the second quarter of 2014, 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

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Threshold for such quarter (which is 20% below the target distribution level for the corresponding quarter). However, the subordinated units constitute only a 25% interest in the Trust, and the subordination feature does not guarantee that common units will receive a distribution equal to the Subordination Threshold, or any distribution at all. Additionally, at the end of the second quarter of 2014 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. 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, as occurred in the first quarter of 2014.

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

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

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

· evacuation of personnel and curtailment of operations;

· weather-related damage to facilities, resulting in suspension of operations;

· inability to deliver materials to worksites; and

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

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

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

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

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

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

Trust unitholders have no voting rights with respect to SandRidge and, therefore, have no managerial, contractual or other ability to influence SandRidge’s activities or operations of the Underlying Properties. In addition, some of the Trust Development Wells may, at some point, be operated by third parties unrelated to SandRidge. Such third-party operators may not have the operational expertise of SandRidge. Oil and natural gas properties are typically managed pursuant to an operating agreement among the working interest owners in the properties. The typical operating agreement contains procedures whereby the owners of the aggregate working interest in the property designate one of the interest owners to be the operator of the property. Under these

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arrangements, the operator is typically responsible for making all decisions relating to drilling activities, sale of production, compliance with regulatory requirements and other matters that affect the property. The failure of an operator to adequately perform operations could reduce production from the Underlying Properties and cash available for distribution to unitholders. Neither the Trustee nor the Trust unitholders has any contractual or other ability to influence or control the field operations of, sale of oil and natural gas from, or future development of, the Underlying Properties.

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

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

Future maintenance may affect the quantity of proved reserves that can be economically produced from the Underlying Properties to which the wells relate. The timing and size of these projects will depend on, among other factors, the market prices of oil, NGLs and natural gas. 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 any activity reasonably related to such ownership, 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 depends on a variety of factors, including discounts based on the quality and location of hydrocarbons produced, Btu content and post-production costs. These factors can cause differentials to be volatile from period to period. Sellers of production have little or no control over the factors that determine the amount of the differential, and cannot accurately predict differentials for natural gas or crude oil. Increases in the differential between the realized price of oil or natural gas and the benchmark price for oil or natural gas could reduce the proceeds to the Trust and therefore the cash distributions made by the Trust and the value of the Trust units. The target distributions were prepared (a) for natural gas using an assumed negative differential of 19% from NYMEX futures prices for natural gas, and (b) for oil using an assumed negative differential of $5.00 per barrel from NYMEX futures prices for oil.

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

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

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

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

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

· any amounts owed to counterparties under the hedging contracts underlying the derivatives agreement.

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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. SandRidge’s right to incentive distributions will remain in effect through the distribution for the second quarter of 2014, and will then terminate.

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. See Item 3 of this report for a description of the impact of legal proceedings on the Trust’s administrative expenses.

The hedging arrangements for the Trust may not cover all 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.

Pursuant to the derivatives agreement, SandRidge has provided the Trust with the effect of certain oil and natural gas hedging contracts that it has entered into with third parties. The derivatives agreement may not cover all of the oil and natural gas production attributable to the Royalty Interests, and will terminate after December 31, 2015. The Trust’s receipt of any payments due to it based on the derivatives agreement depends upon the financial position of SandRidge and SandRidge’s hedge contract counterparties. A default by SandRidge or any of the hedge contract counterparties could reduce the amount of cash available for distribution to the Trust unitholders. See “—SandRidge’s ability to satisfy its obligations to the Trust depends on its financial position, and in the event of a default by SandRidge in its obligation to drill the Trust Development Wells, or in the event of SandRidge’s bankruptcy, it may be expensive and time-consuming for the Trust to exercise its remedies.”

No production after December 31, 2015 will be hedged to protect against the price risks inherent in holding interests in oil and natural gas, 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 and natural gas prices above the hedge price on the portion of the production attributable to the Royalty Interests that is hedged. See “—In certain circumstances the Trust may have to make cash payments under the derivatives agreement and these payments could be significant.” The Trust does not have any ability to terminate the hedging contracts.

The Trust’s counterparty under the derivatives agreement is SandRidge, whose counterparties are Deutsche Bank AG London Branch, Credit Suisse Energy, LLC, and Royal Bank of Canada. In the event that any of the counterparties to the oil and natural gas hedging 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 and natural gas 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 counterparties. The Trust has no ability to enter into its own hedges.

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

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

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

The trust agreement permits the Trustee and the Trust to sue SandRidge or any other future owner of the Underlying Properties to enforce the terms of the conveyances creating the Royalty Interests. If the Trustee does not take appropriate action to enforce provisions of these conveyances, a Trust unitholder’s recourse would be limited to bringing a lawsuit against the Trustee to compel the Trustee to take specified actions. The trust agreement expressly limits a Trust unitholder’s ability to directly sue SandRidge or any other party other than the Trustee. As a result, Trust unitholders will not be able to sue SandRidge or any future owner of the

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Underlying Properties to enforce the Trust’s rights under the conveyances. Furthermore, the Royalty Interest conveyances provide that, except as set forth in the conveyances, SandRidge will not be liable to the Trust for the manner in which it performs its duties in operating the Underlying Properties as long as it acts in good faith and, to the fullest extent permitted by law, will owe no fiduciary duties to the Trust or the unitholders.

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

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

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

As of March 7, 2014, SandRidge, through SandRidge E&P, owned an aggregate of 528,063 common units and 7,000,000 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. During 2012, SandRidge sold an aggregate of 3,221,937 common units in three separate transactions under 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. On October 24, 2012, pursuant to the registration rights agreement, the Trust and SandRidge filed a registration statement on Form S-3 registering the offering by SandRidge Exploration and Production, LLC of 528,063 common units. The registration statement was declared effective on November 7, 2012. To date no units have been sold pursuant to the registration statement.

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

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

· Notwithstanding its fulfillment of its drilling obligation to the Trust, SandRidge’s interests may conflict with those of the Trust and the Trust unitholders in situations involving the 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. 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.

· 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 Mississippian formation or its creditworthiness.

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

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

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

In addition, SandRidge has agreed that, if at any time the Trust’s cash on hand (including available cash reserves) is not sufficient to pay the Trust’s ordinary course administrative expenses as they become due, SandRidge will loan funds to the Trust necessary to pay such expenses. Any such loan will be on an unsecured basis, and the terms of such loan will be substantially the same as those which would be obtained in an arms’ length transaction between SandRidge and an unaffiliated third party. If SandRidge provides such funds to the Trust, it would become a creditor of the Trust and its interests as a creditor could conflict with the interests of unitholders.

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SandRidge may sell all or a portion of the Underlying Properties, subject to and burdened by the Royalty Interests; 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.

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

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

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

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

Oil and natural gas 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. Additionally, there has been a variety of regulatory initiatives at the federal and state levels to further regulate oil and natural gas operations in certain locations. Any increased regulation or suspension of oil and natural gas operations, or revision or reinterpretation of existing laws and regulation, could result in delays and higher operating costs. Such costs or significant delays could have a material adverse effect on the operation of the Underlying Properties, which in turn could negatively impact Trust distributions, estimated and actual future net revenues to the Trust and estimates of reserves attributable to the Trust’s interests.

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

New laws or regulations, or changes to existing laws or regulations may unfavorably impact SandRidge, could result in increased operating costs and could have a material adverse effect on SandRidge’s financial condition and results of operations.

Additionally, federal and state regulatory authorities may expand or alter applicable pipeline safety laws and regulations, compliance with which may require increased capital costs on the part of SandRidge and third-party downstream oil, NGL 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.

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

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

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

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly construction, drilling, water management, completion, waste handling, storage, transport, disposal or cleanup requirements could require significant expenditures by SandRidge or other operators of the Underlying Properties 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 or such other operator. SandRidge or such other operator may not be able to recover some or any of these costs from insurance.

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

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

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

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

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

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

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

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.

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

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

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

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

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

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

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

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

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

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

If a unitholder sells its Trust units, the unitholder will recognize a gain or loss equal to the difference between the amount realized and the unitholder’s tax basis in those Trust units. Because distributions in excess of a unitholder’s allocable share of the Trust’s net taxable income decrease the unitholder’s tax basis in its Trust units, the amount, if any, of such prior excess distributions with respect to the Trust units unitholders sell will, in effect, become taxable income to unitholders if unitholders sell such Trust units

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at a price greater than the unitholder’s tax basis in those Trust units, even if the price the unitholder receives is less than the unitholder’s original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depletion recapture.

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

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

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

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

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

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

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

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

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

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

The U.S. federal income tax consequences of the ownership and disposition of Trust units will depend in part on the Trust’s estimates of the relative fair market values, and the initial tax bases of the Trust’s assets. Although the Trust may from time to time consult with professional appraisers regarding valuation matters, the Trust will make many of the relative fair market value estimates itself. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the

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estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by Trust unitholders might change, and Trust unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

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

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

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

The Obama administration’s budget proposals in recent years, including the budget proposal for fiscal year 2014, have included provisions eliminating certain key U.S. federal income tax preferences currently available to oil and gas exploration and production activities. Specifically, the 2014 budget proposes to repeal the percentage depletion allowance for oil and gas properties, including the Royalty Interests that are perpetual, in which case only cost depletion would be available. If this proposal were enacted into law, it could negatively impact the value of the Trust units.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

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

Item 3. Legal Proceedings

The Trust has been named as an additional defendant in a putative class action against SandRidge Energy, Inc. (“SandRidge”) and others as described below.

On December 5, 2012, James Glitz and Rodger A. Thornberry, on behalf of themselves and all other similarly situated stockholders, filed a putative class action complaint in the U.S. District Court for the Western District of Oklahoma against SandRidge and certain current and former executive officers of SandRidge. On January 4, 2013, Louis Carbone, on behalf of himself and all other similarly situated stockholders, filed a substantially similar putative class action complaint in the same court and against the same defendants. On March 6, 2013, the court consolidated these two actions under the caption “In re SandRidge Energy, Inc. Securities Litigation” (the “Securities Litigation”) and appointed a lead plaintiff and lead counsel.

On July 23, 2013, the lead plaintiff filed a consolidated amended complaint, in which the Trust was named as an additional defendant. The Consolidated Amended Complaint asserts a variety of federal securities claims against the Trust and SandRidge and certain of its current and former officers and directors, among other defendants, on behalf of a putative class of (a) purchasers of SandRidge common stock during the period from February 24, 2011 to November 8, 2012, (b) purchasers of common units of the Trust in or traceable to its initial public offering on or about April 12, 2011, and (c) purchasers of common units of SandRidge Mississippian Trust II in or traceable to its initial public offering on or about April 23, 2012. The claims are based on allegations that SandRidge and certain of its current and former officers and directors, among other defendants, including the Trust with respect to certain of the allegations, are responsible for making false and misleading statements, and omitting material information, concerning a variety of subjects, including oil and gas reserves, SandRidge’s capital expenditures, and certain transactions entered into by companies allegedly affiliated with SandRidge’s former CEO Tom Ward. The plaintiffs seek class certification, an order rescinding the Trust’s initial public offering and an unspecified amount of damages, plus interest, attorneys’ fees and costs. The complaint was corrected by way of a Corrected Consolidated Amended Complaint filed on July 30, 2013.

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The Trust and SandRidge have each filed a Motion to Dismiss the claims asserted against the Trust in the Corrected Consolidated Amended Complaint, which are pending before the court.

Regardless of the outcome of the litigation, the Trust will incur expenses in defending the litigation, and the expenses may increase the Trust’s administrative expenses significantly. The Trust will estimate and provide for potential losses that may arise out of litigation to the extent that such losses are probable and can be reasonably estimated. Significant judgment will be required in making any such estimates and any final liabilities of the Trust may ultimately be materially different than any estimates. The Trust is currently unable to assess the probability of loss or estimate a range of any potential loss the Trust may incur in connection with the Securities Litigation, and has not established any reserves relating to the Securities Litigation. The Trust may withhold estimated amounts from future distributions to cover future costs associated with the litigation if determined necessary. The Trust has not yet fully analyzed any rights it may have to indemnities that may be applicable or any claims it may make in connection with the Securities Litigation.

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

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

The Trust units are listed on the New York Stock Exchange (“NYSE”) under the symbol “SDT”. 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:

					Distributions Per Unit
	High		Low		Common		Subordinated
Calendar Quarter 2013
First Quarter	$	19.85	$	12.14	$	0.6507	$	0.6507
Second Quarter	$	15.14	$	12.51	$	0.5904	$	0.5015
Third Quarter	$	14.85	$	11.67	$	0.6112	$	0.5835
Fourth Quarter	$	14.60	$	8.65	$	0.6029	$	0.0000

Calendar Quarter 2012
First Quarter	$	36.97	$	28.25	$	0.7909	$	0.7909
Second Quarter	$	33.11	$	23.79	$	0.7870	$	0.7870
Third Quarter	$	29.43	$	24.43	$	0.7277	$	0.7277
Fourth Quarter	$	24.90	$	14.68	$	0.6831	$	0.6831

On March 7, 2014, there were eight record unitholders of the Trust’s common units.

Distributions

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 2013.

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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,
	2013		2012		2011

Total revenues	$	69,642	$	89,998	$	57,515
Distributable income	$	63,710	$	83,684	$	52,800

Distributable income per common unit (21,000,000 units issued and outstanding)	$	2.4552	$	2.9887	$	1.8857
Distributable income per subordinated unit (7,000,000 units issued and outstanding)	$	1.7357	$	2.9887	$	1.8857

	As of December 31,
	2013		2012		2011
Total assets	$	235,959	$	260,887	$	286,456
Trust corpus	$	235,959	$	260,887	$	286,456

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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 Years Ended December 31, 2013, 2012 and 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. Royalty income, post-production expenses, certain taxes and derivative settlements are recorded on a cash basis when net revenue distributions are received by the Trust from SandRidge. Although the Trust was formed on December 30, 2010, the conveyance of the Royalty Interests did not occur until April 12, 2011, with an effective date of January 1, 2011, and no proceeds were received from SandRidge until August 2011. As a result, the Trust did not recognize any income or make any distributions during the first two calendar quarters of 2011. Information regarding the Trust’s revenues, expenses, production and pricing for the years ended December 31, 2013, 2012 and 2011 is presented below.

	Year Ended December 31,
	2013(1)		2012(2)			2011(3)

Production data
Oil (MBbl)(4)	513		665			444
Natural gas (MMcf)	5,551		5,918			3,388
Combined equivalent volumes (MBoe)	1,439		1,651			1,009
Average daily combined equivalent volumes (MBoe/d)	3.9		4.5			4.2

Well data
Initial and Trust Development Wells producing — average	149		100			54

Revenues (in thousands)
Royalty income	$	65,455	$	78,985		$	55,937
Derivative settlements	4,187		11,013			1,578
Total revenue	$	69,642	$	89,998		$	57,515

Expenses (in thousands)
Post-production expenses	$	3,076	$	3,285		$	1,749
Production taxes	987		806			570
Trust administrative expenses	1,346		1,493			643
Cash reserves withheld (used) for current Trust expenses, net of amounts (used) withheld	523		(190		)	1,312
Total expenses	$	5,932	$	5,394		$	4,274
Income available for distribution prior to incentive calculation	63,710		84,604			53,241
Less: Incentive distribution to SandRidge	—		920			441
Distributable income available to unitholders	$	63,710	$	83,684		$	52,800

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	Year Ended December 31,
	2013(1)		2012(2)		2011(3)
Average prices
Oil (per Bbl)(4)	$	87.41	$	90.03	$	90.16
Natural gas (per Mcf)	$	3.71	$	3.23	$	4.69
Combined equivalent (per Boe)	$	45.50	$	47.83	$	55.43

Average prices — including impact of derivative settlements and post-production expenses
Oil (per Bbl)(4)(5)	$	94.74	$	96.35	$	92.59
Natural gas (per Mcf)	$	3.23	$	3.83	$	4.32
Combined equivalent (per Boe)	$	46.27	$	52.51	$	55.26

Expenses (per Boe)
Post-production	$	2.14	$	1.99	$	1.73
Production taxes	$	0.69	$	0.49	$	0.57

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

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

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

(4) Includes NGLs, which comprised approximately 1.4%, 0.1% and 0.0% of total production in 2013, 2012 and 2011, respectively.

Comparison of Results of the Trust for the Years Ended December 31, 2013 and 2012

Revenues

Royalty Income. Royalty income received during the year ended December 31, 2013 totaled $65.5 million compared to $79.0 million received during the year ended December 31, 2012. The decrease in royalty income is primarily attributable to the decrease in combined equivalent volumes produced as production from Trust Development Wells completed and brought on production during 2013 was more than offset by natural declines in production from the Initial Wells and older Trust Development Wells. Net revenue distributions received from SandRidge by the Trust during the year ended December 31, 2013 included royalty income attributable to production for the twelve-month period from September 1, 2012 to August 31, 2013 of 513 MBbls of oil and 5,551 MMcf of natural gas. Net revenue distributions received from SandRidge by the Trust during the year ended December 31, 2012 included royalty income attributable to production for the twelve-month period from September 1, 2011 to August 31, 2012 of 665 MBbls of oil and 5,918 MMcf of natural gas. Also contributing to the decrease in royalty income was a decrease in the average price received for oil production. Average prices received for oil production, excluding the impact of derivative settlements and post-production expenses, during the year ended December 31, 2013 were $87.41 per Bbl of oil compared to $90.03 per Bbl of oil during the year ended December 31, 2012. The decreases in total production and the average price received for oil production were slightly offset by an increase in the average price received for natural gas production, excluding the impact of derivative settlements and post-production expenses, to $3.71 per Mcf during the year ended December 31, 2013 from $3.23 per Mcf during the year ended December 31, 2012.

Derivative Settlements. The Trust’s derivatives agreement with SandRidge is intended to reduce the Trust’s exposure to commodity price volatility attributable to a portion of production from the Royalty Interests through December 31, 2015 by the use of oil fixed price swaps and natural gas collars. Additionally, the derivatives agreement contained natural gas fixed price swaps for production from April 2011 through June 30, 2012. Net cash settlements under the derivatives agreement for the year ended December 31, 2013 were approximately $4.2 million ($3.8 million received related to oil fixed price swaps and $0.4 million received related to natural gas collars), which effectively increased the average price received for oil by $7.33 per Bbl to $94.74 per Bbl and increased the average price received for natural gas by $0.07 per Mcf to $3.78 per Mcf ($3.23 per Mcf including the impact of post-production expenses). Net cash settlements received under the derivatives agreement for the year ended December 31, 2012 for production from September 1, 2011 to August 31, 2012 were approximately $11.0 million ($4.2 million received related to oil fixed price swaps, $6.7 million received related to natural gas fixed price swaps and $0.1 million received related to natural gas collars), which effectively increased the average price received for oil by $6.32 per Bbl to $96.35 per Bbl and increased the average price received for natural gas

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by $1.15 per Mcf to $4.38 per Mcf ($3.83 per Mcf including the impact of post-production expenses). Net cash settlements received during 2013 and 2012 were due to lower commodity prices at the time of settlement compared to the contract price of the Trust’s oil fixed price swaps and natural gas collars.

Expenses

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, 2013 totaled approximately $3.1 million or $2.14 per Boe, compared to approximately $3.3 million or $1.99 per Boe, for the year ended December 31, 2012. Post-production expense on a per unit basis increased approximately 8% for the year ended December 31, 2013 from 2012 as natural gas production comprised a larger portion of total production during 2013.

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, 2013 totaled $1.0 million, or $0.69 per Boe, and were approximately 1.5% of royalty income. Production taxes for the year ended December 31, 2012 totaled $0.8 million, or $0.49 per Boe, and were approximately 1.0% of royalty income.

Trust Administrative Expenses. Trust administrative expenses for the year ended December 31, 2013 totaled approximately $1.4 million compared to approximately $1.5 million for the year ended December 31, 2012.

Incentive Distribution to SandRidge

Cash available for distribution during the year ended December 31, 2013 prior to incentive calculations did not exceed Incentive Thresholds for the applicable distribution periods, whereas for the year ended December 31, 2012, cash available for distribution exceeded the Incentive Threshold by approximately $1.8 million ($1.7 million for the February 2012 distribution and $0.1 million for the May 2012 distribution). As the holder of the Trust’s subordinated units, SandRidge received 50% of the amount by which the cash available for distribution exceeded the Incentive Threshold for each distribution, or approximately $0.9 million for the year ended December 31, 2012.

Distributable Income

Distributable income for the year ended December 31, 2013 was $63.7 million, which included a net addition to the cash reserve for the payment of future Trust expenses of approximately $0.5 million (approximately $1.9 million withheld from 2013 cash distributions to unitholders partially offset by approximately $1.4 million used to pay Trust expenses during the period). Distributable income for the year ended December 31, 2012 was $83.7 million, which included a net reduction to the cash reserve for payment of future Trust expenses of approximately $0.2 million (approximately $1.5 million used to pay Trust expenses during the period partially offset by approximately $1.3 million withheld from 2012 cash distributions to unitholders).

Distributions to Common and Subordinated Units. Holders of Trust common units received greater distributions than holders of Trust subordinated units during the year ended December 31, 2013 as a result of the Trust’s subordination provisions. Because income available for distribution on all Trust units for the May 2013 and August 2013 distributions was below the Subordination Threshold, reduced distributions were paid to the subordinated units for those periods. Since income available for distribution on the Trust common units for the November 2013 distribution was below the Subordination Threshold, no distribution was paid to the subordinated units for that period. As a result of the subordination provisions, holders of common units received approximately $3.8 million more in distributions for the year ended December 31, 2013 than such holders would have received had the subordination provisions not existed.

Comparison of Results of the Trust for the Years Ended December 31, 2012 and 2011

Revenues

Royalty Income. Royalty income received during the year ended December 31, 2012 totaled $79.0 million compared to $55.9 million received during the year ended December 31, 2011. The increase in royalty income is primarily attributable to the Trust’s receipt during the 2012 period of net revenue for production covering a twelve-month period compared to its receipt during the 2011 period of net revenue for production covering an eight-month period. Net revenue distributions received from SandRidge by the Trust during the year ended December 31, 2012 included royalty income attributable to production for the twelve-month period from September 1, 2011 to August 31, 2012 of 665 MBbls of oil and 5,918 MMcf of natural gas. Net revenue distributions received from SandRidge by the Trust during the year ended December 31, 2011 included royalty income attributable to production for the eight-month period from January 1, 2011 to August 31, 2011 of 444 MBbls of oil and 3,388 MMcf of natural gas. Additionally, increases in production during 2012 from Trust Development Wells completed during 2012 were partially offset by natural declines in production from the Initial Wells and older Trust Development Wells. During 2012, there was an average of 100 Initial and Trust Development Wells producing compared to 54 during 2011. The overall net increase in production was partially offset by a decrease in the price received for natural gas production, which declined to $3.23 per Mcf during the year ended December 31, 2012 from $4.69 per Mcf during the year ended December 31, 2011.

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Derivative Settlements. Net cash settlements under the derivatives agreement for the year ended December 31, 2012 for production from September 1, 2011 to August 31, 2012 were approximately $11.0 million, which effectively increased the average price received for oil by $6.32 per Bbl to $96.35 per Bbl and increased the average price received for natural gas by $1.15 per Mcf to $4.38 per Mcf ($3.83 per Mcf including the impact of post-production expenses). Net cash settlements under the derivatives agreement for the year ended December 31, 2011 were approximately $1.6 million ($1.1 million received related to oil fixed price swaps and $0.5 million received related to natural gas fixed price swaps), which effectively increased the average price received for oil by $2.43 per Bbl to $92.59 per Bbl and increased the average price received for natural gas by $0.15 per Mcf to $4.84 per Mcf, ($4.32 per Mcf including the impact of post-production expenses). Net cash settlements during 2012 and 2011 were due to lower commodity prices at the time of settlement compared to the contract price of the Trust’s oil and natural gas fixed price swaps and natural gas collars.

Expenses

Post-Production Expenses. Post-production expenses for the year ended December 31, 2012 totaled approximately $3.3 million compared to approximately $1.7 million for the year ended December 31, 2011. Expense for the year ended December 31, 2012 is attributable to twelve months of production compared to eight months of production for the year ended December 31, 2011. Post-production costs per Boe increased approximately 15% for the year ended December 31, 2012 from 2011 as natural gas production comprised a higher percentage of total production during 2012.

Production Taxes. Production taxes for the year ended December 31, 2012 totaled $0.8 million, or $0.49 per Boe, and were approximately 1.0% of royalty income. Production taxes for the year ended December 31, 2011 totaled $0.6 million, or $0.57 per Boe, and were approximately 1.0% of royalty income.

Trust Administrative Expenses. Trust administrative expenses for the year ended December 31, 2012 totaled approximately $1.5 million compared to approximately $0.6 million for the year ended December 31, 2011. Because the Royalty Interests were conveyed to the Trust in April 2011, expense for the year ended December 31, 2011 is attributable to eight months of activity compared to twelve months of activity for the year ended December 31, 2012.

Incentive Distribution to SandRidge

Cash available for distribution during the year ended December 31, 2012 prior to incentive calculations exceeded Incentive Thresholds for the applicable distribution periods by approximately $1.8 million ($1.7 million for the February 2012 distribution and $0.1 million for the May 2012 distribution) compared to approximately $0.9 million (November 2011 distribution) for the year ended December 31, 2011. As the holder of the Trust’s subordinated units, SandRidge received 50% of the amount by which the cash available for distribution exceeded the Incentive Threshold for each distribution, or approximately $0.9 million and $0.4 million for the years ended December 31, 2012 and 2011, respectively.

Distributable Income

Distributable income for the year ended December 31, 2012 was $83.7 million, which included a net reduction to the cash reserve for payment of future Trust expenses of approximately $0.2 million (approximately $1.5 million used to pay Trust expenses during the period partially offset by approximately $1.3 million withheld from 2012 cash distributions to unitholders). Distributable income for the year ended December 31, 2011 was $52.8 million, which included a net addition to the cash reserve for the payment of future Trust expenses of approximately $1.3 million (approximately $1.9 million withheld from 2011 cash distributions to unitholders partially offset by approximately $0.6 million used to pay Trust expenses during the period).

Liquidity and Capital Resources

The Trust’s principal sources of liquidity and capital are cash flow generated from the Royalty Interests and derivative contracts under the derivatives agreement, 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 derivatives agreement, payment of Trust administrative expenses, including any reserves established by the Trustee for future liabilities, and payment of expense reimbursements to SandRidge for out-of-pocket expenses incurred on behalf of the Trust. See Item 3 of this report for a description of the impact of legal proceedings on the Trust’s administrative expenses. 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.

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Administrative expenses include payments to the Trustee and the Delaware Trustee as well as a quarterly fee of $50,000 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. If at any time the Trust’s cash on hand (including available cash reserves) is not sufficient to pay the Trust’s ordinary course administrative expenses as they become due, the Trust may borrow funds from the Trustee or other lenders, including SandRidge, to pay such expenses. The Trustee does not intend to lend funds to the Trust. If such funds are borrowed, no further distributions will be made to unitholders (except in respect of any previously determined quarterly distribution amount) until the borrowed funds have been repaid. There was no such loan outstanding at December 31, 2013 or 2012.

Under the derivatives agreement, SandRidge pays the Trust amounts it receives from its counterparties and the Trust pays SandRidge any amounts that SandRidge is required to pay such counterparties. Significant payments by the Trust to SandRidge to cover such settlements could reduce or eliminate distributions paid to unitholders.

Trust Distributions to Unitholders. During the years ended December 31, 2013, 2012 and 2011, the Trust’s distributions to unitholders were as follows:

	Covered Production Period	Date Declared	Date Paid	Total Distribution Paid
				(in millions)
Calendar Quarter 2013
First Quarter	September 1, 2012– November 30, 2012	January 31, 2013	March 1, 2013	$	18.2
Second Quarter	December 1, 2012 – February 28, 2013	April 25, 2013	May 30, 2013	$	15.9
Third Quarter	March 1, 2013 – May 31, 2013	July 25, 2013	August 29, 2013	$	16.9
Fourth Quarter	June 1, 2013 – August 31, 2013	October 24, 2013	November 29, 2013	$	12.7

Calendar Quarter 2012
First Quarter(1)	September 1, 2011 – November 30, 2011	February 2, 2012	February 29, 2012	$	22.1
Second Quarter(2)	December 1, 2011 – February 29, 2012	April 30, 2012	May 30, 2012	$	22.0
Third Quarter	March 1, 2012 – May 31, 2012	July 26, 2012	August 29, 2012	$	20.4
Fourth Quarter	June 1, 2012 – August 31, 2012	November 1, 2012	November 29, 2012	$	19.1

Calendar Quarter 2011
First Quarter	N/A	N/A	N/A	N/A
Second Quarter	N/A	N/A	N/A	N/A
Third Quarter	January 1, 2011 – May 31, 2011	July 22, 2011	August 30, 2011	$	29.9
Fourth Quarter(3)	June 1, 2011 – August 31, 2011	October 28, 2011	November 30, 2011	$	22.9

(1) Total distribution paid amount excludes $0.9 million incentive distribution paid to SandRidge as holder of the subordinated units.

(2) Total distribution paid amount excludes $57,000 incentive distribution paid to SandRidge as holder of the subordinated units.

(3) Total distribution paid amount excludes $0.4 million incentive distribution paid to SandRidge as holder of the subordinated units.

On February 28, 2014, the Trust paid a cash distribution of $0.5003 per common unit covering production for the three-month period from September 1, 2013 to November 30, 2013. Because income available for distribution to the common units was below the Subordination Threshold for the period, no distribution was paid on the subordinated units. The distribution totaled $10.5 million and was made to record unitholders as of February 14, 2014.

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Contractual Obligations

A summary of the Trust’s contractual obligations as of December 31, 2013 is provided in the following table:

	Payments Due by Year
	2014		2015		2016		2017		2018		After 2018		Total
	(in thousands)
Administrative services fee	$	200.0	$	200.0	$	200.0	$	200.0	$	200.0	$	2,400.0	$	3,400.0
Trustee Administrative fee	150.0		150.0		150.0		150.0		150.0		1,800.0		2,550.0
Delaware Trustee fee	2.3		2.3		2.3		2.3		2.3		27.6		39.1
Total	$	352.3	$	352.3	$	352.3	$	352.3	$	352.3	$	4,227.6	$	5,989.10

Pursuant to the terms of the administrative services agreement with SandRidge, the Trust is obligated to pay SandRidge an annual administrative services fee of $200,000 for accounting, tax preparation, bookkeeping and informational 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 January 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 $2,300, throughout the life of the Trust.

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 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 of investment in royalty interests, calculated on a unit-of-production basis, and any impairment are charged directly to trust corpus. Distributions to unitholders are recorded when declared. 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.

Proved Reserves. The proved oil, NGL 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 used to record 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 produce oil and gas from the Underlying Properties, or from other factors, including changes to estimates for other reasons. 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, NGL 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, NGL 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. No impairments were recorded in 2013, 2012 or 2011.

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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, 2013, 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 April 1, 2011. Under the derivatives agreement, SandRidge pays the Trust amounts it receives from counterparties under certain of its derivative contracts with third parties, and the Trust pays SandRidge any amounts that SandRidge is required to pay the counterparties under such derivative contracts. The Trust did not bear any costs related to establishing the contracts underlying the derivatives agreement. 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 and collar contracts are settled based upon NYMEX prices. Collar contracts result in a cash settlement only when the settlement price exceeds the fixed ceiling price or falls below the fixed floor price. The contracts underlying the derivatives agreement may not cover all of the future sales volumes of oil and natural gas production through December 31, 2015. The Trust does not have the ability to enter into its own derivative contracts. 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 and natural gas derivative contracts at December 31, 2013. The Trust received net settlement proceeds of approximately $4.2 million, $11.0 million and $1.6 million related to the derivatives agreement during the years ended December 31, 2013, 2012 and 2011, respectively. See “—In certain circumstances the Trust may have to make cash payments under the derivatives agreement and these payments could be significant.” located in Item 1A of this report.

Commodity Price Risk. Because the Trust’s primary asset and source of income is the Royalty Interests, which generally entitle the Trust to receive a portion of the net proceeds from sales of oil, NGL and natural gas production from the Underlying Properties, the Trust’s most significant market risk relates to the prices received for oil, NGL and natural gas production. The derivative contracts described above are intended to mitigate a portion of the variability of oil and natural gas prices received for the Trust’s share of production from the Underlying Properties through December 31, 2015.

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 counterparties will be unable to meet their obligations under the contracts. The Trust’s counterparty under the derivatives agreement is SandRidge, whose counterparties are institutions with an “investment grade” credit rating. SandRidge is not required to pay the Trust to the extent of payment defaults by SandRidge’s counterparties.

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

Evaluation of Disclosure Controls and Procedures. The Trustee conducted an evaluation of the effectiveness of the design and operation of the Trust’s disclosure controls and procedures pursuant to Exchange Act Rules 13a-15 and 15d-15 as of the end of the period covered by this annual report. Based on this evaluation, Michael Ulrich, as Trust Officer, has concluded that the disclosure controls and procedures of the Trust are effective as of December 31, 2013 to provide reasonable assurance that the information required to be disclosed by the Trust in its reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and such information is accumulated and communicated, as appropriate to allow timely decisions regarding required disclosure. In its evaluation of disclosure controls and procedures, the Trustee has relied, to the extent considered reasonable, on information provided by SandRidge Energy, Inc. (“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 results of operations, the status of

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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.

Trustee’s Report on Internal Control over Financial Reporting and Report of Independent Registered Public Accounting Firm. The information required to be furnished pursuant to this item is set forth below and in the “Report of Independent Registered Public Accounting Firm” in Item 8 of this annual report.

The Trustee is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Securities and Exchange Act of 1934, as amended. The Trustee conducted an evaluation of the effectiveness of the Trust’s internal control over financial reporting based on the criteria established in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Trustee’s evaluation under the framework in Internal Control—Integrated Framework (1992), the Trustee concluded that the Trust’s internal control over financial reporting was effective as of December 31, 2013. The effectiveness of the Trust’s internal control over financial reporting as of December 31, 2013 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report, which is included herein.

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

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

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, 2013 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.

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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 years ended December 31, 2013, 2012 and 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 Unitholder 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 7, 2014 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	528,063	(1)	2.5	%
123 Robert S. Kerr Avenue Oklahoma City, OK 73102	Subordinated units	7,000,000	(1)	100.0	%

(1) All 528,063 common units and 7,000,000 subordinated units beneficially owned by SandRidge are held of record by its wholly owned subsidiary, SandRidge Exploration and Production, LLC.

On June 30, 2014, which is 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 25.0% of the total number of units outstanding. As of March 7, 2014, SandRidge owned 26.9% of the total Trust units outstanding.

(b) Security Ownership of Management.

Not applicable.

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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 April 12, 2011, effective January 1, 2011. Additionally, the Trust entered into the derivatives agreement with SandRidge on April 12, 2011, which was effective April 1, 2011, and the registration rights agreement with SandRidge. On October 24, 2012, pursuant to the registration rights agreement, the Trust and SandRidge filed a registration statement on Form S-3 registering the offering by SandRidge Exploration and Production, LLC of 528,063 common units. The registration statement was declared effective on November 7, 2012. 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 initial public offering 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 2013 and 2012 and fees billed for other services rendered by PricewaterhouseCoopers LLP.

	2013		2012
Audit fees(1)	$	255,000	$	250,729
Audit-related fees	—		—
Tax fees	370,000		369,391
All other fees	—		—
Total fees	$	625,000	$	620,120

(1) Fees for audit services in 2013 and 2012 consisted of the audit of the Trust’s annual financial statements and reviews of the Trust’s quarterly financial statements and registration statement.

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PART IV

Item 15. Exhibits and Financial Statement Schedules

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

(1) Financial Statements

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

(2) Financial Statement Schedules

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

(3) Exhibits

Reference is made to the Exhibit Index.

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INDEX TO FINANCIAL STATEMENTS

	Page(s)
Report of Independent Registered Public Accounting Firm	F-2
Statements of Assets and Trust Corpus at December 31, 2013 and 2012	F-3
Statements of Distributable Income for the Years Ended December 31, 2013, 2012 and 2011	F-4
Statements of Changes in Trust Corpus for the Years Ended December 31, 2013, 2012 and 2011	F-5
Notes to Financial Statements	F-6

F-1

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Report of Independent Registered Public Accounting Firm

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

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

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

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

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

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


	/s/ PricewaterhouseCoopers LLP
	PricewaterhouseCoopers LLP

Tulsa, Oklahoma

March 14, 2014

F-2

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SANDRIDGE MISSISSIPPIAN TRUST I

STATEMENTS OF ASSETS AND TRUST CORPUS

(In thousands, except unit data)

	December 31,
	2013			2012
ASSETS
Cash and cash equivalents	$	1,669		$	1,146
Investment in royalty interests	308,964			308,964
Less: accumulated amortization	(74,674		)	(49,223		)
Net investment in royalty interests	234,290			259,741
Total assets	$	235,959		$	260,887
TRUST CORPUS
Trust corpus, 21,000,000 common units and 7,000,000 subordinated units issued and outstanding at December 31, 2013 and 2012	$	235,959		$	260,887

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

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SANDRIDGE MISSISSIPPIAN TRUST I

STATEMENTS OF DISTRIBUTABLE INCOME

(In thousands, except unit and per unit data)

	Years Ended December 31,
	2013		2012			2011
Revenues
Royalty income	$	65,455	$	78,985		$	55,937
Derivative settlements, net	4,187		11,013			1,578
Total revenues	69,642		89,998			57,515
Expenses
Post-production expenses	3,076		3,285			1,749
Production taxes	987		806			570
Trust administrative expenses	1,346		1,493			643
Cash reserves withheld (used) for current Trust expenses, net of amounts (used) withheld	523		(190		)	1,312
Total expenses	5,932		5,394			4,274
Income available for distribution prior to incentive calculation	63,710		84,604			53,241
Less: Incentive distribution to SandRidge	—		920			441
Distributable income available to unitholders	63,710		83,684			52,800
Distributable income per common unit (21,000,000 units issued and outstanding)	$	2.4552	$	2.9887		$	1.8857
Distributable income per subordinated unit (7,000,000 units issued and outstanding)	$	1.7357	$	2.9887		$	1.8857

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

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SANDRIDGE MISSISSIPPIAN TRUST I

STATEMENTS OF CHANGES IN TRUST CORPUS

(In thousands)

	Years Ended December 31,
	2013			2012			2011

Trust corpus, beginning of year	$	260,887		$	286,456		$	1
Issuance of Trust units	—			—			336,893
Conveyance of royalty interests	—			—			308,964
Consideration paid for conveyance of royalty interests	—			—			(336,893		)
Amortization of investment in royalty interests	(25,451		)	(25,379		)	(23,844		)
Net cash reserves withheld (used)	523			(190		)	1,312
Distributable income	63,710			83,684			52,800
Distributions paid or payable to unitholders	(63,710		)	(83,684		)	(52,777		)
Trust corpus, end of year	$	235,959		$	260,887		$	286,456

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

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SANDRIDGE MISSISSIPPIAN TRUST I

NOTES TO FINANCIAL STATEMENTS

1. Organization of the Trust

Nature of Business. SandRidge Mississippian Trust I (the “Trust”) is a statutory trust formed on December 30, 2010 under the Delaware Statutory Trust Act pursuant to a trust agreement by and among SandRidge Energy, Inc. (“SandRidge”), as Trustor, The Bank of New York Mellon Trust Company, N.A., as Trustee (the “Trustee”), and The Corporation Trust Company, as Delaware Trustee (the “Delaware Trustee”). The trust agreement was amended and restated by SandRidge, the Trustee and the Delaware Trustee on April 12, 2011. References in this report to the “trust agreement” are to the amended and restated trust agreement.

The Trust was created to acquire and hold Royalty Interests in specified oil and natural gas properties located in the Mississippian formation in Alfalfa, Garfield, Grant, Major and Woods counties in Oklahoma (the “Underlying Properties”). The Royalty Interests were conveyed to the Trust by SandRidge in exchange for Trust common and subordinated units and the proceeds of the Trust’s initial public offering, described further below.

The Royalty Interests entitle the Trust to receive 90% of the proceeds (after deducting post-production costs and any applicable taxes) from the sale of oil, natural gas liquids (“NGL”) and natural gas production attributable to SandRidge’s net revenue interest in 36 wells producing at December 31, 2010, and one additional well undergoing completion operations at that time (together, the “Initial Wells”), and 50% of the proceeds (after deducting post-production costs and any applicable taxes) from the sale of oil, NGL and natural gas production attributable to SandRidge’s net revenue interest in 123 development wells that have been drilled (the “Trust Development Wells”) within an area of mutual interest (“AMI”) beginning January 1, 2011, the effective date of the conveyance. Although the Trust was formed on December 30, 2010, conveyance of the Royalty Interests did not occur until April 2011 and no proceeds from the sale of oil and natural gas production were received by the Trust until August 2011.

As specified in the development agreement executed by the Trust with SandRidge, SandRidge was obligated to drill, or cause to be drilled, the Trust Development Wells by December 31, 2015 (see Note 6), and was credited for having drilled one full Trust Development Well if the well was drilled and perforated for completion with a minimum perforated length of 2,500 feet in a specified target formation and SandRidge’s net revenue interest in the well was equal to 57.0%. As of December 31, 2013, SandRidge had drilled and perforated for completion approximately 124 Trust Development Wells and met its obligation under the development agreement.

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

Initial Public Offering. Through an initial public offering in April 2011, the Trust sold 17,250,000 of its common units to the public for net proceeds, after payment of offering expenses, of approximately $336.9 million. The Trust delivered the net proceeds of the offering, along with 3,750,000 common units and 7,000,000 subordinated units, to certain wholly owned subsidiaries of SandRidge, in exchange for the conveyance of the Royalty Interests to the Trust. Upon completion of these transactions and as of December 31, 2013, there were 28,000,000 Trust units, consisting of 21,000,000 common and 7,000,000 subordinated units, issued and outstanding. At December 31, 2013, SandRidge owned 528,063 Trust common units and 7,000,000 Trust subordinated units. The common and subordinated units have identical rights and privileges, except with respect to their rights to receive distributions as described below.

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

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

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The subordinated units, all of which are held by SandRidge, constitute 25% of the Trust units issued and outstanding. The subordinated units are entitled to receive pro rata distributions from the Trust each quarter if and to the extent there is sufficient cash to provide a cash distribution on the common units that is no less than 80% of the target distribution for the corresponding quarter (“Subordination Threshold”). If there is not sufficient cash to fund such a distribution on all of the common units, the distribution to be made with respect to the subordinated units is reduced or eliminated for such quarter in order to make a distribution, to the extent possible, of up to the Subordination Threshold amount on all of the common units. 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”). On June 30, 2014, which is the end of the fourth full calendar quarter following SandRidge’s satisfaction of its drilling obligation with respect to the Trust Development Wells, the subordinated units will automatically convert into common units on a one-for-one basis and SandRidge’s right to receive incentive distributions in respect of subsequent periods will terminate. Distributions made to common units in respect of subsequent periods will no longer have the protection of the Subordination Threshold, and all Trust unitholders will share on a pro rata basis in the Trust’s distributions.

Dissolution. The Trust will dissolve and begin to liquidate on December 31, 2030 (the “Termination Date”) and will soon thereafter wind up its affairs and terminate. At the Termination Date, 50% of the Royalty Interests will revert automatically to SandRidge. The remaining 50% of the Royalty Interests will be retained by the Trust at the Termination Date and thereafter sold, with the net proceeds of the sale, as well as any remaining Trust cash reserves, distributed to the unitholders on a pro rata basis. SandRidge has a right of first refusal to purchase the Royalty Interests retained by the Trust at the Termination Date.

2. Significant Accounting Policies

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

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

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

Distributable Income Per Common and Subordinated Unit. The Trust calculates distributable income per common and subordinated unit using the two-class method. In accordance with this method, undistributed earnings in the accompanying statements of distributable income have been allocated to the common and subordinated units based upon the subordinated units’ contractual participation rights as if all of the distributable income for the periods presented had been distributed. Distributable income per unit amounts as calculated for the periods presented in the accompanying statement of distributable income do not differ from declared distribution amounts per unit.

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 April 2011 was accounted for as a transfer of properties between entities under common control and recorded at SandRidge’s historical cost, or $309.0 million, which was determined by allocating the historical net book value of SandRidge’s full cost pool based on the fair value of the Royalty Interests relative to the fair value of SandRidge’s full cost pool. The carrying value of the Trust’s investment in royalty interests is not necessarily indicative of the fair value of such Royalty Interests.

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

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

Derivative Financial Instruments. The Trust entered into a derivatives agreement with SandRidge to manage risks related to oil and natural gas price volatility. See Note 6. In accordance with the Trust’s accounting policy, derivative instruments are recorded when benefits are received or obligations are paid. The fair market values and changes in the fair market value of the derivative contracts are not included in the accompanying financial statements as the statements are presented on a modified cash basis. The Trust received net settlement proceeds of approximately $4.2 million, $11.0 million and $1.6 million related to the derivatives agreement during the years ended December 31, 2013, 2012 and 2011, respectively.

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

Concentration of Risk. The Trust maintains cash balances at one financial institution which are insured by the Federal Deposit Insurance Corporation up to $250,000. The Trust typically has balances in these accounts that exceed the federally insured limit substantially. The Trust does not anticipate any loss associated with balances exceeding the federally insured limit. The Trust also has credit risk with respect to SandRidge to the extent that payments under hedging arrangements are remitted to SandRidge for payment to the Trust.

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.

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, on or about 60 days following the completion of each quarter. Other than the first distribution, which covered production for the five-month period from January 1, 2011 to May 31, 2011, distributions cover a three-month period. A summary of the Trust’s distributions to unitholders is as follows:

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				Total
	Covered			Distribution		Distribution Per Unit
	Production Period	Date Declared	Date Paid	Paid		Common		Subordinated
				(in millions)
Calendar Quarter 2013
First Quarter	September 1, 2012 – November 30, 2012	January 31, 2013	March 1, 2013	$	18.2	$	0.6507	$	0.6507
Second Quarter	December 1, 2012 – February 28, 2013	April 25, 2013	May 30, 2013	$	15.9	$	0.5904	$	0.5015
Third Quarter	March 1, 2013 – May 31, 2013	July 25, 2013	August 29, 2013	$	16.9	$	0.6112	$	0.5835
Fourth Quarter	June 1, 2013 – August 31, 2013	October 24, 2013	November 29, 2013	$	12.7	$	0.6029	$	0.0000

Calendar Quarter 2012
First Quarter(1)	September 1, 2011 – November 30, 2011	February 2, 2012	February 29, 2012	$	22.1	$	0.7909	$	0.7909
Second Quarter(2)	December 1, 2011 – February 29, 2012	April 30, 2012	May 30, 2012	$	22.0	$	0.7870	$	0.7870
Third Quarter	March 1, 2012 – May 31, 2012	July 26, 2012	August 29, 2012	$	20.4	$	0.7277	$	0.7277
Fourth Quarter	June 1, 2012 – August 31, 2012	November 1, 2012	November 29, 2012	$	19.1	$	0.6831	$	0.6831

Calendar Quarter 2011
First Quarter	N/A	N/A	N/A	N/A		N/A		N/A
Second Quarter	N/A	N/A	N/A	N/A		N/A		N/A
Third Quarter	January 1, 2011 – May 31, 2011	July 22, 2011	August 30, 2011	$	29.9	$	1.0685	$	1.0685
Fourth Quarter(3)	June 1, 2011 – August 31, 2011	October 28, 2011	November 30, 2011	$	22.9	$	0.8164	$	0.8164

(1) Total distribution paid amount excludes $0.9 million incentive distribution paid to SandRidge as holder of the subordinated units.

(2) Total distribution paid amount excludes $57,000 incentive distribution paid to SandRidge as holder of the subordinated units.

(3) Total distribution paid amount excludes $0.4 million incentive distribution paid to SandRidge as holder of the subordinated units.

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

5. Commitments and Contingencies

Loan Commitment. Pursuant to the trust agreement, if at any time the Trust’s cash on hand (including available cash reserves) is not sufficient to pay the Trust’s ordinary course administrative expenses as they become due, SandRidge will loan funds to the Trust necessary to pay such expenses. Any funds loaned by SandRidge pursuant to this commitment will be limited to the payment of current accounts payable or other obligations to trade creditors in connection with obtaining goods or services or the payment of other 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, no further distributions will be made to unitholders (except in respect of any previously determined quarterly cash distribution amount) until such loan is repaid. Any such loan will be on an unsecured basis, and the terms of such loan will be substantially the same as those which would be obtained in an arm’s length transaction between SandRidge and an unaffiliated third party. There was no such loan outstanding with SandRidge at December 31, 2013 or 2012.

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

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Legal Proceedings. The Trust has been named as an additional defendant in a putative class action against SandRidge and others as described below.

The Trust and SandRidge have each filed a Motion to Dismiss the claims asserted against the Trust in the Corrected Consolidated Amended Complaint, which are pending before the court.

6. Related Party Transactions

Trustee Administrative Fee. Under the terms of the trust agreement, the Trust pays an annual administrative fee of $150,000 to the Trustee, which will be adjusted for inflation by no more than 3% in any year, beginning in 2017. The Trustee’s administrative fees paid during the years ended December 31, 2013, 2012 and 2011 totaled approximately $150,000, $150,000 and $122,500, respectively.

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

Development Agreement. The Trust’s development agreement with SandRidge obligated SandRidge to drill, or cause to be drilled, the Trust Development Wells by December 31, 2015. 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 the Trust Development Wells until SandRidge had fulfilled its drilling obligation. The Development Agreement terminated upon SandRidge’s fulfillment of its drilling obligation in the second quarter of 2013.

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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 $166.1 million. As of December 31, 2013, SandRidge had drilled and perforated for completion approximately 124 equivalent Trust Development Wells, thus fulfilling its drilling obligation. Accordingly the Trust had fully released the Drilling Support Lien.

Administrative Services Agreement. The Trust is party to an administrative services agreement with SandRidge, effective January 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. For its services under the administrative services agreement, SandRidge receives an annual fee of $200,000, 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. During the years ended December 31, 2013, 2012 and 2011, the Trust paid administrative fees to SandRidge equal to $200,000, $200,000 and $100,000, respectively.

Derivatives Agreement. The Trust is party to a derivatives agreement with SandRidge, effective April 1, 2011, that provides the Trust with the economic effect of certain oil and natural gas derivative contracts entered into by SandRidge with third parties. The underlying commodity derivative contracts cover volumes of oil and natural gas production through December 31, 2015. Under the derivatives agreement, SandRidge pays the Trust amounts it receives from its counterparties and the Trust pays SandRidge any amounts that SandRidge is required to pay such counterparties. The Trust did not bear any costs related to the establishment of the underlying contracts. The Trust does not have the ability to enter into its own derivative contracts. The commodity derivative contracts underlying the derivatives agreement consist of fixed price swaps and collars.

The following tables present, as of December 31, 2013, the notional amount and weighted average fixed price or collar range of the open contracts underlying the derivatives agreement.

Oil – Price Swaps

Contract Period	Notional (MBbl)	Weighted Avg. Fixed Price
January 2014 — December 2014	541	$	100.94
January 2015 — December 2015	468	$	101.07

Natural Gas – Collars

Contract Period	Notional (MMBtu)	Collar Range
January 2014 — December 2014	937	$4.00 - $7.78
January 2015 — December 2015	1,010	$4.00 - $8.55

7. Major Customers

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

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	2013
	Sales		% of Revenue
	(in thousands)
Plains All American, Inc.	$	27,394	41.9%
Atlas Pipeline Mid-Continent Westok, LLC	$	22,772	34.8%
Sunoco, Inc.	$	8,264	12.6%

	2012
	Sales		% of Revenue
	(in thousands)
Sunoco, Inc.	$	20,966	26.5%
Atlas Pipeline Mid-Continent Westok, LLC	$	19,024	24.1%
Gavilon, LLC	$	18,275	23.1%

	2011
	Sales		% of Revenue
	(in thousands)
Atlas Pipeline Mid-Continent Westok, LLC	$	15,501	27.7%
Sunoco, Inc.	$	15,041	26.9%
Shell Trading (US) Company	$	12,833	23.0%
Gavilon, LLC	$	7,573	13.5%

8. Subsequent Events

On January 30, 2014, the Trust declared a cash distribution of $0.5003 per common unit covering production for the three-month period from September 1, 2013 to November 30, 2013 for record unitholders as of February 14, 2014. The distribution was paid on February 28, 2014. Distributable income for September 1, 2013 to November 30, 2013 was calculated as follows (in thousands, except for unit and per unit amounts):

Revenues
Royalty income	$	11,201
Derivative settlements, net	323
Total revenues	11,524
Expenses
Post-production expenses	530
Production taxes	104
Cash reserves withheld by Trustee(1)	382
Total expenses	1,016
Distributable income available to unitholders	$	10,508
Distributable income per common unit (21,000,000 units issued and outstanding)	$	0.5003
Distributable income per subordinated unit (7,000,000 units issued and outstanding)	$	0.0000

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

Because income available for distribution on the Trust common units was $0.5003 per unit, which is below the Subordination Threshold of $0.6088 for the period, no distribution was paid on the subordinated units for the period.

9. Supplemental Information on Oil and Natural Gas Producing Activities

The following supplemental information includes capitalized costs related to oil and natural gas producing activities; costs incurred in oil and natural gas property acquisition, exploration and development; and the results of operations for oil and natural gas producing activities. Supplemental information is also provided for oil, NGL and natural gas production and average sales prices; the estimated quantities of proved oil, NGL and natural gas reserves; the standardized measure of discounted future net cash flows

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associated with proved oil, NGL and natural gas reserves; and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved oil, NGL and natural gas reserves. This supplemental information was prepared on an accrual basis, which is the basis upon which SandRidge and the Underlying Properties maintain their records and is different from the modified cash basis on which the Trust financial statements are prepared. A reconciliation of information presented on the modified cash basis to the accrual basis for the years ended December 31, 2013, 2012 and 2011 is as follows:

	Year Ended December 31, 2013
			For the period
	Modified Cash Basis(1)		September 1, 2012 to December 31, 2012			September 1, 2013 to December 31, 2013		Accrual Basis (2)

Production Data(Unaudited)
Oil (MBbls)(3)	513.4		(210.6		)	117.1		419.9
Natural Gas (MMcf)	5,550.9		(2,162.4		)	1,315.4		4,703.9
Combined equivalent volumes (MBoe)	1,438.5		(571.0		)	336.4		1,203.9

Royalty Income (in thousands)	$	65,455	$	(24,415	)	$	14,687	$	55,727
Expenses (in thousands):
Post-production costs	3,076		(1,162		)	635		2,549
Production taxes	987		(247		)	143		883
	$	61,392	$	(23,006	)	$	13,909	$	52,295

	Year Ended December 31, 2012
			For the period
	Modified Cash Basis(4)		September 1, 2011 to December 31, 2011			September 1, 2012 to December 31, 2012		Accrual Basis (5)

Production Data(Unaudited)
Oil (MBbls)(6)	665.0		(244.9		)	210.6		630.7
Natural Gas (MMcf)	5,918.1		(2,088.7		)	2,162.4		5,991.8
Combined equivalent volumes (MBoe)	1,651.4		(593.0		)	571.0		1,629.4

Royalty Income (in thousands)	$	78,985	$	(29,651	)	$	24,415	$	73,749
Expenses (in thousands):
Post-production costs	3,285		(1,120		)	1,162		3,327
Production taxes	806		(300		)	247		753
	$	74,894	$	(28,231	)	$	23,006	$	69,669

	Year Ended December 31, 2011
			For the period
	Modified Cash Basis(7)		January 1, 2011 to April 12, 2011			September 1, 2011 to December 31, 2011		Accrual Basis (8)

Production Data(Unaudited)
Oil (MBbls)	444.0		(178.7		)	244.9		510.2
Natural Gas (MMcf)	3,387.8		(1,192.6		)	2,088.7		4,283.9
Combined equivalent volumes (MBoe)	1,008.6		(377.4		)	593.0		1,224.2

Royalty Income (in thousands)	$	55,937	$	(21,318	)	$	29,651	$	64,270
Expenses (in thousands):
Post-production costs	1,749		(588		)	1,120		2,281
Production taxes	570		(214		)	300		656
	$	53,618	$	(20,516	)	$	28,231	$	61,333

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

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

(3) Includes NGLs which comprised approximately 1% and 3% of total production for the modified cash basis and accrual basis, respectively.

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

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

(6) Includes NGLs which comprised approximately 0.1% of total production for both the modified cash basis and accrual basis.

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

(8) Production volumes attributable to the Royalty Interests and related revenues and expenses, presented on an accrual basis, from the date of conveyance, April 12, 2011, through December 31, 2011.

Capitalized Costs Related to Oil and Natural Gas Producing Activities

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

	December 31,
	2013			2012			2011
Investment in royalty interests
Proved(1)	$	308,964		$	308,964		$	308,964
Unproved	—			—			—
Total investment in royalty interests	308,964			308,964			308,964
Less accumulated amortization	(74,674		)	(49,223		)	(23,844		)
Net investment in royalty interests	$	234,290		$	259,741		$	285,120

(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 $309.0 million. The Trust delivered the net proceeds of its initial public offering, or $336.9 million, along with 3,750,000 common units and 7,000,000 subordinated units, to certain wholly owned subsidiaries of SandRidge in exchange for the conveyance of the Royalty Interests to the Trust in April 2011. The Trust is not responsible for any costs incurred to drill the Trust Development Wells. As such, the Trust did not incur any costs in the exploration or development of oil and natural gas properties during any of the years ended December 31, 2013, 2012 or 2011.

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

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

For the Year Ended December 31, 2013
Revenues(1)	$	55,727
Expenses(1)(2)
Post-production costs	2,549
Production taxes	883
Amortization expense(3)	25,451
Total expenses	28,883
Results of operations for oil and natural gas producing activities (excluding general and administrative costs and derivative settlements of the Trust)	$	26,844

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SANDRIDGE MISSISSIPPIAN TRUST I

NOTES TO FINANCIAL STATEMENTS

For the Year Ended December 31, 2012
Revenues(4)	$	73,749
Expenses(2)(4)
Post-production costs	3,327
Production taxes	753
Amortization expense(3)	25,379
Total expenses	29,459
Results of operations for oil and natural gas producing activities (excluding general and administrative costs and derivative settlements of the Trust)	$	44,290

For the Year Ended December 31, 2011
Revenues(5)	$	64,270
Expenses(2)(5)
Post-production costs	2,281
Production taxes	656
Amortization expense(3)	23,844
Total expenses	26,781
Results of operations for oil and natural gas producing activities (excluding general and administrative costs and derivative settlements of the Trust)	$	37,489

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

(2) The Trust does not bear any well operating costs and is not subject to federal or state income taxes.

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

(5) Revenues and post-production costs attributable to volumes produced from April 12, 2011, the date of conveyance, to December 31, 2011, regardless of whether proceeds from the sale of production have been remitted to the Trust by SandRidge.

Oil, NGL and Natural Gas Reserve Quantities (Unaudited)

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

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

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

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

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SANDRIDGE MISSISSIPPIAN TRUST I

NOTES TO FINANCIAL STATEMENTS

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

	Oil (MBbls)		Natural Gas (MMcf)(1)
Proved developed and undeveloped reserves
As of December 31, 2010	—		—
Conveyance of Royalty Interests by SandRidge	9,179.9		58,667.9
Revisions of previous estimates	(354.8	)	11,869.7
Extensions and discoveries	—		—
Production(2)	(510.2	)	(4,283.9	)
As of December 31, 2011	8,314.9		66,253.7

	Oil (MBbls)		NGL (MBbls)		Natural Gas (MMcf)(1)
Proved developed and undeveloped reserves
As of December 31, 2011	8,314.9		—		66,253.7
Revisions of previous estimates	(4,361.1	)	2,143.0		(7,482.8	)
Extensions and discoveries	—		—		—
Production(3)	(629.6	)	(1.1	)	(5,991.8	)
As of December 31, 2012	3,324.2		2,141.9		52,779.1
Revisions of previous estimates	(734.6	)	(130.9	)	(13,361.6	)
Extensions and discoveries	—		—		—
Production(4)	(388.2	)	(31.7	)	(4,703.9	)
As of December 31, 2013	2,201.4		1,979.3		34,713.6

Proved developed reserves(5)
As of December 31, 2010	—		—		—
As of December 31, 2011	5,012.5		—		43,550.2
As of December 31, 2012	2,943.1		1,946.0		48,829.4
As of December 31, 2013	2,201.4		1,979.3		34,713.6
Proved undeveloped reserves(5)
As of December 31, 2010	—		—		—
As of December 31, 2011	3,302.4		—		22,703.5
As of December 31, 2012	381.1		195.9		3,949.7
As of December 31, 2013	—		—		—

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

(2) Volumes produced from April 12, 2011, the date of Royalty Interest conveyance, to December 31, 2011, regardless of whether proceeds from the sale of such production have been remitted to the Trust by SandRidge.

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

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

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

The Trust recognized net reductions to reserves associated with proved properties of approximately 3,092 MBoe as a result of negative revisions due to well performance during 2013 as additional information was obtained through the continued horizontal development of and production within the AMI from the Mississippian formation during the period. Additionally, approximately 878 MBoe were converted from proved undeveloped reserves to proved developed reserves during 2013 as SandRidge drilled the Trust Development Wells in order to fulfill its drilling obligation.

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SANDRIDGE MISSISSIPPIAN TRUST I

NOTES TO FINANCIAL STATEMENTS

The Trust recognized net reductions to reserves associated with proved properties in the AMI of approximately 3,465.2 MBoe as a result of negative revisions due to pricing and well performance during 2012 as additional information was obtained through the continued horizontal development of and production within the AMI from the Mississippian formation during the period. Additionally, approximately 2,566.0 MBoe were converted from proved undeveloped reserves to proved developed reserves during 2012 as SandRidge drilled the Trust Development Wells in order to fulfill its drilling obligation.

During 2011, the Trust recognized net additions to oil and natural gas reserves associated with proved properties in the AMI of approximately 1,623.5 MBoe as a result of positive revisions due to well performance.

Standardized Measure of Discounted Future Net Cash Flows (Unaudited)

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

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

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

	December 31,
	2013		2012		2011
Oil (per barrel)	$	94.13	$	90.57	$	91.21
NGL (per barrel)	$	30.69	$	30.70	$	—
Natural Gas (per Mcf)	$	3.10	$	2.26	$	4.12

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

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

As of December 31, 2013
Future cash inflows from production	$	375,448
Future production costs(1)	(22,805		)
Undiscounted future net cash flows(2)	352,643
10% annual discount	(178,220		)
Standardized measure of discounted future net cash flows	$	174,423

As of December 31, 2012
Future cash inflows from production	$	486,127
Future production costs(1)	(27,099		)
Undiscounted future net cash flows(2)	459,028
10% annual discount	(224,694		)
Standardized measure of discounted future net cash flows	$	234,334

As of December 31, 2011
Future cash inflows from production	$	1,031,238
Future production costs(1)	(52,699		)
Undiscounted future net cash flows(2)	978,539
10% annual discount	(470,240		)
Standardized measure of discounted future net cash flows	$	508,299

(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.

(2) The Trust is not subject to federal or state income taxes.

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

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SANDRIDGE MISSISSIPPIAN TRUST I

NOTES TO FINANCIAL STATEMENTS

Present value as of December 31, 2010	$	—
Conveyance of Royalty Interests by SandRidge	433,631
Revenues less post-production and other costs	(61,333		)
Net changes in prices, production and other costs	65,676
Revisions of previous quantity estimates	5,875
Accretion of discount	32,177
Timing differences and other(1)	32,273
Net change for the year	508,299
Present value as of December 31, 2011	508,299
Revenues less post-production and other costs	(69,669		)
Net changes in prices, production and other costs	(142,863		)
Revisions of previous quantity estimates	(82,689		)
Accretion of discount	43,778
Timing differences and other(1)	(22,522		)
Net change for the year	(273,965		)
Present value as of December 31, 2012	234,334
Revenues less post-production and other costs	(52,295		)
Net changes in prices, production and other costs	24,858
Revisions of previous quantity estimates	(45,828		)
Accretion of discount	20,175
Timing differences and other(1)	(6,821		)
Net change for the year	(59,911		)
Present value as of December 31, 2013	$	174,423

(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 2013 and 2012 are summarized below (in thousands, except per unit data).

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
2013	(1)		(2)		(3)		(4)
Royalty income	$	18,107	$	16,096	$	17,136	$	14,116
Distributable income available to unitholders	$	18,221	$	15,909	$	16,920	$	12,660
Distributable income per common unit	$	0.6507	$	0.5904	$	0.6112	$	0.6029
Distributable income per subordinated unit	$	0.6507	$	0.5015	$	0.5835	$	—

2012	(5)		(6)		(7)		(8)
Royalty income	$	22,005	$	21,124	$	18,317	$	17,539
Distributable income available to unitholders	$	22,145	$	22,037	$	20,375	$	19,126
Distributable income per common unit	$	0.7909	$	0.7870	$	0.7277	$	0.6831
Distributable income per subordinated unit	$	0.7909	$	0.7870	$	0.7277	$	0.6831

(1) Includes proceeds attributable to production from the Royalty Interests from September 1, 2012 to November 30, 2012.

(2) Includes proceeds attributable to production from the Royalty Interests from December 1, 2012 to February 28, 2013.

(3) Includes proceeds attributable to production from the Royalty Interests from March 1, 2013 to May 31, 2013.

(4) Includes proceeds attributable to production from the Royalty Interests from June 1, 2013 to August 31, 2013.

(5) Includes proceeds attributable to production from the Royalty Interests from September 1, 2011 to November 30, 2011.

(6) Includes proceeds attributable to production from the Royalty Interests from December 1, 2011 to February 29, 2012.

(7) Includes proceeds attributable to production from the Royalty Interests from March 1, 2012 to May 31, 2012.

(8) Includes proceeds attributable to production from the Royalty Interests from June 1, 2012 to August 31, 2012.

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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 MISSISSIPPIAN TRUST I

	By	The Bank of New York Mellon
		Trust Company, N.A., Trustee

		By: /s/ Michael J. Ulrich
		Michael J. Ulrich Vice President


March 14, 2014

The Registrant, SandRidge Mississippian Trust I, 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 any such function exists pursuant to the terms of the trust agreement under which it serves.

Table of Contents

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 Mississippian Trust I	S-1	333-171551	3.1	01/05/2011

3.2	Trust Agreement of SandRidge Mississippian Trust I, dated December 30, 2010	S-1	333-171551	4.1	01/05/2011

3.3	Amended and Restated Trust Agreement, dated as of April 12, 2011, by and among SandRidge Energy, Inc., SandRidge Mississippian Trust I, and The Corporation Trust Company	8-K	001-35122	3.1	04/18/2011

3.4	Amendment No. 1 to Amended and Restated Trust Agreement of SandRidge Mississippian Trust I, dated June 13, 2012, by The Bank of New York Mellon Trust Company, N.A.	10-Q	001-35122	3.3	08/13/2012

10.1	Perpetual Overriding Royalty Interest Conveyance (PDP), by and between SandRidge Exploration and Production, LLC and SandRidge Mississippian Trust I	8-K	001-35122	10.1	04/18/2011

10.2	Perpetual Overriding Royalty Interest Conveyance (PUD), by and between SandRidge Exploration and Production, LLC and SandRidge Mississippian Trust I	8-K	001-35122	10.2	04/18/2011

10.3	Assignment of Overriding Royalty Interest, by and between Mistmada Oil Company and SandRidge Mississippian Trust I	8-K	001-35122	10.3	04/18/2011

10.4	Term Overriding Royalty Interest Conveyance (PDP), by and between SandRidge Exploration and Production, LLC and Mistmada Oil Company	8-K	001-35122	10.4	04/18/2011

10.5	Term Overriding Royalty Interest Conveyance (PUD), by and between SandRidge Exploration and Production, LLC and Mistmada Oil Company	8-K	001-35122	10.5	04/18/2011

10.6	Administrative Services Agreement, by and between SandRidge Energy, Inc. and SandRidge Mississippian Trust I	8-K	001-35122	10.6	04/18/2011

10.7	Derivatives Agreement, by and between SandRidge Energy, Inc. and SandRidge Mississippian Trust I	8-K	001-35122	10.9	04/18/2011

10.8	Registration Rights Agreement, dated as of April 12, 2011, by and between SandRidge Energy, Inc. and SandRidge Mississippian Trust I	8-K	001-35122	10.10	04/18/2011

23.1	Consent of Cawley, Gillespie & Associates, Inc.					*

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

23.3	Consent of PricewaterhouseCoopers LLP.					*

31.1	Section 302 Certification					*

32.1	Section 906 Certification					*

99.1	Report of Cawley, Gillespie & Associates, Inc.					*