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Index to Financial Statements

As filed with the Securities and Exchange Commission on February 9, 2011

Registration No. 333-171551

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

 

Amendment No. 1 to		Amendment No. 1 to
FORM S-1		FORM S-3
SandRidge Mississippian Trust I		SandRidge Energy, Inc.
(Exact name of co-registrant as specified in its charter)		(Exact name of co-registrant as specified in its charter)
Delaware		Delaware
(State or other jurisdiction of incorporation or organization)		(State or other jurisdiction of incorporation or organization)
1311		1311
(Primary Standard Industrial Classification Code Number)		(Primary Standard Industrial Classification Code Number)
27-6990649		20-8084793
(I.R.S. Employer Identification No.)		(I.R.S. Employer Identification No.)
919 Congress Avenue, Suite 500 Austin, Texas 78701 (512) 236-6599		123 Robert S. Kerr Avenue Oklahoma City, Oklahoma 73102 (405) 429-5500
(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)		(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)
		Tom L. Ward
Michael J. Ulrich The Bank of New York Mellon Trust Company, N.A. 919 Congress Avenue, Suite 500 Austin, Texas 78701 (512) 236-6599		Chairman and Chief Executive Officer SandRidge Energy, Inc. 123 Robert S. Kerr Avenue Oklahoma City, Oklahoma 73102 (405) 429-5500
(Name, address, including zip code, and telephone number, including area code, of agent for service)		(Name, address, including zip code, and telephone number, including area code, of agent for service)

 

 

Copies to:

 

Philip T. Warman, Esq. SandRidge Energy, Inc. 123 Robert S. Kerr Avenue Oklahoma City, Oklahoma 73102 (405) 429-5500		David H. Engvall, Esq. Covington & Burling LLP 1201 Pennsylvania Avenue, N.W. Washington, D.C. 20004 (202) 662-6000		David P. Oelman, Esq. Matthew R. Pacey, Esq. Vinson & Elkins L.L.P. First City Tower 1001 Fannin Street, Suite 2500 Houston, Texas 77002-6760 (713) 758-2222

Approximate date of commencement of proposed sale to the public: As soon as practicable

after this Registration Statement becomes effective.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box:  ¨

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

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):

 

SandRidge Mississippian Trust I
Large accelerated filer		¨		Accelerated filer		¨
Non-accelerated filer		x   (Do not check if a smaller reporting company)		Smaller reporting company		¨
SandRidge Energy, Inc.
Large accelerated filer		x		Accelerated filer		¨
Non-accelerated filer		¨   (Do not check if a smaller reporting company)		Smaller reporting company		¨

The Registrants hereby amend this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrants shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act, or until this Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

 

 

 

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The information in this preliminary prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities, and it is not soliciting an offer to buy these securities, in any jurisdiction where the offer or sale is not permitted.

 

Subject to Completion, dated February 9, 2011

PRELIMINARY PROSPECTUS

SandRidge Mississippian Trust I

12,500,000 Common Units

 

 

This is an initial public offering of common units representing beneficial interests in SandRidge Mississippian Trust I. The trust is selling all of the units offered hereby. SandRidge Energy, Inc. (“SandRidge”) will convey to the trust certain royalty interests in exchange for common and subordinated units collectively representing a 51% beneficial interest in the trust (without giving effect to the exercise of the underwriters’ over-allotment option), as well as all of the net proceeds of this offering. SandRidge will also enter into an agreement with the trust to provide the trust with the benefit of certain hedging arrangements with respect to a portion of the anticipated oil and natural gas production covered by the royalty interests.

Prior to this offering, there has been no public market for the common units. SandRidge expects that the public offering price will be between $             and $             per common unit. The trust intends to apply to have the common units approved for listing on the New York Stock Exchange under the symbol “SDT.”

The Trust Units. Trust units, consisting of the common and subordinated units, are units of beneficial interest in the trust and represent undivided beneficial interests in the property of the trust. They do not represent any interest in SandRidge.

The Trust. The trust will own term and perpetual royalty interests in oil and natural gas properties leased by SandRidge in the Mississippian formation in Alfalfa, Garfield, Grant, Major and Woods counties in Oklahoma. These royalty interests will entitle the trust to receive (a) 90% of the proceeds attributable to SandRidge’s net revenue interest in the sale of production from 37 horizontal producing wells and (b) 50% of the proceeds attributable to SandRidge’s net revenue interest in the sale of production from 123 horizontal development wells to be drilled on drilling locations included within an Area of Mutual Interest consisting of approximately 63,500 gross acres (42,600 net acres) held by SandRidge. The number of wells required to be drilled may increase or decrease in proportion to SandRidge’s actual net revenue interest in each well. The trust will be treated as a partnership for U.S. federal income tax purposes.

The Trust Unitholders. As a trust unitholder, you will receive quarterly distributions of cash from the proceeds that the trust receives from SandRidge’s sale of oil and natural gas subject to the royalty interests held by the trust.

Ownership of Trust Units by SandRidge. After the completion of this offering (without giving effect to the exercise of the underwriters’ over-allotment option), SandRidge will own 6,475,000 common units and 6,325,000 subordinated units, together representing 51% of all outstanding trust units. If the underwriters exercise their over-allotment option, SandRidge will own 4,600,000 common units and 6,325,000 subordinated units, together representing 43% of trust units.

Incentive Distributions and Subordinated Units. SandRidge will be entitled to receive incentive distributions equal to 50% of the amount, if any, by which the cash available for distribution on all of the trust units in any quarter during the subordination period described herein exceeds certain target distribution levels by more than 20%. Trust unitholders, including SandRidge, will be entitled to receive the remaining 50% of such amount on a pro rata basis. A portion of the trust units owned by SandRidge will be subordinated units and will not be entitled to receive distributions to the extent necessary to support specified distribution levels on the common units. The subordinated units will convert into common units following SandRidge’s satisfaction of its drilling obligation. Please see “Target Distributions and Subordination and Incentive Thresholds.”

Investing in the common units involves a high degree of risk. Before buying any common units, you should read the discussion of material risks of investing in the common units in “Risk Factors” beginning on page 18 of this prospectus.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

 

		Per Common Unit				Total
Price to the public		$				$
Underwriting discounts and commissions (1)		$				$
Proceeds to the trust (before expenses) (1)		$				$

 

(1)	Excludes a structuring fee equal to 0.50% of the gross proceeds of this offering, or approximately $             million, payable to Raymond James & Associates, Inc.

 

 

The underwriters may also purchase up to an additional 1,875,000 common units at the initial public offering price, less underwriting discounts and commissions, to cover over-allotments, if any, within 30 days of the date of this prospectus. If the underwriters exercise this option in full, the total underwriting discounts and commissions will be $            , and the trust’s total proceeds, after deducting underwriting discounts and commissions and before expenses, will be $            , which proceeds will be paid to SandRidge.

The underwriters are offering the common units as set forth under “Underwriting.” Delivery of the common units will be made on or about                     , 2011.

 

 

 

RAYMOND JAMES		MORGAN STANLEY

                    , 2011

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IMPORTANT NOTICE ABOUT INFORMATION IN THIS PROSPECTUS			i
SUMMARY			1
RISK FACTORS			18
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS			40
USE OF PROCEEDS			41
SANDRIDGE ENERGY, INC.			42
THE TRUST			43
TARGET DISTRIBUTIONS AND SUBORDINATION AND INCENTIVE THRESHOLDS			48
THE UNDERLYING PROPERTIES			60
DESCRIPTION OF THE ROYALTY INTERESTS			76
DESCRIPTION OF THE TRUST AGREEMENT			80
DESCRIPTION OF THE TRUST UNITS			86
TRUST UNITS ELIGIBLE FOR FUTURE SALE			90
U.S. FEDERAL INCOME TAX CONSIDERATIONS			92
STATE TAX CONSIDERATIONS			110
ERISA CONSIDERATIONS			111
UNDERWRITING			112
LEGAL MATTERS			117
EXPERTS			117
WHERE YOU CAN FIND MORE INFORMATION			118
GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS AND TERMS RELATED TO THE TRUST			119
INDEX TO FINANCIAL STATEMENTS			F-1
ANNEX A: SUMMARY RESERVE REPORT			A-1
ANNEX B: CALCULATION OF TARGET DISTRIBUTIONS			B-1

IMPORTANT NOTICE ABOUT INFORMATION IN THIS PROSPECTUS

You should rely only on the information contained in this prospectus or in any free writing prospectus the trust may authorize to be delivered to you. Until                      (25 days after the date of this prospectus), federal securities laws may require all dealers that effect transactions in the common units, whether or not participating in this offering, to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

The trust and SandRidge have not, and the underwriters have not, authorized anyone to provide you with additional or different information. If anyone provides you with additional, different or inconsistent information, you should not rely on it. This prospectus is not an offer to sell or a solicitation of an offer to buy the common units in any jurisdiction where such offer and sale would be unlawful. You should not assume that the information contained in this prospectus is accurate as of any date other than the date on the front of this document. The trust’s and SandRidge’s business, financial condition, results of operations and prospects may have changed since such date.

 

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RISK FACTORS

Risks Related to the Units

Drilling and completion of the PUD Wells on the Underlying Properties are high risk activities with many uncertainties that could delay the anticipated drilling schedule and adversely affect future production from the Underlying Properties. Any such delays or reductions in production could decrease future revenues that are available for distribution to unitholders.

The drilling and completion of the PUD Wells are subject to numerous risks beyond SandRidge’s and the trust’s control, including risks that could delay the current drilling schedule for the PUD Wells (including the drilling schedule of third party operators that may drill the PUD Wells) and the risk that drilling will not result in commercially viable oil and natural gas production. Drilling for oil and natural gas can be unprofitable if dry wells are drilled and if productive wells do not produce sufficient revenues to return a profit. SandRidge’s and third-party operators’ decisions to develop or otherwise exploit certain areas within the AMI will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. The costs of drilling, completing and operating wells for SandRidge and third-party operators are often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. There can be no assurance that a PUD Well that is successfully completed will pay out the capital costs spent to drill it. Drilling and production operations on the Underlying Properties may be curtailed, delayed or canceled as a results of various factors, including the following:

 

•

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

 

•

unusual or unexpected geological formations and miscalculations;

 

•

shortages of or delays in obtaining equipment and qualified personnel;

 

•

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 and drilling conditions;

 

•

pipe or cement failures;

 

•

casing collapses;

 

•

pressures, fires and blowouts;

 

•

lost or damaged drilling and service tools;

 

•

loss of drilling fluid circulation;

 

•

uncontrollable flows of oil and natural gas and fluids;

 

•

natural disasters;

 

•

environmental hazards, such as oil and natural gas leaks, pipeline ruptures and discharges of toxic gases;

 

•

adverse weather conditions;

 

•

reductions in oil and natural gas prices;

 

•

oil and natural gas property title problems; and

 

•

market limitations for oil and natural gas.

 

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In the event that drilling of development wells is delayed or development wells have lower than anticipated production due to one of the factors above or for any other reason, estimated future distributions to unitholders may be reduced. In addition, because horizontal wells drilled in the Mississippian formation in the AMI typically produce a larger volume of water than wells drilled in other areas, more saltwater disposal wells must be drilled by SandRidge. SandRidge’s inability to drill these wells or otherwise dispose of the water produced from the Producing Wells and PUD Wells in an efficient manner could delay production and therefore the trust’s receipt of proceeds from the royalty interests.

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

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

 

•

regional, domestic and foreign supply, and perceptions of supply, of oil 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 and natural gas;

 

•

weather conditions and seasonal trends;

 

•

anticipated future prices of oil 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;

 

•

acts of force majeure;

 

•

domestic and foreign governmental regulations and taxation;

 

•

energy conservation and environmental measures; and

 

•

the price and availability of alternative fuels.

For oil, from 2007 through 2010, the highest monthly NYMEX settled price was $134.62 per Bbl and the lowest was $33.87 per Bbl. For natural gas, from 2007 through 2010, the highest monthly NYMEX settled price was $13.105 per MMBtu and the lowest was $2.843 per MMBtu. In addition, the market price of oil and natural gas is generally higher in the winter months than during other months of the year due to increased demand for oil and natural gas for heating purposes during the winter season.

Lower oil and natural gas prices will reduce proceeds to which the trust is entitled and may ultimately reduce the amount of oil and natural gas that is economic to produce from the Underlying Properties. As a result, SandRidge or any third-party operator of any of the Underlying Properties could determine during periods of low oil and natural gas prices to shut in or curtail production from wells on the Underlying Properties. In addition, the operator of the Underlying Properties could determine during periods of low oil and natural 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 any well or property if it reasonably believes that the well or property can no longer

 

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produce oil 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. The volatility of oil and natural gas prices also reduces the accuracy of estimates of future cash distributions to trust unitholders.

SandRidge plans to enter into a derivatives agreement with the trust to provide the trust with the benefit of certain hedge contracts with third parties, covering approximately 61% of the oil and 60% of the natural gas volumes expected to be produced from the Underlying Properties through December 31, 2015. The derivatives agreement will not cover all of the oil and natural gas volumes that are expected to be produced during the term of the trust. The trust does not have the ability to enter into any hedge contracts relating to oil and natural gas volumes expected to be produced after December 31, 2015. As a result, the amounts of the cash distributions to unitholders may fluctuate even more significantly after such period as a result of changes in oil and natural gas prices because there will be no hedge contracts in place to reduce the effects of such price changes.

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 trust’s royalty interests. The trust’s reserve quantities and revenues are based on estimates of reserve quantities and revenues for the Underlying Properties. See “The Underlying Properties—Oil and Natural Gas Reserves” for a discussion of the method of allocating proved reserves to the trust. It is not possible to measure underground accumulations of oil and natural gas in an exact way, and estimating reserves is inherently uncertain. Ultimately, actual production and revenues for the Underlying Properties could be materially less than estimated amounts. Petroleum engineers are required to make subjective estimates of underground accumulations of oil and natural gas based on factors and assumptions that include:

 

•

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

 

•

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

 

•

the assumed effect of governmental regulation.

Changes in these assumptions or actual production costs incurred and results of actual development could materially decrease reserve estimates.

Reserve estimates for fields that do not have a lengthy production history are less reliable than estimates for fields with lengthy production histories. A lack of production history may contribute to inaccuracy in estimates of proved reserves, future production rates and the timing of development expenditures. Most of the Producing Wells have been operational for less than one year and estimated total reserves vary substantially from well to well and are not directly correlated to perforated lateral length or completion technique. Although SandRidge and Netherland Sewell 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 proved 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.

 

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The average perforated interval length of the wells assumed for purposes of calculating the PUD reserves (approximately 3,900 feet) is longer than the minimum perforated interval length required for SandRidge to receive credit for one full development well under the development agreement (2,500 feet). Further, there is no guarantee that wells drilled with shorter perforated interval lengths will achieve the same reserve recoveries as wells drilled with longer perforated interval lengths. Moreover, 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, you may not receive the benefit of the total amount of PUD reserves reflected in the reserve report, notwithstanding the fact that SandRidge has satisfied its drilling obligation. See “Summary—The Development Wells.”

Estimates of future cash distributions to unitholders, subordination thresholds and incentive thresholds are based on assumptions that are inherently subjective and are subject to significant business, economic, financial, legal, regulatory and competitive risks and uncertainties that could cause actual cash distributions to differ materially from those estimated.

The estimates of target distributions to unitholders, subordination thresholds and incentive thresholds, as set forth in this prospectus, are based on SandRidge’s calculations, and SandRidge has not received an opinion or report on such calculations from any independent accountants, financial advisers, or engineers. Such calculations are based on assumptions about drilling, production, oil and natural gas prices, hedging activities, capital expenditures, expenses, tax rates and production tax credits under state law and other matters that are inherently uncertain and are subject to significant business, economic, financial, legal, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those estimated. For example, these estimates have assumed that oil and natural gas production is sold at prices consistent with NYMEX forward pricing as of December 17, 2010 for the 36-month period ending December 31, 2013, and assumed price increases thereafter of 2.5% annually, capped at $120.00 per Bbl of oil in 2025 and $7.00 per MMBtu of natural gas in 2022; however, actual sales prices may be significantly lower. Additionally, these estimates assume that the PUD Wells will be drilled on SandRidge’s current anticipated schedule and the related Underlying Properties will achieve production volumes set forth in the reserve report; however, the drilling of the development wells may be delayed and actual production volumes may be significantly lower. Further, after wells are completed, production operations may be curtailed, delayed or terminated as a result of a variety of risks and uncertainties, including those described above under “—Drilling and completion of the PUD Wells on the Underlying Properties are high risk activities with many uncertainties that could delay the anticipated drilling schedule and adversely affect future production from the Underlying Properties. Any such delays or reductions in production could decrease future revenues that are 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 you 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 you receive may be lower than the target distribution and the subordination threshold for the applicable quarter. A cash distribution to trust unitholders below the target distribution amount or the subordination threshold may materially adversely affect the market price of the trust units.

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

Although SandRidge will not be entitled to receive any distribution on its subordinated units unless there is enough cash for all of the common units to receive a distribution equal to the subordination threshold for such quarter (which is 20% below the target distribution level for the

 

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corresponding quarter), the subordinated units constitute only a 25% interest in the trust, and this feature does not guarantee that common units will receive a distribution equal to the subordination threshold, or any distribution at all. Additionally, the subordination period will terminate and the subordinated units will convert into common units at the end of the fourth full calendar quarter following SandRidge’s completion of its drilling obligation. Depending on the prices at which SandRidge is able to sell volumes attributable to the trust, the common units may receive a distribution that is below the subordination threshold.

Quarterly cash distributions will be made by the trust based on the proceeds received by the trust pursuant to the royalty interests for the preceding calendar quarter. If a quarterly cash distribution is lower than the target distribution amount or subordination threshold set forth in this prospectus 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.

The historical and pro forma financial information relating to the Underlying Properties may not be representative of the trust’s future distributable income.

The historical financial information for the Underlying Properties included in this prospectus is derived from SandRidge’s historical financial statements for periods prior to the trust’s initial public offering. The historical financial information for the Underlying Properties included in this prospectus does not give effect to the terms and conditions of the royalty interests and, as a result, does not reflect what the trust’s distributable income will be in the future.

In preparing the pro forma statements of distributable income included in this prospectus, we have made adjustments to the historical financial information for the Underlying Properties based upon currently available information and upon assumptions that our management believes are reasonable in order to reflect, on a pro forma basis, the impact of the conveyance of the royalty interests to the trust and the other items discussed in the unaudited pro forma financial statements and related notes. The estimates and assumptions used in the calculation of the pro forma financial information in this prospectus may be materially different from the trust’s actual experience. Accordingly, the pro forma financial information included in this prospectus does not purport to represent what the trust’s distributable income would actually have been had it been in operation during the periods presented or what the trust’s distributable income will be in the future, nor does the pro forma financial information give effect to any events other than those discussed in the unaudited pro forma financial statements and related notes.

In order to satisfy its drilling obligation to the trust, SandRidge will rely upon third parties to drill the PUD Wells where SandRidge is not the operator.

Pursuant to the development agreement between SandRidge and the trust, SandRidge is obligated to drill, or cause to be drilled, 123 PUD Wells in the AMI. SandRidge owns a majority working interest in approximately 75% of the locations on which it expects to drill the PUD Wells, and it expects to operate such wells during the subordination period. In order to satisfy its drilling obligation, SandRidge will rely upon third-party operators to drill certain of these development wells. A significant portion of these wells may be drilled by a single third-party operator. The ability of third-party operators to help SandRidge meet the drilling obligation will depend on those operators’ future financial condition and economic performance and access to capital, which, in turn, will depend upon the supply and demand for oil and natural gas, prevailing economic conditions and financial, business and other factors. The failure of an operator to adequately perform operations could reduce production from the Underlying Properties and the cash available for distribution to trust unitholders. SandRidge may be provided little or no notice by these operators that they are failing to drill the PUD Wells in accordance with pre-existing schedules.

 

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

For those PUD Wells where SandRidge is the operator, SandRidge may rely on third party servicers to conduct the drilling operations.

Where SandRidge is the operator of a PUD Well, it may rely on third party servicers to perform the necessary drilling operations. The ability of third-party servicers to perform such drilling operations will depend on those servicers’ financial condition and economic performance and access to capital, which in turn will depend upon the supply and demand for oil and natural gas, prevailing economic conditions and financial, business and other factors. The failure of a third party servicer to adequately perform operations could delay drilling or completion or reduce production from the Underlying Properties and the cash available for distribution to trust unitholders. If the PUD Wells take longer to be drilled and completed than currently anticipated, this may delay revenue earned from the production of oil and natural gas by such wells. The revenues distributable to the trust and the amount of cash distributable to the trust unitholders would similarly be delayed.

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

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

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

The Underlying Properties will be operated for oil and natural gas production only and are focused exclusively in the Mississippian formation in Alfalfa, Garfield, Grant, Major and Woods counties in 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 plan 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 trust’s royalty interests were more diversified.

 

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

The amount of oil and natural gas that may be produced and sold from any well to which the Underlying Properties relate is subject to curtailment in certain circumstances, such as by reason of weather conditions, pipeline interruptions due to scheduled and unscheduled maintenance, failure of tendered oil and natural gas to meet quality specifications of gathering lines or downstream transporters, excessive line pressure which prevents delivery, physical damage to the gathering system or transportation system or lack of contracted capacity on such systems. The curtailments may vary from a few days to several months. In many cases, SandRidge is provided limited notice, if any, as to when production will be curtailed and the duration of such curtailments. If SandRidge is forced to reduce production due to such a curtailment, the revenues of the trust and the amount of cash distributions to the trust unitholders would similarly be reduced due to the reduction of proceeds from the sale of production. Although SandRidge currently does not have any material production shut-in and does not shut-in production on a routine basis as a result of lack of accessibility to transportation or lack of processing facilities, there can be no assurance this will be the case in the future.

Some of the PUD Wells on the Underlying Properties will be drilled in locations that currently are not serviced by natural gas gathering and transportation pipelines or locations in which existing gathering and transportation pipelines do not have sufficient capacity to transport additional production. As a result, SandRidge may not be able to sell the natural gas production from certain PUD Wells until the necessary gathering systems and/or transportation pipelines are constructed or until the necessary transportation capacity on an interstate pipeline is obtained. In particular, the system SandRidge intends to use to compress and process the natural gas produced from certain of the Underlying Properties is near its capacity and may not be able to process all of SandRidge’s gas. Any delay in the expansion of such system or the construction or expansion of any other natural gas gathering systems beyond the currently estimated construction schedules, or a delay in the procurement of additional transportation capacity would delay the receipt of any proceeds that may be associated with the natural gas production from the PUD Wells.

The trust units may lose value as a result of title deficiencies with respect to the Underlying Properties.

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

Consistent with industry practice, SandRidge has not yet obtained drilling title opinions on the properties upon which SandRidge intends to drill the PUD Wells. Prior to the drilling of a PUD Well, SandRidge intends to obtain a drilling title opinion to identify defects in title to the leasehold. Frequently, as a result of such examinations, certain curative work must be done to correct identified title defects, and such curative work entails time and expense. SandRidge’s inability or failure to cure title defects could render some locations undrillable or cause SandRidge to lose its rights to some or all production from some of the Underlying Properties, which could result in a reduction in proceeds available for distribution to unitholders and the value of the trust units if a comparable additional location to drill a PUD Well cannot be identified.

 

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The trust is passive in nature and will have no stockholder 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, will have no managerial, contractual or other ability to influence SandRidge’s activities or operations of the Underlying Properties. In addition, some of the PUD Wells may be operated by third parties unrelated to SandRidge. Such third party operators may not have the operational expertise of SandRidge within the AMI. Oil and natural gas properties are typically managed pursuant to an operating agreement among the working interest owners in the properties. The typical operating agreement contains procedures whereby the owners of the aggregate working interest in the property designate one of the interest owners to be the operator of the property. Under these arrangements, the operator is typically responsible for making all decisions relating to drilling activities, sale of production, compliance with regulatory requirements and other matters that affect the property. Neither the trustee nor the trust unitholders has any contractual ability to influence or control the field operations of, sale of oil and natural gas from, or future development of, the Underlying Properties. The trust units are a passive investment that entitle the trust unitholder to only receive cash distributions from the royalty interests and hedging contracts being passed through to the trust.

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

The proceeds payable to the trust from the royalty interests are derived from the sale of the production of oil and natural gas from the Underlying Properties. The oil and natural gas reserves attributable to the Underlying Properties are depleting assets, which means that the reserves of oil and natural gas attributable to the Underlying Properties will decline over time. As a result, the quantity of oil and natural gas produced from the Underlying Properties will decline over time.

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

The trust agreement will provide that the trust’s business activities will be 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 will not be permitted to acquire other oil and gas properties or royalty interests to replace the depleting assets and production attributable to the trust.

 

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An increase in the differential between the price realized by SandRidge for oil or 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 SandRidge’s oil and natural gas production usually fall below the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. The difference between the price received and the benchmark price is called a differential. The amount of the differential will depend on a variety of factors, including discounts based on the quality and location of hydrocarbons produced, Btu content and post-production costs. These factors can cause differentials to be volatile from period to period. SandRidge has little or no control over the factors that determine the amount of the differential, and cannot accurately predict natural gas or crude oil differentials. Increases in the differential between the realized price of oil and natural gas and the benchmark price for oil and natural gas could reduce the proceeds to the trust and therefore the cash distributions by the trust and the value of the trust units. The target distributions were prepared using an assumed negative differential of 19% from NYMEX futures prices for natural gas, and an assumed negative differential of $5.00 per barrel from NYMEX futures prices for oil. For more information on the estimated differentials assumed for purposes of preparing the target distributions, see “Target Distributions and Subordination and Incentive Thresholds—Significant Assumptions Used to Calculate the Target Distributions.”

The amount of cash available for distribution by the trust will be reduced by post-production costs and applicable taxes associated with the trust’s royalty interests, trust expenses and incentive distributions payable to SandRidge.

The royalty interests and the trust will bear certain costs and expenses that will reduce the amount of cash received by or available for distribution by the trust to the holders of the trust units. These costs and expenses include the following:

 

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the trust’s share of the costs incurred by SandRidge to gather, store, compress, transport, process, treat, dehydrate and market the oil and gas;

 

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the trust’s share of applicable taxes on the oil and gas; and

 

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

In addition, the amount of funds available for distribution to unitholders will be 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 will be 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 exceed the incentive threshold for the applicable quarter. See “Target Distributions and Subordination and Incentive Thresholds.”

The amount of costs and expenses borne by the trust 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. For a further summary of post-production costs and applicable taxes for the producing lives of the Producing Wells and PUD Wells, see “The Underlying Properties.” Historical post-production costs and taxes, however, may not be indicative of future post-production costs and taxes.

 

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The hedging contracts entered into by SandRidge pursuant to the derivatives agreement will cover only a portion of the oil and natural gas production attributable to the trust, and such contracts limit the trust’s ability to benefit from commodity price increases for hedged volumes above the corresponding hedge price.

Pursuant to the derivatives agreement, SandRidge will provide the trust with the benefit of certain oil and natural gas hedging contracts that it plans to enter into with third parties. The derivatives agreement will cover only a portion of the estimated oil and natural gas production attributable to the trust’s 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 PUD Wells, or in the event of SandRidge’s bankruptcy, it may be expensive and time-consuming for the trust to exercise its remedies.”

Pursuant to the derivatives agreement, approximately 61% of the estimated oil production and 60% of the estimated natural gas production attributable to the trust’s royalty interests will be hedged until December 31, 2015. The remaining estimated production of oil and natural gas during that time and all production after such time will not be hedged to protect against the price risks inherent in holding interests in oil 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 trust’s royalty interests that is hedged. The trust will not have any ability to terminate the hedging contracts.

The trust’s counterparty under the derivatives agreement is SandRidge, whose counterparties will be established institutions. In the event that any of the counterparties to the oil and natural gas hedging contracts default on their 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 will have no ability to enter into its own hedges.

The trustee may, under certain circumstances, sell the royalty interests and dissolve the trust. The trust will begin to liquidate following the end of the 20-year period in which the trust owns the Term Royalties.

The royalty interests will be sold and the trust will be dissolved upon the occurrence of certain events. For example, the trustee must sell the royalty interests if unitholders approve the sale or vote to dissolve the trust. The trustee must also sell the royalty interests if cash available for distribution is less than $1.0 million in each of any four consecutive quarters. The sale of all of the royalty interests will result in the dissolution of the trust. Upon the dissolution of the trust, the net proceeds of any such sale will be distributed to the trust unitholders pro rata and unitholders will not be entitled to receive any proceeds from the sale of production from the Underlying Properties following such date.

At the Termination Date, the Term Royalties will automatically revert to SandRidge, while the Perpetual Royalties will be sold and the proceeds will be distributed to the unitholders (including

 

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SandRidge to the extent of any trust units it owns) at the Termination Date or soon thereafter. The price received by the trust by any purchaser of the Perpetual Royalties will depend, among other things, on the prices of oil and natural gas at that time. There can be no assurance that the prices of oil and natural gas will be at levels such that trust unitholders will receive any particular amount of cash in return for the trust’s sale of the Perpetual Royalties. Moreover, SandRidge will have a right of first refusal to purchase the Perpetual Royalties at the Termination Date, which may reduce the inclination of third parties to place a bid, and thereby reduce the value received by the trust in a sale. If the trustee receives a bid from a proposed purchaser other than SandRidge and wants to sell all or part of the Perpetual Royalties to such third party, the trustee will be required to give notice to SandRidge and identify the proposed purchaser and proposed sale price, and other terms of the bid. See “The Trust.”

There has been no public market for the common units and no independent appraisal of the value of the royalty interests has been performed.

The initial public offering price of the common units will be determined by negotiation among SandRidge and the underwriters. Among the factors to be considered in determining the initial public offering price, in addition to prevailing market conditions, will be current and historical oil and natural gas prices, current and prospective conditions in the supply and demand for oil and natural gas, reserve and production quantities estimated for the royalty interests and the trust’s cash distributions prospects. None of SandRidge, the trust or the underwriters will obtain any independent appraisal or other opinion of the value of the royalty interests other than the reserve report prepared by Netherland Sewell.

The trust is managed by a trustee who cannot be replaced except at a special meeting of trust unitholders.

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

 

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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 will be 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. No assurance can be given, however, that the courts in jurisdictions outside of Delaware will give effect to such limitation.

SandRidge may sell trust units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.

After the closing of the offering, SandRidge will hold an aggregate of 6,475,000 common units and 6,325,000 subordinated units. All of the subordinated units will automatically convert into common units at the end of the subordination period. SandRidge has agreed not to sell any trust units for a period of 180 days after the date of this prospectus without the consent of Raymond James & Associates, Inc., acting as representative of the several underwriters. See “Trust Units Eligible for Future Sale—SandRidge Lock-up Agreement.” After such period, SandRidge may sell trust units in the public or private markets, and any such sales could have an adverse impact on the price of the common units or on any trading market that may develop. The trust has granted registration rights to SandRidge, which, if exercised, would facilitate sales of common units by SandRidge to the public. See “Trust Units Eligible for Future Sale—Registration Rights Agreement.”

Conflicts of interest could arise between SandRidge and the trust unitholders.

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

 

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Notwithstanding its drilling obligation to the trust, SandRidge’s interests may conflict with those of the trust and the trust unitholders in situations involving the development, maintenance, operation or abandonment of the Underlying Properties. Additionally, SandRidge may abandon a well that is uneconomic even though such well is still generating revenue for the trust unitholders. Subsequent to fulfilling its drilling obligation, SandRidge may make decisions with respect to expenditures and decisions to allocate resources on projects in other areas that adversely affect the Underlying Properties, including reducing expenditures on these properties, which could cause oil and natural gas production to decline at a faster rate and thereby result in lower cash distributions by the trust in the future.

 

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SandRidge may sell some or all of the Underlying Properties, subject to its obligation not to sell any property relating to the PUD Royalty Interest prior to satisfying its obligation to drill the PUD Wells. Such sale may not be in the best interests of the trust unitholders. Any purchaser may lack SandRidge’s experience in the Mississippian formation or its creditworthiness.

 

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SandRidge may, without the consent of the trust unitholders, require the trust to release royalty interests with an aggregate value to the trust of up to $5.0 million during any 12-month period. These releases will be made only in connection with the sale by SandRidge of the Underlying Properties and are conditioned upon the trust receiving an amount equal to the fair value to the trust of such royalty interests. See “The Underlying Properties—Sale and Abandonment of the Underlying Properties.”

 

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•

SandRidge is permitted under the conveyance agreements creating the royalty interests to enter into new processing and transportation contracts without obtaining bids from or otherwise negotiating with any independent third parties, and SandRidge will deduct from the trust’s proceeds any charges under such contracts attributable to production from the trust properties. Provisions in the conveyance agreements, however, require that charges under future contracts with affiliates of SandRidge relating to processing or transportation of oil and natural gas be comparable to charges prevailing in the area for similar services.

 

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After expiration of a 180-day lock-up period, SandRidge can sell its 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.

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

You will not be entitled to vote on any sale of the Underlying Properties if the Underlying Properties are sold subject to and burdened by the royalty interests and the trust will not receive any proceeds from any such sale. The purchaser would be responsible for all of SandRidge’s obligations relating to the royalty interests on the portion of the Underlying Properties sold, and SandRidge would have no continuing obligation to the trust for those properties. Additionally, SandRidge may enter into farmout or joint venture arrangements with respect to the wells burdened by the trust’s royalty interest. Any purchaser, farmout counterparty or joint venture partner could have a weaker financial position and/or be less experienced in oil and natural gas development and production than SandRidge.

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

Pursuant to the terms of the development agreement, SandRidge will be obligated to drill, or cause to be drilled, the PUD Wells at its own expense. SandRidge is also the operator of 73% of the Producing Wells. SandRidge owns a majority working interest in approximately 75% of the locations on which it expects to drill the PUD Wells, and it expects to operate such wells until completion of its drilling obligation. The conveyances also provide that SandRidge will be obligated to market, or cause to be marketed, the oil and natural gas production related to the Underlying Properties. Additionally, SandRidge will be the counterparty to the trust’s derivatives agreement and will have certain obligations to the trust under the agreement. Due to the trust’s reliance on SandRidge to fulfill these numerous obligations, the value of the trust’s royalty interest and its ultimate cash available for distribution will be highly dependent on SandRidge’s performance.

 

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SandRidge’s ability to perform these obligations will depend on its future financial condition and economic performance and access to capital, which in turn will depend upon the supply and demand for oil and natural gas, prevailing economic conditions and financial, business and other factors, many of which are beyond SandRidge’s control. See “SandRidge Energy, Inc.” and “Where You Can Find More Information” for additional information relating to SandRidge

In the event that SandRidge defaults on its obligation to drill the PUD Wells, the trust’s sole remedy would be to foreclose on the Drilling Support Lien to the extent of SandRidge’s remaining interests in the undeveloped portions of the AMI. The trust would not have any recourse against SandRidge or any of its assets other than SandRidge’s interests in the undeveloped portions of the AMI secured by the Drilling Support Lien. The maximum amount the trust can recover in such a foreclosure action is $166.1 million, which amount will be reduced proportionately as each PUD Well is drilled. There can be no assurance that the value of SandRidge’s interests in the undeveloped portions of the AMI secured by the Drilling Support Lien will be equal to the amount recoverable at any given time, and such interests may be worth considerably less. The process of foreclosing on such collateral may be expensive and time-consuming and delay the drilling and completion of the PUD Wells; such delays and expenses would reduce trust distributions by reducing the amount of proceeds available for distribution. Any amounts actually recovered in a foreclosure action would be applied to completion of SandRidge’s drilling obligation, would not result in any distribution to the trust unitholders and may be insufficient to drill the number of wells needed for the trust to realize the full value of the PUD Royalty Interest. Furthermore, the trust would have to seek a new party to perform the drilling and operations of the wells. The trust may not be able to find a replacement driller or operator, and it may not be able to enter into a new agreement with such replacement party on favorable terms within a reasonable period of time.

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

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

There are a variety of operating risks inherent in oil and natural gas production and associated activities, such as fires, leaks, explosions, mechanical problems, major equipment failures, blowouts, uncontrollable flow of oil and natural gas, water or drilling fluids, casing collapses,

 

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abnormally pressurized formations and natural disasters. The occurrence of any of these or similar accidents that temporarily or permanently halt the production and sale of oil and natural gas at any of the Underlying Properties will reduce trust distributions by reducing the amount of proceeds available for distribution.

Additionally, if any of such risks or similar accidents occur, SandRidge could incur substantial losses as a result of injury or loss of life, severe damage or destruction of property, natural resources and equipment, regulatory investigation and penalties and environmental damage and clean-up responsibility. If SandRidge experiences any of these problems, its ability to conduct operations and perform its obligations to the trust could be adversely affected. While SandRidge intends to obtain and maintain 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.

SandRidge is subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting its operations or expose SandRidge to significant liabilities.

SandRidge’s oil and natural gas exploration, production, transportation and treatment operations are subject to complex and stringent laws and regulations. In order to conduct its operations in compliance with these laws and regulations, SandRidge must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. SandRidge may incur substantial costs in order to maintain compliance with these existing laws and regulations. Further, in light of the explosion and fire on the drilling rig Deepwater Horizon in the Gulf of Mexico, as well as recent incidents involving the release of oil and natural gas and fluids as a result of drilling activities in the United States, there has been a variety of regulatory initiatives at the federal and state level to restrict oil and natural gas drilling operations in certain locations. Any increased regulation or suspension of oil and natural gas exploration and production, or revision or reinterpretation of existing laws and regulations, that arises out of these incidents or otherwise could result in delays and higher operating costs. Such costs or significant delays could have a material adverse effect on SandRidge’s business, financial condition and results of operations. SandRidge must also comply with laws and regulations prohibiting fraud and market manipulations in energy markets. To the extent SandRidge is a shipper on interstate pipelines, it must comply with the tariffs of such pipelines and with federal policies related to the use of interstate capacity.

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

New laws or regulations, or changes to existing laws or regulations may unfavorably impact SandRidge, could result in increased operating costs and have a material adverse effect on SandRidge’s financial condition and results of operations. For example, Congress is currently considering legislation that, if adopted in its proposed form, would subject companies involved in

 

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oil and natural gas exploration and production activities to, among other items, additional regulation of and restrictions on hydraulic fracturing of wells, the elimination of most U.S. federal tax incentives and deductions available to oil and natural gas exploration and production activities, and the prohibition or additional regulation of private energy commodity derivative and hedging activities.

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

The operations of SandRidge are subject to environmental laws and regulations that may result in significant costs and liabilities.

The oil and natural gas exploration and production operations of SandRidge in the Mississippian formation 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 SandRidge’s operations including the acquisition of a permit before conducting drilling; water withdrawal or waste disposal activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and the imposition of substantial liabilities for pollution resulting from operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency (“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 the assessment of administrative, civil or criminal penalties; the imposition of investigatory or remedial obligations; and the issuance of injunctions limiting or preventing some or all of SandRidge’s operations.

There is inherent risk of incurring significant environmental costs and liabilities in the performance of SandRidge’s operations due to its 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, SandRidge could be subject to joint and several strict liability for the removal or remediation of previously released materials or property contamination regardless of whether SandRidge was responsible for the release or contamination or if the operations were not in compliance with all applicable laws at the time those actions were taken. Private parties, including the owners of properties upon which SandRidge’s wells are drilled and facilities where SandRidge’s 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 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 SandRidge to significant liabilities that could have a material adverse effect on its financial condition or results of operations. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require SandRidge to make significant expenditures to attain and maintain

 

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compliance and may otherwise have a material adverse effect on its results of operations, competitive position or financial condition. SandRidge may not be able to recover some or any of these costs from insurance. As a result of the increased cost of compliance, SandRidge may decide to discontinue drilling. Additionally, permitting delays may inhibit SandRidge’s ability to drill the PUD Wells on schedule.

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

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present a danger to public health and the environment. These findings allow the agency to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Accordingly, the EPA has proposed regulations that would require a reduction in emissions of GHGs from motor vehicles and adopted regulations that could trigger permit review for GHG emissions from certain stationary sources. In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA published a final rule that expands its October 2009 final rule on reporting of GHG emissions to include owners and operators of onshore oil and natural gas production, effective December 30, 2010. Both houses of Congress have actively considered legislation to reduce emissions of GHGs and the Obama Administration has indicated its support for legislation to reduce GHG emissions through an emission allowance system. At the state level, almost one-half of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of GHGs. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, SandRidge’s equipment and operations could require SandRidge to incur 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, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if any such effects were to occur, they could have an adverse effect on SandRidge’s assets and operations.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect SandRidge’s services.

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions but is not subject to regulation at the federal level. The EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with results of the study anticipated to be available by late 2012, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. Legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. If new laws

 

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or regulations that significantly restrict or regulate hydraulic fracturing are adopted, such legal requirements could make it more difficult or costly for SandRidge to perform fracturing to stimulate production from the Mississippian formation and thereby affect the determination of whether a well is commercially viable. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that SandRidge is ultimately able to produce in commercial quantities from the Underlying Properties.

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

The trust will be subject to certain of the requirements of the Sarbanes-Oxley Act of 2002 which will require, 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 Internal Revenue Service, or 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. Although the trust does not believe based upon its current activities that it is so treated, a change in current law could cause it to be treated as a corporation for U.S. federal income tax purposes or otherwise subject it to taxation as an entity.

If the trust was treated as a corporation for U.S. federal income tax purposes, it would pay federal income tax on its taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely be required to pay state income tax on its taxable income at the corporate tax rate of such state. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to you without first being subjected to taxation at the entity level. Because a tax would be imposed upon the trust as a corporation, its cash available for distribution to you 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 taxation as a corporation or otherwise subjects it to entity-level taxation for U.S. federal income tax purposes, the minimum quarterly distribution amount and the 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 generally to 3.8% of the lesser of such excess or the individual’s net investment income, which appears to include interest income and royalty income derived from investments such as the trust units as well as any net gain from the disposition of trust units. In addition, absent new legislation extending the current rates, beginning January 1, 2013, the highest marginal U.S. federal income tax rate applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. Moreover, these rates are subject to change by new legislation at any time.

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

The trust will 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, gain, loss and deduction may be reallocated among trust unitholders.

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

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

 

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You will be required to pay taxes on your share of the trust’s income even if you do not receive any cash distributions from the trust.

Because the trust unitholders will be treated as partners to whom the trust will allocate taxable income that could be different in amount than the cash the trust distributes, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of the trust’s taxable income even if you receive no cash distributions from the trust. You may not receive cash distributions from the trust equal to your 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 you sell your trust units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those trust units. Because distributions in excess of your allocable share of the trust’s net taxable income decrease your tax basis in your trust units, the amount, if any, of such prior excess distributions with respect to the trust units you sell will, in effect, become taxable income to you if you sell such trust units at a price greater than your tax basis in those trust units, even if the price you receive is less than your 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. Please read “U.S. Federal Income Tax Considerations—Disposition of Trust Units—Recognition of Gain or Loss” for a further discussion of the foregoing.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning the trust units that may result in adverse tax consequences to them.

Investment in trust units by tax-exempt entities, such as individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons may be required to file U.S. federal income tax returns and pay tax on their share of the trust’s taxable income. If you are a tax exempt entity or a non-U.S. person, you should consult a tax advisor before investing in the trust units.

The trust will treat 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 will adopt positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of trust units and could have a negative impact on the value of the trust units or result in audit adjustments to your tax returns. Please read “U.S. Federal Income Tax Considerations—Tax Consequences of Trust Unit Ownership—Section 754 Election.”

The trust will prorate its items of income, gain, loss and deduction between transferors and transferees of the trust units each month based upon the ownership of the trust units on the first day of each month, 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 will generally prorate its items of income, gain, loss and deduction between transferors and transferees of the trust units each month based upon the ownership of the trust

 

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units on the first day of each month, instead of on the basis of the date a particular trust unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations, and, accordingly, the trust’s counsel is unable to opine as to the validity of this method. Recently, however, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method the trust will adopt. 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. Please read “U.S. Federal Income Tax Considerations—Disposition of Trust Units—Allocations Between Transferors and Transferees.”

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, gain, loss or deduction with respect to those trust units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those trust units could be fully taxable as ordinary income. The trust’s counsel has not rendered an opinion regarding the treatment of a unitholder where trust units are loaned to a short seller to cover a short sale of trust units; therefore, trust unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from loaning their trust units.

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

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

The sale or exchange of 50% or more of the trust’s capital and profits interests during any twelve-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 twelve-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.

 

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The trust’s termination would, among other things, result in the closing of its taxable year for all trust unitholders, which would result in the trust filing two tax returns (and the trust unitholders could receive two Schedules K-1) for one calendar year. The IRS has recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership will be required to provide only a single Schedule K-1 to unitholders for the tax year in which the termination occurs. In the case of a unitholder reporting on a taxable year other than a calendar year ending December 31, the closing of the trust’s taxable year may also result in more than 12 months of the trust’s taxable income being includable in his 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.

Among the changes contained in President Obama’s Budget Proposal for Fiscal Year 2011 is the elimination of certain key U.S. federal income tax preferences relating to oil and natural gas exploration and production. The President’s budget proposes to eliminate certain tax preferences applicable to taxpayers engaged in the exploration or production of natural resources. Specifically, the budget proposes to repeal the deduction for percentage depletion with respect to wells, including interests such as the Perpetual Royalty Interests, in which case only cost depletion would be available.

 

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This prospectus and the documents incorporated by reference contain forward-looking statements. Such forward-looking statements are based on assumptions and beliefs that the trust and SandRidge believe to be reasonable; however, assumed facts almost always vary from actual results, and the differences between assumed facts and actual results can be material, depending upon the circumstances. Where the trust or SandRidge expresses an expectation or belief as to future results, that expectation or belief is expressed in good faith and based on assumptions believed to have a reasonable basis. It cannot be assured, however, that the stated expectation or belief will occur or be achieved or accomplished. All statements other than statements of historical facts included or incorporated by reference in this prospectus, including, without limitation, statements regarding the proved oil and natural gas reserves associated with the Underlying Properties, the trust’s or SandRidge’s future financial position, business strategy, budgets, pending acquisitions, recent acquisitions and divestitures, project costs and plans and objectives for future operations, including the information under the heading “Target Distributions and Subordination and Incentive Thresholds,” statements pertaining to future development activities and costs, and other statements in this prospectus that are prospective and constitute forward-looking statements are forward-looking statements.

The words “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal,” “will,” “should” and “intend” and similar expressions will generally identify forward-looking statements. Our forward-looking statements, whether written or oral, are expressly qualified by these cautionary statements and any other cautionary statements that may accompany those statements. In addition, neither the trust nor SandRidge undertakes an obligation to update or revise any forward-looking statements to reflect events or circumstances after the date of this prospectus.

With this in mind, you should consider the risks discussed under the heading “Risk Factors” in this prospectus, as well as those contained in SandRidge’s Annual Report on Form 10-K for the year ended December 31, 2009, its Quarterly Reports on Form 10-Q for the periods ended March 31, 2010, June 30, 2010 and September 30, 2010 and other disclosures about SandRidge that are included in or incorporated by reference into this prospectus.

 

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USE OF PROCEEDS

The trust is offering all of the common units to be sold in this offering. Assuming no exercise of the underwriters’ over-allotment option and an initial public offering price of $             per common unit, the estimated net proceeds of this offering will be approximately $             million, after deducting underwriting discounts and commissions and offering expenses. The trust will deliver all of the net proceeds to SandRidge’s wholly-owned subsidiary, as partial consideration for the conveyance of the royalty interests.

At the initial closing, 1,875,000 common units will be issued and retained by the trust and will be used to satisfy (if necessary) the over-allotment option granted to the underwriters. If the over-allotment option is exercised, the trust will sell to the underwriters such number of the retained units as is necessary to satisfy the over-allotment option, and will then deliver the net proceeds of such sale, together with any remaining unsold units, to one or more SandRidge subsidiaries as partial consideration for the conveyance of the royalty interests. If the over-allotment option is not exercised by the underwriters, the retained units will be delivered to SandRidge subsidiaries, as partial consideration for the conveyance of the royalty interests, promptly following the 30th day after the initial closing.

SandRidge intends to use the proceeds received from the offering to repay borrowings under its credit facility and for general corporate purposes, which may include the funding of the drilling obligation. As of December 31, 2010, the outstanding balance on SandRidge’s credit facility, which matures in 2014, was approximately $340 million, and the weighted average interest rate of the credit facility was 2.51%. Borrowings under the credit facility in the past year were incurred by SandRidge for general corporate purposes, including to fund its capital expenditures program and a portion of the consideration used for its acquisition of Arena Resources, Inc., which closed in July 2010.

 

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SANDRIDGE ENERGY, INC.

SandRidge is a publicly traded, independent oil and natural gas company concentrating on development and production activities related to the exploitation of its significant holdings in West Texas and the Mid-Continent area of Oklahoma and Kansas. As of December 31, 2010, its market capitalization was approximately $3.0 billion and, as of December 31, 2009, it had total estimated net proved reserves of 1,312.2 Bcfe. SandRidge has approximately 780,000 net acres leased in the Mississippian formation and plans to devote a significant portion of its future capital budget to increasing its acreage and oil and natural gas production in this area. As of December 31, 2010, SandRidge was operating seven rigs in the Mississippian formation. SandRidge also owns and operates other interests in the Mid-Continent, Cotton Valley Trend in East Texas, Gulf Coast and Gulf of Mexico.

SandRidge’s principal executive offices are located at 123 Robert S. Kerr Avenue, Oklahoma City, Oklahoma 73102 and its telephone number is (405) 429-5500. Its website is http://www.sandridgeenergy.com.

The trust units do not represent interests in or obligations of SandRidge.

 

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THE TRUST

The trust is a statutory trust created under the Delaware Statutory Trust Act in December 2010. The business and affairs of the trust will be managed by The Bank of New York Mellon Trust Company, N.A., as trustee. In addition, the Corporation Trust Company will act as Delaware trustee of the trust. The Delaware trustee will have only minimal rights and duties as are necessary to satisfy the requirements of having a trustee in Delaware who will accept service of process on the trust under the Delaware Statutory Trust Act. Although SandRidge will operate a substantial number of the Underlying Properties, SandRidge will have no ability to manage or influence the management of the trust (except through its limited voting rights as a holder of trust units) and, to the fullest extent permitted by law, will owe no fiduciary duties to the trust or the unitholders.

The trustee can authorize the trust to borrow money to pay trust administrative or incidental expenses that exceed cash held by the trust. The trustee may authorize the trust to borrow from the trustee as a lender provided the terms of the loan are fair to the trust unitholders. The trustee may also deposit funds awaiting distribution in an account with itself, if the interest paid to the trust at least equals amounts paid by the trustee on similar deposits, and make other short term investments with the funds distributed to the trust. The trustee may also hold funds awaiting distribution in a non-interest bearing account.

The trust will be responsible for paying all legal, accounting, tax advisory, engineering, printing costs and other administrative and out-of-pocket expenses incurred by or at the direction of the trustee or the Delaware trustee, including tax return and Schedule K-1 preparation and mailing costs, independent auditor fees and registrar and transfer agent fees. The trust will also be responsible for paying other expenses incurred as a result of being a publicly traded entity, including costs associated with annual and quarterly reports to unitholders. These trust administrative expenses are anticipated to aggregate approximately $900,000 per year, although such costs could be greater or less depending on future events that cannot be predicted. Included in the annual estimate is an annual administrative fee of $150,000 for the trustee, which may be adjusted beginning on the fifth anniversary of the trust as provided in the trust agreement, an annual administrative fee of $2,300 for the Delaware trustee and an annual fee of $200,000 payable to SandRidge pursuant to the terms of the administrative services agreement. The trustee will also receive a one-time acceptance fee of $10,000. These costs will be deducted by the trust before distributions are made to trust unitholders. The trustee intends to withhold $1.0 million from the first distribution to unitholders to establish a cash reserve available to the trustee to pay trust administrative expenses.

Formation Transactions

At or prior to the closing of the offering, SandRidge’s wholly owned subsidiaries, SandRidge Exploration and Production, LLC (“SandRidge E&P”) and                         , a                      corporation (“                    ”), will convey to the trust a 90% royalty interest in the Producing Wells and a 50% royalty interest in the PUD Wells.

The 90% royalty interest in the Producing Wells will consist of a term royalty interest entitling the trust to receive 45% of the proceeds from the sale of oil and natural gas production attributable to SandRidge’s net revenue interest in the Producing Wells (after deducting post-production costs and any applicable taxes) for a period of 20 years commencing on January 1, 2011 (the “Term PDP Royalty”) and a perpetual royalty interest entitling the trust to receive 45% of the proceeds from the sale of oil and natural gas production attributable to SandRidge’s net revenue interest in the Producing Wells (after deducting post-production costs and any applicable taxes) (the “Perpetual PDP Royalty”).

 

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The 50% royalty interest in the PUD Wells will consist of a term royalty interest entitling the trust to receive 25% of the proceeds from the sale of the production of oil and natural gas attributable to SandRidge’s net revenue interest in the PUD Wells (after deducting post-production costs and any applicable taxes) for a period of 20 years commencing on January 1, 2011 (the “Term PUD Royalty”) and a perpetual royalty interest entitling the trust to receive 25% of the proceeds from the sale of oil and natural gas production attributable to SandRidge’s net revenue interest in the PUD Wells (after deducting post-production costs and any applicable taxes) (the “Perpetual PUD Royalty”).

The Term PDP Royalty and the Term PUD Royalty are collectively referred to as the “Term Royalties,” while the Perpetual PDP Royalty and the Perpetual PUD Royalty are collectively referred to as the “Perpetual Royalties.” The Perpetual Royalties will be conveyed directly from SandRidge E&P to the trust. The Term Royalties will be conveyed from SandRidge E&P to              in exchange for a demand note in the principal amount of approximately $         , and then assigned from                     to the trust. In exchange for the Term Royalties and the Perpetual Royalties, the trust will issue to SandRidge E&P, 4,600,000 common units and 6,325,000 subordinated units, and will deliver [all] of the net proceeds of this offering to         , which will use such proceeds to repay the demand note to SandRidge E&P. See “Use of Proceeds.”

1,875,000 common units will be issued and retained by the trust at the initial closing, to be used to satisfy (if necessary) the over-allotment option granted to the underwriters. If the over-allotment option is exercised, the trust will sell to the underwriters such number of the retained units as is necessary to satisfy the over-allotment option, and will then deliver the net proceeds of such sale, together with any remaining unsold units, to one or more SandRidge subsidiaries as partial consideration for the conveyance of the royalty interests. If the over-allotment option is not exercised by the underwriters, the retained units will be delivered to SandRidge subsidiaries, as partial consideration for the conveyance of the royalty interests, promptly following the 30th day after the initial closing.

The trust will sell the 12,500,000 common units offered hereby to the public, representing a 49% interest in the trust.

SandRidge and the trust will enter into several agreements in connection with the conveyance of the royalty interests, including: (1) a development agreement, which sets forth SandRidge’s drilling obligation to the trust with respect to the PUD Wells, (2) a derivatives agreement, pursuant to which SandRidge will provide the trust with the benefit of certain hedging contracts entered into between SandRidge and third parties and (3) an administrative services agreement, which outlines SandRidge’s duty to provide administrative services to the trust. These agreements are described in more detail below.

Termination Date; Liquidation

The trust will dissolve and begin to liquidate on the Termination Date, which is December 31, 2030, and will soon thereafter wind up its affairs and terminate. At the Termination Date, the Term Royalties will automatically revert to SandRidge, while the Perpetual Royalties will be sold and the proceeds will be distributed to the unitholders at the Termination Date or soon thereafter, but only after the trust has paid, or made reasonable provision for payment of, all liabilities of the trust. See “Description of the Royalty Interests—Sale of the Perpetual Royalties.” Any additional cash held in reserve by the trustee will also be distributed to unitholders.

 

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Development Agreement

In connection with the closing of this offering, the trust will enter into a development agreement with SandRidge that will obligate SandRidge to drill, or cause to be drilled, all of the PUD Wells by December 31, 2014. In the event of delays, SandRidge will have until December 31, 2015 to fulfill its drilling obligation. SandRidge E&P will grant to the trust the Drilling Support Lien, covering SandRidge E&P’s interest in the AMI (except the Producing Wells and any other wells that are already producing and not subject to the royalty interests) in order to secure the estimated amount of the drilling costs for the trust’s interests in the PUD Wells. The amount obtained by the trust pursuant to the Drilling Support Lien may not exceed $166.1 million. As SandRidge fulfills its drilling obligation over time, the total dollar amount that may be recovered will be proportionately reduced and the completed PUD Wells will be released from the lien.

Under the development agreement, a PUD Well is calculated based on the perforated length of the well (measured from the first perforation along the measured depth to the last perforation along the measured depth) and SandRidge’s net revenue interest in such well. SandRidge will be credited for drilling one full development well if the perforated length of the well is equal to or greater than 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, SandRidge will receive partial credit equal to the fraction calculated by dividing the well’s perforated length by 2,500 feet. SandRidge will not receive any extra credit for wells with perforated lengths in excess of 2,500 feet.

For wells in which SandRidge has a net revenue interest greater than or less than 57.0%, SandRidge will receive credit for such well in the proportion that its net revenue interest in the well bears to 57.0%.

Accordingly, for example, if SandRidge drilled one well in which it has a 80% net revenue interest, and such well was drilled to a perforated length of 2,500 feet, such well would count for purposes of the development agreement as 1.404 PUD Wells (i.e., 2,500/2,500 X 80%/57.0%). If, on the other hand, SandRidge drilled one well in which it has a 50% net revenue interest, and such well was drilled to a perforated length of 2,000 feet, such well would count for purposes of the development agreement as only 0.702 PUD Wells (i.e., 2,000/2,500 X 50%/57.0%).

Given that SandRidge’s actual net revenue interest in each PUD Well may be greater than or less than 57.0% and the perforated length of each well drilled may be less than 2,500 feet, SandRidge may be required to drill more or less than 123 wells in order to fulfill its drilling obligation.

SandRidge is required to adhere to a reasonably prudent operator standard, which requires that it act with respect to the Underlying Properties as it would act with respect to its own properties, disregarding the existence of the royalty interests as burdens affecting such property. Accordingly, SandRidge expects that average perforated interval lengths for future wells will be generally consistent with the perforated interval length of the completed Producing Wells within the AMI and other Mississippian wells outside of the AMI that have been drilled exclusively for SandRidge’s account. However, due to the complexity of well completions, it may be appropriate in some instances to complete wells with shorter perforated interval lengths. In fact, completions to date reflect that greater than anticipated reserve recoveries may be achieved from producing perforated interval lengths substantially shorter than 2,500 feet. For example, the four Producing Wells completed to less than 2,500 feet of perforated interval length have an average estimated ultimate reserve recovery that exceeds the median estimated ultimate reserve recovery for all Producing Wells completed to date.

 

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The PUD reserves reflected in the reserve report assume that SandRidge will drill and complete the 123 PUD Wells with the same completion technique, and bearing the same capital and other costs, as the 37 Producing Wells completed to date. These 37 Producing Wells produce from perforated interval lengths contributing to production ranging from less than 500 feet to more than 4,500 feet. The average perforated interval length contributing to production of the 37 Producing Wells is approximately 3,900 feet, which is longer than the 2,500 foot perforated interval length upon which the definition of one full development well is based.

Because (a) the average perforated interval length of the wells assumed for purposes of calculating the PUD reserves is longer than the minimum perforated interval length required for SandRidge to receive credit for one full development well and (b) there is no guarantee that wells drilled with shorter perforated interval lengths will achieve the same reserve recoveries as wells drilled with longer perforated interval lengths, you may not receive the benefit of the total amount of PUD reserves reflected in the reserve report, notwithstanding the fact that SandRidge has satisfied its drilling obligation. In addition to its obligation to act as a reasonably prudent operator, SandRidge’s significant retained economic interest in the trust and its opportunity to earn incentive distributions provide it with substantial incentives to pursue well completions with perforated interval lengths greater than 2,500 feet to the extent necessary to optimize reserve recoveries for the benefit of the trust.

SandRidge may, and anticipates that it will, rely on third-party operators to fulfill a portion of its drilling obligation.

SandRidge is required to complete and equip each development well that reasonably appears to SandRidge to be capable of producing oil and natural gas in quantities sufficient to pay completion, equipping and operating costs. In making such decisions, SandRidge is required to act as a reasonably prudent operator in the AMI under the same or similar circumstances as it would act if it were acting with respect to its own properties, disregarding the existence of the royalty interests as burdens affecting such property. See “The Underlying Properties—Sale and Abandonment of Underlying Properties.” The trust will not bear any of the costs of drilling and completing the PUD Wells that SandRidge drills or causes to be drilled.

SandRidge will covenant and agree not to drill and complete, and will not permit any other person within its control to drill and complete, any well in the AMI other than a development well until such time as SandRidge has met its commitment to drill the PUD Wells. Once SandRidge has completed its drilling obligation, the trustee will be required to release the Drilling Support Lien in full. Upon the trustee’s release of the Drilling Support Lien, SandRidge will further agree not to drill and complete, and will not permit any other person within its control to drill and complete, any well on the lease acreage that will have a perforated segment that will be within 660 feet of any perforated interval of a PUD Well or Producing Well in the AMI.

Hedging Arrangements

At the closing of this offering, SandRidge will enter into a derivatives agreement with the trust to provide the trust with the benefit of certain hedging contracts entered into between SandRidge and third parties. Under the agreement, SandRidge will pay the trust amounts it receives from its counterparties under the hedge contracts, and the trust will be required to pay SandRidge any amounts that SandRidge is required to pay its counterparties under such hedge contracts. The trust will not bear any costs related to the establishment of these arrangements. Volumes hedged under the derivatives agreement will include production from both the Producing Wells and the PUD Wells. During the term of the derivatives agreement, SandRidge will determine the amounts due to (or from) the trust under the derivatives agreement. While the derivatives agreement is expected to

 

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limit the downside risk of oil and natural gas price declines, it 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 trust’s royalty interests that is hedged.

The trust’s counterparty under the derivatives agreement is SandRidge, whose counterparties will be established institutions. In the event that any of the counterparties to the oil and natural gas hedging contracts default on their obligations to make payments under such contracts, the cash distributions to the trust unitholders could 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 pay the trust to the extent of payment defaults by 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. The trust will have no ability to enter into its own hedges.

Pursuant to the derivatives agreement, approximately 61% of the estimated oil production and 60% of the estimated natural gas production attributable to the trust’s royalty interests will be hedged until December 31, 2015. The remaining estimated production of oil and natural gas during that time and all production after such time will not be hedged.

The following table illustrates SandRidge’s current expectation for the percentage of oil and natural gas volumes attributable to the trust’s royalty interest that are planned to be hedged pursuant to the hedging contracts SandRidge plans to enter into with third parties before the closing of this offering. The percentages of oil and natural gas volumes shown in the table reflect SandRidge’s current expectation but may change.

 

Year		Percentage of Oil Volumes Expected to be Hedged				Percentage of Natural Gas Volumes Expected to be Hedged
2011			80	%			90	%
2012			70	%			65	%
2013			60	%			50	%
2014			50	%			50	%
2015			50	%			50	%

Administrative Services Agreement

In connection with the closing of this offering, the trust will enter into an administrative services agreement with SandRidge pursuant to which SandRidge will provide the trust with certain accounting, tax preparation, bookkeeping and informational services related to the royalty interests. In return for these services, the trust will pay to SandRidge, on a quarterly basis, a total annual fee of $200,000. SandRidge will also be entitled to receive reimbursement for its actual out-of-pocket fees, costs and expenses incurred in connection with the provision of any of the services under the agreement.

The administrative services agreement will terminate upon the earliest to occur of: (i) December 31, 2030, (ii) the date that all of the royalty interests have been terminated or are no longer held by the trust, (iii) with respect to services to be provided with respect to any Underlying Properties being 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 by SandRidge and the trustee.

 

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TARGET DISTRIBUTIONS AND SUBORDINATION AND INCENTIVE THRESHOLDS

SandRidge will create the royalty interests through conveyances to the trust of royalty interests in specified oil and natural gas properties in the AMI. The PDP Royalty Interest will entitle the trust to receive 90% of the proceeds (exclusive of any production or development costs but after deducting post-production costs and any applicable taxes) from the sale of oil and natural gas production attributable to SandRidge’s net revenue interest in the Producing Wells for a period of 20 years commencing on January 1, 2011. The PUD Royalty Interest will entitle the trust to receive 50% of the proceeds (exclusive of any production or development costs but after deducting post-production costs and any applicable taxes) from the sale of future production of oil and natural gas attributable to SandRidge’s net revenue interest in the PUD Wells for a period of 20 years commencing on January 1, 2011.

The amount of trust revenues and cash distributions to trust unitholders will depend on:

 

•

the timing of initial production from the PUD Wells;

 

•

oil and natural gas prices received;

 

•

the volume of oil and natural gas produced and sold;

 

•

amounts realized under hedging arrangements;

 

•

post-production costs and any applicable taxes; and

 

•

the trust’s general and administrative expenses.

SandRidge has calculated quarterly target levels of cash distributions for the life of the trust. Such target distribution levels are set forth on Annex B to this prospectus. The target distributions were prepared by SandRidge on a cash basis based on assumptions of production volumes, pricing and other assumptions that are described below in “—Significant Assumptions Used to Calculate the Target Distributions.” The production forecasts are estimates prepared by Netherland Sewell and have been used to calculate target distributions. Actual cash distributions may vary from those presented. SandRidge will pay to the trust each quarter an amount equal to the trust’s royalty interest in the proceeds of production from the Underlying Properties received during the calendar quarter most recently ended (after deducting post-production costs and any applicable taxes). The trust, in turn, will make quarterly cash distributions of substantially all of its quarterly cash receipts, after deduction of fees and expenses for the administration of the trust, to holders of trust units.

The first distribution, which will cover the first and second quarters of 2011, is expected to be made on or about August 30, 2011 to record unitholders as of August 15, 2011. The trustee intends to withhold $1.0 million from the first distribution to establish a cash reserve available to pay trust administrative expenses. If the trustee uses such cash reserve to pay for trust administrative expenses, the reserve must be replenished before any further quarterly distributions are made to trust unitholders. Due to the timing of the payment of production proceeds to the trust, the trust expects that the first distribution will include sales for oil and natural gas for five months. Thereafter, quarterly distributions will generally include royalties on sales of oil and natural gas for three months, including the first two months of the quarter just ended as well as the last month of the immediately preceding quarter. Because payments to the trust will be generated by depleting assets and production from the Underlying Properties will diminish over time, a portion of each distribution will represent a return of your original investment.

In order to provide support for cash distributions on the common units, SandRidge has agreed to subordinate 6,325,000 of the trust units it will retain following this offering, which will constitute 25% of the outstanding trust units. The subordinated units will be entitled to receive

 

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pro rata distributions from the trust if and to the extent there is sufficient cash to provide a cash distribution on the common units that is no less than the applicable quarterly subordination threshold. If there is not sufficient cash to fund such a distribution on all trust units, the distribution to be made with respect to the subordinated units will be reduced or eliminated in order to make a distribution, to the extent possible, of up to the subordination threshold amount on the common units. Each applicable quarterly subordination threshold is 20% below the target distribution level for the corresponding quarter, as reflected on Annex B. In exchange for agreeing to subordinate these trust units, and in order to provide additional financial incentive to SandRidge to perform its drilling obligation and operations on the Underlying Properties in an efficient and cost-effective manner, SandRidge will be 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 during the subordination period exceeds the target distribution for such quarter by more than 20%. SandRidge’s right to receive incentive distributions will terminate upon the expiration of the subordination period.

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 at the end of the fourth full calendar quarter following SandRidge’s satisfaction of its drilling obligation to the trust. The trust currently expects that SandRidge will complete its drilling obligation on or before December 31, 2014 and that, accordingly, the subordinated units would convert into common units on or before December 31, 2015. In the event of delays, SandRidge will have until December 31, 2015 under the development agreement to drill all the PUD Wells, in which event the subordinated units would convert into common units on or before December 31, 2016.

SandRidge’s management has prepared the prospective financial information set forth below to present the projected cash distributions to the holders of the trust units based on the estimates and assumptions described below. The accompanying prospective financial information was not prepared with a view toward complying with the guidelines of the SEC or the guidelines established by the American Institute of Certified Public Accountants with respect to preparation and presentation of prospective financial information, but, in the view of SandRidge’s management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the expected course of action and the expected future financial performance of the royalty interests. However, this information is based on estimates and judgments, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

The prospective financial information included in this prospectus has been prepared by, and is the responsibility of, SandRidge’s management. PricewaterhouseCoopers LLP, the trust’s and SandRidge’s independent registered public accountant, has neither examined, compiled nor performed any procedures with respect to the accompanying prospective financial information and, accordingly, PricewaterhouseCoopers LLP does not express an opinion or any other form of assurance with respect thereto. The reports of PricewaterhouseCoopers LLP included in this prospectus relate to the historical Statement of Assets and Trust Corpus of the trust and the historical Statements of Revenues and Direct Operating Expenses of the Underlying Properties. The reports do not extend to the prospective financial information and should not be read to do so.

The following table sets forth the target distributions and subordination and incentive thresholds for each calendar quarter through the fourth quarter of 2016. The effective date of the conveyance of the royalty interests is January 1, 2011, which means that the trust will receive credit for the proceeds of production attributable to the royalty interests from that date even though the trust properties will not be conveyed to the trust until the closing of this offering.

 

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Period		Subordination Threshold(1)				Target Distribution				Incentive Threshold(1)
						(per unit)
2011:
Second Quarter(2)		$	0.83			$	1.04			$	1.25
Third Quarter			0.52				0.65				0.78
Fourth Quarter			0.50				0.62				0.75
2012:
First Quarter			0.52				0.65				0.78
Second Quarter			0.55				0.69				0.83
Third Quarter			0.58				0.73				0.87
Fourth Quarter			0.58				0.72				0.86
2013:
First Quarter			0.60				0.74				0.89
Second Quarter			0.61				0.77				0.92
Third Quarter			0.61				0.77				0.92
Fourth Quarter			0.61				0.76				0.92
2014:
First Quarter			0.63				0.79				0.95
Second Quarter			0.67				0.84				1.01
Third Quarter			0.71				0.89				1.07
Fourth Quarter			0.73				0.92				1.10
2015:
First Quarter			0.69				0.87				1.04
Second Quarter			0.64				0.80				0.96
Third Quarter			0.60				0.75				0.89
Fourth Quarter			0.56				0.70				0.84
2016:
First Quarter			0.54				0.67				0.80
Second Quarter			0.51				0.64				0.77
Third Quarter			0.49				0.61				0.74
Fourth Quarter			0.47				0.59				0.71

 

(1)	The subordination and incentive thresholds terminate after the fourth full calendar quarter following SandRidge’s completion of its drilling obligation.

(2)	Includes proceeds attributable to the first five months of production from January 1, 2011 to May 31, 2011, and gives effect to $1.0 million of reserves for general and administrative expenses withheld by the trustee and additional administrative costs relating to the formation of the trust.

SandRidge has prepared the projected operational and financial information set forth above and below in order to present the target distributions attributable to the oil and natural gas sales volumes reflected in the reserve report attached hereto as Annex A. The target distributions, in the view of SandRidge’s management, were prepared on a reasonable basis based on the assumptions outlined in “—Significant Assumptions Used to Calculate the Target Distributions.”

The projections outlined below should not be relied upon as being necessarily indicative of future results. Neither SandRidge nor the trust undertakes any obligation to update the financial forecast to reflect events or circumstances after the date of this prospectus and readers of this prospectus are cautioned not to place undue reliance on the projected financial information.

The projections and assumptions on which they are based are subject to significant uncertainties, many of which are beyond the control of SandRidge and the trust. Actual cash

 

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distributions to trust unitholders, therefore, could vary significantly based upon events or conditions occurring that are different from the events or conditions assumed to occur for purposes of these projections.

Cash distributions to trust unitholders will be particularly sensitive to fluctuations in oil and natural gas prices and production volumes. See “—Sensitivity of Target Distributions to Oil and Natural Gas Prices and Volumes,” which shows estimated effects to cash distributions through March 31, 2012 from changes in assumed realized oil and natural gas prices as well as changes in estimated production volumes. As a result of typical production declines for oil and natural gas properties, production estimates generally decrease from year to year. However, the production estimates included in the table below reflect that these declines are expected to be offset by additional production from PUD Wells as they are completed and begin to produce. The timing of the completion of, and the amount of production attributable to, the PUD Wells are substantially dependent on SandRidge executing its drilling plans with respect to the drilling and completion of the PUD Wells in a manner substantially similar to those underlying the assumptions used in establishing these target distributions. In addition, the completion of SandRidge’s drilling obligation will depend, in part, on the completion of drilling for certain PUD Wells by third parties, over whom SandRidge has no control, in a manner consistent with the assumptions used in establishing these target distributions. Please see “Risk Factors” for risks relating to the timing of drilling and amount of production attributable to the PUD Wells. As a result of these factors, the target distributions shown in the tables below are not necessarily indicative of distributions for future years.

Because payments to the trust will be generated by depleting assets and production from the Underlying Properties will diminish over time, a portion of each distribution will represent a return of your original investment. See “Risk Factors—The oil and natural gas reserves estimated to be attributable to the Underlying Properties of the trust are depleting assets and production from those reserves will diminish over time. Furthermore, the trust is precluded from acquiring other oil and gas properties or royalty interests to replace the depleting assets and production.”

 

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The table below presents the calculation of the target distributions for each quarter through and including the quarter ending March 31, 2012.

 

Period		June 30, 2011(1)				September 30, 2011				December 31, 2011				March 31, 2012
		(In thousands, except volumetric and per unit data)
Estimated production from trust properties
Oil sales volumes (MBbl)			262				154				146				149
Natural gas sales volumes (MMcf)			1,661				959				910				921
Total sales volumes (MBoe)			539				314				298				302
% PDP sales volumes			86	%			69	%			63	%			56	%
% PUD sales volumes			14	%			31	%			37	%			44	%
% Oil volumes			49	%			49	%			49	%			49	%
% Natural gas volumes			51	%			51	%			51	%			51	%
Commodity price and derivative contract positions
NYMEX futures price(2)
Oil ($/Bbl)		$	89.23			$	90.86			$	91.24			$	91.35
Natural gas ($/MMBtu)		$	4.10			$	4.25			$	4.43			$	4.98
Assumed realized unhedged price(3)
Oil ($/Bbl)		$	84.23			$	85.86			$	86.24			$	86.35
Natural gas ($/Mcf)		$	3.75			$	3.89			$	4.06			$	4.55
Assumed realized hedged weighted price*
Oil ($/Bbl)*
Natural gas ($/Mcf)*
Percent of oil volumes hedged*
Oil hedged price ($/Bbl)*
Percent of natural gas volumes hedged*
Natural gas hedged price ($/MMBtu)*
Estimated cash available for distribution
Oil sales revenues		$	22,088			$	13,195			$	12,601			$	12,858
Natural gas sales revenues			6,231				3,730				3,693				4,194
Realized gains (losses) from derivative contracts*
Operating revenues and realized gains (losses) from derivative contracts		$	28,319			$	16,926			$	16,293			$	17,052
Production taxes			348				199				189				194
Ad valorem taxes			140				84				81				84
Trust administrative expenses			1,460	(4)			225				225				226
Total trust expenses			1,948				507				494				504
Cash available for distribution		$	26,371			$	16,418			$	15,799			$	16,548
Trust units outstanding			25,300				25,300				25,300				25,300
Target distribution per trust unit		$	1.04			$	0.65			$	0.62			$	0.65
Subordination threshold per trust unit		$	0.83			$	0.52			$	0.50			$	0.52
Incentive threshold per trust unit		$	1.25			$	0.78			$	0.75			$	0.78

 

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Period		June 30, 2011(1)				September 30, 2011				December 31, 2011				March 31, 2012
		(In thousands, except volumetric and per unit data)
If actual cash exceeds targeted by 20%		$	31,645			$	19,702			$	18,959			$	19,858
Cash necessary to meet incentive threshold			31,645				19,702				18,959				19,858
Excess cash available for incentive distributions			—				—				—				—
Incentive distributions to unitholders		$	—			$	—			$	—			$	—
Incentive distributions to SandRidge		$	—			$	—			$	—			$	—
If actual cash available exceeds targeted by 40%		$	36,920			$	22,985			$	22,119			$	23,167
Cash necessary to meet incentive threshold			31,645				19,702				18,959				19,858
Excess cash available for incentive distributions			5,274				3,284				3,160				3,310
Incentive distributions to unitholders		$	2,637			$	1,642			$	1,580			$	1,655
Incentive distributions to SandRidge		$	2,637			$	1,642			$	1,580			$	1,655
If actual cash available falls short of projected by 20%		$	21,097			$	13,135			$	12,640			$	13,238
Cash available for distribution to common units			15,823				9,851				9,480				9,929
Cash necessary to meet common unit subordination threshold			15,823				9,851				9,480				9,929
Cash short of subordination threshold		$	—			$	—			$	—			$	—
Reduction in distribution to subordinated units to support subordination threshold			—				—				—				—
Cash distributions to common unitholders		$	15,823			$	9,851			$	9,480			$	9,929
Cash distributions to subordinated units		$	5,274			$	3,284			$	3,160			$	3,310
If actual cash available falls short of projected by 40%		$	15,823			$	9,851			$	9,480			$	9,929
Cash available for distribution to common units			11,867				7,388				7,110				7,447
Cash necessary to meet common unit subordination threshold			15,823				9,851				9,480				9,929
Cash short of subordination threshold		$	(3,956	)		$	(2,463	)		$	(2,370	)		$	(2,482	)
Reduction in distribution to subordinated units to support subordination threshold			3,956				2,463				2,370				2,482
Cash distributions to common unitholders		$	15,823			$	9,851			$	9,480			$	9,929
Cash distributions to subordinated units		$	—			$	—			$	—			$	—

 

(1)	Includes proceeds attributable to the first five months of production from January 1, 2011 to May 31, 2011.

(2)	Average NYMEX futures prices, as reported December 17, 2010. For a description of the effect of lower NYMEX prices on projected cash distributions, please read “—Sensitivity of Target Distributions to Changes in Oil and Natural Gas Prices and Volumes.”

(3)	Sales price net of forecasted quality, Btu content, transportation costs, and marketing costs. For information about the estimates and assumptions made in preparing the table above, see “—Significant Assumptions Used to Calculate the Target Distributions.”

(4)	Includes trustee cash reserve of $1.0 million and additional administrative costs relating to the formation of the trust.

*

Information with respect to assumed realized hedged weighted price for oil ($/Bbl) and natural gas ($/Mcf), percent of oil volumes hedged, oil hedged price ($/Bbl), percent of natural gas volumes hedged, natural gas hedged price ($/MMBtu), and realized gains (losses) from derivative contracts will be provided after hedging arrangements are finalized with respect to estimated future production attributable to the royalty interests.

 

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Significant Assumptions Used to Calculate the Target Distributions

In preparing the target distributions and subordination and incentive threshold tables above and sensitivity tables below, the revenues and expenses of the trust were calculated based on the terms of the conveyances creating the trust’s royalty interests using the following assumptions and those set forth above under “Target Distributions and Subordination and Incentive Thresholds.” These calculations are described under “Description of the Royalty Interests.”

Production Estimates.    Production estimates for each of the quarters during the life of the trust are based on the reserve report. The estimates of reserves and production relating to the Underlying Properties and the royalty interests included in the reserve report have been made in accordance with the SEC’s rules for reserve reporting. Production attributable to the royalty interests from the Underlying Properties for the 12-months ending December 31, 2011 is estimated to be 1,249 MBoe. However, due to the timing of the payment of production proceeds to the trust, the production attributable to the distributions for the 12-months ending December 31, 2011 will be for the 11-months ending November 30, 2011, estimated to be 1,150 MBoe. The estimated production in the forecast period gives effect to the drilling and completion by SandRidge of approximately 31 PUD Wells per year during the four-year drilling period, and the completion by SandRidge of its drilling obligation to the trust of 123 PUD Wells by December 31, 2014. As a reasonably prudent operator, SandRidge is obligated to drill and complete the PUD Wells consistent with the drilling and completion techniques used in the Producing Wells to enhance oil and natural gas recovery in a cost effective manner, which we believe will result in completions longer than the perforated interval length for which full credit will be given under the terms of the development agreement. See “—Oil Prices” and “—Natural Gas Prices” below for a description of changes in production due to price variations. Differing levels of production will result in different levels of distributions and cash returns.

Oil Prices.    The assumed oil prices utilized for purposes of preparing the target distributions are based on NYMEX forward pricing for the 36-month period ending December 31, 2013 and assumed price increases thereafter of 2.5% annually, capped at $120.00 per Bbl. Using these assumptions, the price per Bbl would reach the $120.00 per Bbl cap in 2025. The table below sets forth NYMEX forward pricing as of December 17, 2010 for the 36-month period ending December 31, 2013.

Estimated Market Prices for Oil ($/Bbl)

Based on Settled NYMEX Pricing

as of December 17, 2010

 

		2011				2012				2013
January		$	88.02			$	91.36			$	90.56
February			88.60				91.29				90.46
March			89.37				91.22				90.36
April			89.95				91.15				90.27
May			90.36				91.10				90.19
June			90.65				91.04				90.12
July			90.89				90.95				90.08
August			91.05				90.86				90.05
September			91.16				90.78				90.01
October			91.24				90.73				89.98
November			91.32				90.69				89.96
December			91.41				90.67				89.95

 

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Natural Gas Prices.    The assumed natural gas prices utilized for purposes of preparing the target distributions are based on NYMEX forward pricing for the 36-month period ending December 31, 2013 and assumed price increases thereafter of 2.5% annually, capped at $7.00 per MMBtu. Using these assumptions, the price per MMBtu would reach the $7.00 per MMBtu cap in 2022. The table below sets forth NYMEX forward pricing as of December 17, 2010 for the 36-month period ending December 31, 2013.

Estimated Market Prices for Natural Gas ($/MMBtu)

Based on Settled NYMEX Pricing

as of December 17, 2010

 

		2011				2012				2013
January		$	4.07			$	5.04			$	5.50
February			4.10				5.01				5.46
March			4.10				4.91				5.32
April			4.09				4.72				5.05
May			4.13				4.73				5.05
June			4.19				4.76				5.07
July			4.26				4.81				5.11
August			4.30				4.84				5.15
September			4.32				4.85				5.17
October			4.39				4.93				5.25
November			4.60				5.11				5.42
December			4.88				5.34				5.63

It has been assumed that 61% of the estimated oil production and 60% of the estimated natural gas production attributable to the trust’s royalty interests will be hedged through December 31, 2015. SandRidge will enter into a derivatives agreement with the trust in order to transfer to the trust the benefit of the hedging contracts entered into between SandRidge and third parties. However, the oil and natural gas prices used for purposes of preparing the target distributions do not reflect any hedging assumptions.

If oil and natural gas prices decline, the operators of producing oil and natural gas properties may elect to reduce or completely suspend production. SandRidge is required under the applicable conveyance to act as a reasonably prudent operator with respect to the Underlying Properties under the same or similar circumstances as it would act if it were acting with respect to its own properties, disregarding the existence of the royalty interests as burdens affecting such property. No adjustments have been made to estimated production in the tables above to reflect potential reductions or suspensions of production by SandRidge or third party operators.

Differentials.    Proceeds to the trust will be calculated based on the actual price realized by SandRidge for oil and natural gas produced, which will differ from NYMEX prices as a result of:

 

•

discounts based on location,

 

•

quality of oil and natural gas produced,

 

•

estimated shrinkage and fuel usage for natural gas and

 

•

post-production costs (generally consisting of costs incurred to gather, store, compress, transport, process, treat, dehydrate and market the oil and natural gas produced).

We refer to these charges collectively as pricing “differentials” from NYMEX pricing.

 

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To prepare the target distributions, assumed differentials were subtracted from the NYMEX prices shown in the tables above, based on an analysis by SandRidge of historical realized prices for production from the region. The estimated realized prices for natural gas assume a 19% negative differential from the NYMEX futures price for natural gas and an estimated 1.13 times conversion factor from MMBtu to Mcf, which account for the historical volatility in differentials in the region.

The estimated realized prices for oil assume a $5.00 per barrel negative differential from the NYMEX futures price for oil based on the historical stability of the differential and the estimated gravity of the oil in the reserve report, which varies from sweet to sour crude oil. The reserve report classifies 72% and 28% of the oil production over the life of the trust as sweet crude and sour crude, respectively. Due to the higher refining costs of sour crude oil, it typically has a greater differential than sweet crude oil. Over the eleven months ended November 30, 2010, SandRidge realized a price differential to NYMEX prices for sweet crude oil of $3.31 per barrel and a price differential to NYMEX prices for sour crude oil of $9.20 per barrel. The assumed $5.00 per barrel differential approximates the weighted average of SandRidge’s actual differentials for sweet and sour crude oil over this eleven month period. A flat dollar differential amount has been chosen because the realized oil differential has historically been stable for oil produced in the mid-continent region.

There can be no assurance that realized prices in the future will be the same as historical realized prices or the assumed realized prices used to prepare the target distributions.

Administrative Expense.    Trust administrative expense per year is estimated to be approximately $900,000, although such costs could be greater or less depending on future events that cannot be predicted. Included in this annual estimate, among other miscellaneous items, are annual administrative fees of $150,000 for the trustee, $2,300 for the Delaware trustee and $200,000 for SandRidge, respectively. The annual fee to SandRidge will remain flat for the life of the trust, while the remaining estimated costs ($700,000) escalate at a rate of 2.5% annually starting in the second quarter of 2012. The trust will also pay, out of the first cash payment received by the trust, the trustee’s and Delaware trustee’s legal expenses incurred in forming the trust as well as the trustee’s acceptance fee in the amount of $10,000. These costs will be deducted by the trust before distributions are made to trust unitholders.

Trustee’s Cash Reserve.    It has been assumed that the trustee will withhold $1.0 million from the first distribution to unitholders to establish a cash reserve available for potential administrative expenses of the trust. No other cash reserves have been assumed.

Tax Treatment of Royalty Interests.    For U.S. federal income tax purposes, the Term PDP Royalty and the Term PUD Royalty should be treated as debt instruments. Accordingly, the Term Royalties will be subject to the original issue discount, or OID, rules of the Internal Revenue Code, which require that payments made to the trust with respect to the Term Royalties will be treated first as consisting of a payment of interest to the extent of interest deemed accrued under the OID rules at the applicable federal rate and the excess, if any, will be treated as a payment of principal (which is non-taxable). For federal income tax purposes, the Perpetual PDP Royalties will be, and the Perpetual PUD Royalties should be, treated as mineral royalty interests, which give rise to ordinary income subject to depletion.

Timing of Actual Cash Distributions.    Quarterly cash distributions will be made on or about the 60th day following the end of each calendar quarter to unitholders of record on or about the 45th day following each calendar quarter. Due to the timing of SandRidge’s receipt of cash for production, it has been assumed that cash distributions for each quarter will include production from the first two months of the quarter just ended as well as the last month of the immediately preceding quarter. The first distribution, which will cover the first and second quarters of 2011, is

 

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expected to be made on or about August 30, 2011 to record unitholders as of August 15, 2011, and will include sales for oil and natural gas for the months January through May 2011. Thereafter, quarterly distributions will generally relate to production of oil and natural gas for a three month period, including one month of the prior quarter.

Applicable Taxes.    Oklahoma levies a tax on the production of oil and natural gas in the state. Under current law, a reduced rate of production tax is available for the first four years of a horizontal well’s production so long as the well is producing before July 1, 2015. Accordingly, it has been assumed that the effective rate of production tax on the oil and gas attributable to the trust will be approximately 1.0% for the first four years of production for each well, and approximately 7.0% thereafter.

Incentive Distributions.    To the extent that the trust has cash available for distribution in excess of the incentive thresholds during the subordination period, SandRidge will be entitled to receive 50% of such cash as incentive distributions. The incentive distributions terminate upon completion of the subordination period.

Sensitivity of Target Distributions to Changes in Oil and Natural Gas Prices and Volumes

The amount of revenues of the trust and cash distributions to the trust unitholders will be directly dependent on the sales price for oil and natural gas sold, the volumes of oil and natural gas produced and, to some degree, variations in property and production taxes, if any, and post-production costs. The following tables demonstrate the projected effect that changes in the estimated oil and natural gas production for the forecast period ending March 31, 2012 as reflected in the reserve report and the impact that fluctuations in assumed realized oil and natural gas prices could have on cash distributions to the trust unitholders.

These tables set forth the sensitivity of annual cash distributions per trust unit for the forecast period ending March 31, 2012 based upon (1) the assumption that a total of 18,975,000 common trust units and 6,325,000 subordinated units are issued and outstanding after the closing of the offering made hereby; (2) an assumed initial public offering price of $             per common unit; (3) various realizations of oil and natural gas production levels estimated in the reserve report; (4) various assumed realized oil and natural gas prices; (5) assumptions regarding applicable taxes and differentials; and (6) other assumptions described above under “—Significant Assumptions Used to Calculate the Target Distributions.” The assumed realized prices of oil and natural gas production shown have been chosen solely for illustrative purposes, and do not reflect any hedging assumptions.

The tables give effect to the subordination and incentive distribution features that are contained in the terms of the trust. For a description of the way in which those features would impact trust unitholders’ distributions, please see “Target Distributions and Subordination and Incentive Thresholds.”

 

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The following tables are not a projection or forecast of the actual or estimated results from an investment in the common units. The purpose of these tables is to illustrate the sensitivity of cash distributions to changes in oil and natural gas production levels and the price of oil and natural gas. There is no assurance that the assumptions described below will actually occur or that oil and natural gas production levels and the prices of oil and natural gas will not change by amounts different from those shown in the tables.

The oil and natural gas hedging contracts established by SandRidge with third parties will be in effect only through December 31, 2015, and thus there is likely to be greater fluctuation in cash distributions resulting from fluctuations in realized oil and natural gas prices in periods subsequent to the expiration of those contracts. See “Risk Factors” for a discussion of various items that could impact production levels and the price of oil and natural gas.

These distributions are sensitized to both assumed NYMEX oil and natural gas prices as well as the assumed production from the trust properties. The quarterly distributions in the tables below are based on assumptions outlined in “—Significant Assumptions Used to Calculate the Target Distributions.” The tables set forth below provide examples of possible distributions for the quarters ending June 30, 2011, September 30, 2011, December 31, 2011 and March 31, 2012 based on various NYMEX pricing and production assumptions.

For scenarios in these tables that involve lower NYMEX oil or natural gas prices and production volumes, as applicable, the quarterly distribution per unit does not fall below the subordination threshold because the subordinated units support the common distributions.

For each table, the assumed NYMEX oil price per Bbl or natural gas price per MMBtu, as applicable, used to estimate quarterly distributions is also the assumed NYMEX oil price or gas price for all previous quarters. The distributions below do not reflect any hedging assumptions.

 

Estimated Distribution per Common Unit for the Quarter Ending June 30, 2011(1) % of Assumed NYMEX Futures Pricing(2)
% Estimated of Production(3)							85%				90%				95%				100%				105%				110%				115%
			85%			$	0.834			$	0.834			$	0.836			$	0.877			$	0.926			$	0.975			$	1.024
			90%				0.834				0.836				0.881				0.932				0.984				1.036				1.088
			95%				0.834				0.878				0.933				0.987				1.042				1.097				1.151
			100%				0.870				0.927				0.985				1.042				1.100				1.157				1.215
			105%				0.916				0.976				1.037				1.097				1.158				1.218				1.265
			110%				0.962				1.026				1.089				1.152				1.216				1.265				1.297
			115%				1.009				1.075				1.141				1.207				1.262				1.295				1.328
							Target Cash Distribution											$	1.042
							Subordination Threshold											$	0.834
							Incentive Threshold											$	1.251

 

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Estimated Distribution per Common Unit for the Quarter Ending September 30, 2011 % of Assumed NYMEX Futures Pricing(2)
% Estimated of Production(3)							85%				90%				95%				100%				105%				110%				115%
			85%			$	0.519			$	0.519			$	0.521			$	0.550			$	0.579			$	0.609			$	0.638
			90%				0.519				0.521				0.552				0.583				0.614				0.645				0.676
			95%				0.519				0.551				0.583				0.616				0.649				0.681				0.714
			100%				0.546				0.580				0.615				0.649				0.683				0.718				0.752
			105%				0.574				0.610				0.646				0.682				0.718				0.754				0.784
			110%				0.601				0.639				0.677				0.715				0.753				0.785				0.803
			115%				0.629				0.669				0.708				0.748				0.783				0.803				0.822
							Target Cash Distribution											$	0.649
							Subordination Threshold											$	0.519
							Incentive Threshold											$	0.779

 

Estimated Distribution per Common Unit for the Quarter Ending December 31, 2011 % of Assumed NYMEX Futures Pricing(2)
% Estimated of Production(3)							85%				90%				95%				100%				105%				110%				115%
			85%			$	0.500			$	0.500			$	0.501			$	0.529			$	0.558			$	0.586			$	0.614
			90%				0.500				0.502				0.531				0.561				0.591				0.621				0.650
			95%				0.500				0.530				0.561				0.593				0.624				0.656				0.687
			100%				0.525				0.558				0.591				0.624				0.658				0.691				0.724
			105%				0.552				0.587				0.621				0.656				0.691				0.726				0.755
			110%				0.579				0.615				0.651				0.688				0.724				0.755				0.773
			115%				0.605				0.643				0.681				0.719				0.753				0.772				0.792
							Target Cash Distribution											$	0.624
							Subordination Threshold											$	0.500
							Incentive Threshold											$	0.749

 

Estimated Distribution per Common Unit for the Quarter Ending March 31, 2012 % of Assumed NYMEX Futures Pricing(2)
% Estimated of Production(3)							85%				90%				95%				100%				105%				110%				115%
			85%			$	0.523			$	0.523			$	0.525			$	0.555			$	0.584			$	0.613			$	0.643
			90%				0.523				0.525				0.557				0.588				0.619				0.650				0.681
			95%				0.523				0.555				0.588				0.621				0.654				0.687				0.720
			100%				0.550				0.585				0.619				0.654				0.689				0.723				0.758
			105%				0.578				0.615				0.651				0.687				0.724				0.760				0.791
			110%				0.606				0.644				0.682				0.720				0.758				0.791				0.810
			115%				0.634				0.674				0.714				0.754				0.789				0.809				0.829
							Target Cash Distribution											$	0.654
							Subordination Threshold											$	0.523
							Incentive Threshold											$	0.785

(1)	Includes proceeds attributable to the first five months of production from January 1, 2011 to May 31, 2011.

(2)	Average NYMEX futures prices, as reported December 17, 2010.

(3)	Estimated oil and natural gas production is based on the reserve report, and the sensitivity analysis assumes there will be no variation by location and that oil and natural gas production will continue to represent the same percentage of total production as estimated in the reserve report.

 

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THE UNDERLYING PROPERTIES

The Underlying Properties consist of the working interest owned by SandRidge in the Mississippian formation in Alfalfa, Garfield, Grant, Major and Woods counties in Oklahoma arising under leases and farmout agreements related to properties from which the PDP Royalty Interest and the PUD Royalty Interest will be conveyed. As of December 31, 2010, the Underlying Properties consisted of approximately 63,500 gross acres (42,600 net acres). There are more than 250 potential drilling locations within the AMI. As of December 31, 2010 and after giving effect to the conveyance of the PDP Royalty Interest and the PUD Royalty Interest to the trust, the total reserves estimated to be attributable to the trust were 19,276 MBoe (48% oil). This amount includes 6,860 MBoe attributable to the PDP Royalty Interest and 12,416 MBoe attributable to the PUD Royalty Interest, respectively. SandRidge is currently the operator of 73% of the wells subject to the PDP Royalty Interest. SandRidge owns an average 56.4% net revenue interest in the wells subject to the PDP Royalty Interest. The reserves attributable to the trust’s royalty interests include the reserves that are expected to be produced from the Mississippian formation during the 20-year period in which the trust owns the royalty interests as well as the residual interest in the reserves that the trust will sell on or shortly following the Termination Date.

Overview of Mississippian Formation

The Mississippian formation is located on the Anadarko Shelf in northern Oklahoma and south-central Kansas. The top of this expansive carbonate hydrocarbon system is encountered between 4,000 and 6,000 feet and lies stratigraphically between the Pennsylvanian-aged Morrow Sand and the Devonian-aged Woodford Shale formations. The Mississippian formation may reach 1,000 feet in gross thickness and the targeted porosity zone is between 50 and 100 feet in thickness. The formation’s geology is well understood as a result of the thousands of vertical wells drilled and produced there since the 1940s (including 123 vertical wells drilled on the Underlying Properties). Beginning in 2007, the application of horizontal cased-hole drilling and multi-stage hydraulic fracturing treatments have demonstrated the potential for extracting significant additional quantities of oil and natural gas from the formation.

Since the beginning of 2009, there have been over 95 horizontal wells drilled and completed in the Mississippian formation in Oklahoma, including 37 completed by SandRidge. As of December 2010, there were 14 horizontal rigs drilling in the formation, with seven of those rigs drilling for SandRidge. While horizontal wells are more expensive than vertical wells, a horizontal well bore increases the production of hydrocarbons and adds significant recoverable reserves per well. In addition, an operator can drill one horizontal well, which is the equivalent of several vertical wells, and as a result achieve better returns on drilling investments with horizontal drilling. SandRidge has approximately 780,000 net acres leased in the Mississippian formation in Oklahoma and Kansas.

Historical Results from the Producing Wells

The following table provides revenues and direct operating expenses relating to the Producing Wells for the year ended December 31, 2009 and the nine months ended September 30, 2010, derived from the Underlying Properties’ statements of revenues and direct operating expenses included elsewhere in this prospectus. During the year ended December 31, 2009, only five of the 37 Producing Wells were completed, while 29 were completed (27 of which had begun producing) as of September 30, 2010. As a result, the information in the table set forth below will not be comparable to the trust’s results going forward as SandRidge completes additional Producing Wells. The information in the table below does not reflect the formation of the trust or the

 

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conveyance of the PDP Royalty Interest to the trust. The selected financial data presented below should be read in conjunction with the audited statement of revenues and direct operating expenses of the Underlying Properties, the related notes and “—Discussion and Analysis of Historical Results from the Producing Wells” included elsewhere in this prospectus and the discussion of SandRidge’s business and related Management’s Discussion and Analysis of Financial Condition and Results of Operations of SandRidge set forth and incorporated by reference in this prospectus.

 

		Year Ended December 31, 2009				Nine-Months Ended September 30, 2010
		(Dollars in thousands)
Oil and natural gas revenue		$	550			$	11,823
Direct operating expenses:
Lease operating expense			294				1,675
Production taxes and other post-production expenses			40				1,141
Total direct operating expenses			334				2,816
Revenues in excess of direct operating expenses		$	216			$	9,007

Oil and Natural Gas Sales Prices and Production Costs

The following table sets forth the production, average sales prices and production and post-production costs for the Producing Wells on a historical basis for the year ended December 31, 2009 and the nine months ended September 30, 2010, and for the royalty interests on a pro forma basis for the year ended December 31, 2009 and the nine months ended September 30, 2010.

 

		Historical Results for Producing Wells								Pro Forma for Royalty Interests (1)
		Year Ended December 31, 2009				Nine Months Ended September 30, 2010				Year Ended December 31, 2009				Nine Months Ended September 30, 2010
		(Dollars in thousands)
Production (2):
Oil (Bbls)			6,878				132,595				6,190				119,335
Natural gas (Mcf)			40,534				651,995				36,481				586,795
Total production (Boe)			13,634				241,261				12,270				217,135
Average sales prices:
Oil (per Bbl)		$	61.72			$	68.58			$	61.72			$	68.58
Natural gas (per Mcf)		$	3.09			$	4.19			$	3.09			$	4.19
Production costs (per Boe) (3)		$	21.56			$	6.94			$	—			$	—
Post-production costs and taxes (per Boe) (4)		$	2.90			$	4.73			$	2.90			$	4.73

 

(1)	Pro forma figures are calculated as if the conveyances were in effect for the period indicated.

 

(2)

Production volumes represent volumes from SandRidge’s interest and are net of all burdens and any third-party interest in the wells. Gross production from the five completed wells was approximately 119,200 Boe for the year ended December 31, 2009 and from the 27 completed (and producing) wells was approximately 571,300 Boe for the nine months ended September 30, 2010.

 

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(3)	Production costs include lease operating costs. Average production costs for the year ended December 31, 2009 were generated from the five completed wells, all of which were non-operated and experienced higher than normal average operating costs due to start-up of operations.

 

(4)	Post-production costs and taxes are generally based upon (i) volume produced and (ii) prices received for production.

Discussion and Analysis of Historical Results from the Producing Wells

During the year ended December 31, 2009, SandRidge participated in the drilling and completion of five horizontal wells in the Mississippian formation within the AMI. The first of these wells began producing and selling oil and natural gas in April 2009. The remaining four wells were put into production throughout the remainder of 2009. These wells were drilled with an average lateral length of 3,944 feet and completed with an average of seven fracture stimulations per well. Aggregate monthly production net to SandRidge’s interest ranged from a low of approximately 60 Boe during the month of May 2009 to a high of approximately 3,000 Boe during October 2009 and ended the period with all five wells on line during December 2009. Total volumes produced and sold during the period ended December 31, 2009 from the five wells were approximately 13,600 Boe.

The average sales prices received for oil and natural gas production during the year ended December 31, 2009 were $61.72 per Bbl and $3.09 per Mcf, respectively, before the deduction of any post-production costs or operating expenses. Prices received ranged from a low of $45.97 per barrel in May 2009 to a high of $66.63 per Bbl in November 2009 for oil sales and from a low of $2.14 per Mcf in May 2009 to a high of $4.00 per Mcf in December 2009 for gas sales. Post-production costs, which consist of transportation, gathering and processing fees, and production taxes were $2.90 per Boe produced and totaled approximately $39,600 for the period. Operating expenses averaged approximately $36,700 per month during the period. Revenues less direct operating expenses were approximately $216,500 for the year ended December 31, 2009.

During the nine months ended September 30, 2010, SandRidge drilled or participated in the drilling and completion of 24 additional Mississippian horizontal wells (22 of which had begun producing as of September 30, 2010). These wells were drilled with an average lateral length of 4,384 feet and completed with an average of 10 fracture stimulations per well. Aggregate monthly production net to SandRidge’s interest ranged from a low of approximately 2,200 Boe during the month of January 2010 to a high of approximately 72,400 Boe during September 2010. With 27 wells on line and producing during the month of September 2010, the average daily production was more than 2,400 Boe per day in the aggregate. Total volumes produced and sold during the nine-month period were approximately 241,300 Boe.

The average sales price received for oil and natural gas production during the nine-month period ended September 30, 2010 were $68.58 per Bbl and $4.19 per Mcf, respectively, before deduction of any post-production costs or operating expenses. Prices received ranged from a low of $63.52 per Bbl in June 2010 to a high of $74.97 per Bbl in April 2010 for oil sales and from a low of $3.76 per Mcf in September 2010 to a high of $5.14 per Mcf in February 2010 for gas sales. Post-production costs were $4.73 per Boe produced and totaled approximately $1,141,400 for the nine-month period. Operating expenses averaged approximately $186,200 per month during the period. Revenues less direct operating expenses were approximately $9,006,800 for the nine-month period ended September 30, 2010.

During the nine months ended September 30, 2010 SandRidge invested approximately $5.5 million in the development of two wells that were classified as proved undeveloped at December 31, 2009. These two wells were classified as proved developed wells at September 30, 2010. Since there were no proved undeveloped reserves in the Underlying Properties at December 31, 2008, no amount was invested to convert proved undeveloped to proved developed reserves during 2009.

 

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Properties Related to the PUD Royalty Interest

SandRidge’s average net revenue interest in the oil and natural gas properties underlying the PUD Royalty Interest is approximately 57.0%. The PUD Royalty Interest will entitle the trust to receive 50% of the proceeds attributable to SandRidge’s net revenue interest in future production of oil and natural gas resulting from the drilling of the PUD Wells, with 25% of such proceeds attributable to the Term PUD Royalty and 25% of such proceeds attributable to the Perpetual PUD Royalty.

SandRidge owns a majority working interest in approximately 75% of the locations on which it expects to drill the PUD Wells, and it expects to operate such wells during the subordination period. Until such time as SandRidge has met its commitment to drill the PUD Wells, SandRidge will covenant and agree not to drill and complete, and will not permit any other person within its control to drill and complete, any well in the AMI described above for its own account. Upon the trustee’s release of the Drilling Support Lien, SandRidge will further agree not to drill and complete, and will not permit any other person within its control to drill and complete, any well in the AMI that will have a perforated segment that will be within 660 feet of any perforated interval of any PUD or Producing Well.

The development agreement provides that, until SandRidge has fulfilled its drilling obligation, any additional acreage leased or acquired by any other means by SandRidge within the AMI will become part of the AMI. In addition, SandRidge may, in its sole discretion, make additional acreage or acreage exchanged for other acreage in the AMI subject to the PUD Royalty Interest, so long as the aggregate additional acreage or exchanged acreage does not exceed five percent of the acreage currently subject to the PUD Royalty Interest.

Oil and Natural Gas Reserves

Netherland Sewell estimated oil and natural gas reserves attributable to the Underlying Properties as of December 31, 2010. Numerous uncertainties are inherent in estimating reserve volumes and values, and the estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of the reserves may vary significantly from the original estimates.

Proved reserves of the Underlying Properties and royalty interests.    The following table sets forth certain estimated proved reserves and the PV-10 value as of December 31, 2010 attributable to the Underlying Properties and the royalty interests, in each case derived from the reserve report. The reserve report was prepared by Netherland Sewell in accordance with criteria established by the SEC.

Proved reserve quantities attributable to the royalty interests are calculated by multiplying the gross reserves for each property by the royalty interest assigned to the trust in each property. The net revenues attributable to the trust’s reserves are net of an assumed level of post-production costs based on historical results. The reserves related to the Underlying Properties include all of the proved reserves expected to be economically produced from the Mississippian formation during the life of the properties. The reserves and revenues attributable to the trust’s interests include only the reserves attributable to the Underlying Properties that are expected to be produced within

 

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the 20-year period in which the trust owns the royalty interest as well as the 50% residual interest in the reserves that the trust will own on the Termination Date. The reserve report is included as Annex A to this prospectus.

 

		Proved Reserves(1)
		Oil (MBbl)				Natural Gas (MMcf)				Total (MBoe)				PV-10 Value (2)
														(Dollars in Millions)
Underlying Properties			18,526				113,527				37,447			$	469.5
Royalty Interests:
PDP Royalty Interest (90%) (3)			2,913				23,682				6,860			$	155.7
PUD Royalty Interest (50%)			6,422				35,964				12,416				274.9
Total			9,335				59,646				19,276			$	430.6

 

(1)

The proved reserves were determined using a 12-month unweighted arithmetic average of the first-day-of-the-month prices for oil and natural gas for the period from January 1, 2010 through December 1, 2010, without giving effect to derivative transactions, and were held constant for the life of the properties. The prices used in the reserve reports, as well as SandRidge’s internal reports, yield weighted average prices at our wellhead, which are based on first-day-of-the-month reference prices and adjusted for transportation and regional price differentials. The reference prices and the equivalent weighted average wellhead prices are both presented in the table below.

 

		Reference prices								Weighted average wellhead prices
		Oil (per Bbl)				Natural gas (per Mcf)				Oil (per Bbl)				Natural gas (per Mcf)
December 31, 2010		$	75.96			$	4.376			$	74.60			$	4.075

 

(2)

PV-10 is the present value of estimated future net revenue to be generated from the production of proved reserves, discounted using an annual discount rate of 10%, calculated without deducting future income taxes. PV-10 is a non-GAAP financial measure and generally differs from standardized measure of discounted net cash flows, or Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Because the historical financial information related to the Underlying Properties consists solely of revenues and direct operating expenses and does not include the effect of income taxes, we expect the PV-10 and Standardized Measure attributable to the Underlying Properties for each period to be equivalent. Because the trust will not bear federal income tax expense, we also expect the PV-10 and Standardized Measure attributable to the royalty interests for each period to be equivalent. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of the Underlying Properties or the royalty interests. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.

 

(3)	Includes reserves associated with wells in the process of being completed.

Information concerning historical changes in net proved reserves attributable to the Underlying Properties, and the calculation of the standardized measure of discounted future net revenues related thereto, is contained in the unaudited supplemental information contained elsewhere in this prospectus. SandRidge has not filed reserve estimates covering the Underlying Properties with any other federal authority or agency.

The Reserve Report

All of the oil and natural gas reserves in this registration statement were estimated by Netherland Sewell. The process to review and estimate the reserves began 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 various levels of SandRidge management for accuracy, before consultation with Netherland Sewell. These individuals consulted regularly with

 

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Netherland Sewell during the reserve estimation process to review properties, assumptions, and any new data available. Internal reserve estimates and methodologies were compared to Netherland Sewell to test the reserve estimates and conclusions before the reserve estimates were included in this registration statement. Additionally, SandRidge’s senior management reviewed and approved the reserve report contained herein.

Internal Controls.    SandRidge’s Executive Vice President – Reservoir Engineering is the technical person primarily responsible for overseeing the preparation of the company’s reserve estimates, is the primary contact with Netherland Sewell and received the reserve report from Netherland Sewell. He has a Bachelor of Science degree in Mechanical Engineering with 30 years of practical industry experience, including 25 years of estimating and evaluating reserve information. In addition, our Executive Vice President – Reservoir Engineering has been a certified professional engineer in the state of Oklahoma since 1988 and a member of the Society of Petroleum Engineers since 1980.

SandRidge’s Reservoir Engineering Department continually monitors asset performance and makes reserves estimate adjustments, as necessary, to ensure the most current reservoir information is reflected in reserves estimates. Reserve information includes production histories as well as other geologic, economic, ownership and engineering data. The department currently has a total of 18 full-time employees, comprised of seven degreed engineers and 11 engineering analysts/technicians with a minimum of a four-year degree in mathematics, economics, finance or other business or science field.

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

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

 

•

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

 

•

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

 

•

The Reservoir Engineering Department reports directly to the President, independently from all of our operating divisions.

 

•

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 the Company such as Accounting; and

 

•

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

Each quarter, the Executive Vice President – Reservoir Engineering presents the status of SandRidge’s reserves, including the reserves associated with the Underlying Properties, to the Executive Committee, which subsequently approves all changes. In the event the quarterly updated reserves estimates are disclosed, the aforementioned review process is evidenced by signatures from the Executive Vice President – Reservoir Engineering and the Chief Financial Officer.

 

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SandRidge’s Reservoir Engineering Department works closely with its independent petroleum consultants at each fiscal year end to ensure the integrity, accuracy and timeliness of an annually developed independent reserves estimate. These independently developed reserves estimates are adopted as SandRidge’s corporate reserves and are reviewed by the Audit Committee, as well as the Chief Financial Officer, Senior Vice President of Accounting, Vice President of Internal Audit, Vice President of Financial Reporting, Treasurer and General Counsel. In addition to reviewing the independently developed reserve reports, the Audit Committee interviews the third-party engineer at Netherland Sewell primarily responsible for the reserve report.

Technologies.    The reserve report was prepared using decline curve analysis to determine the reserves of individual Producing Wells. After estimating the reserves of each proved developed well, it was determined that a reasonable level of certainty exists with respect to the reserves that can be expected from close offset undeveloped wells in the field. The continuity of the formation across the AMI area was established by reviewing electric well logs, geologically mapping the analogous reservoir and reviewing extensive production data from more than 1,200 vertical and 40 horizontal wells. The reserves attributable to the Producing Wells, which cover a wide area of the AMI, and the continuity of the formation over the AMI area classification further supports proved undeveloped classification within close proximity to the Producing Wells. Data from both SandRidge and offset operators with which SandRidge has exchanged technical data demonstrate a consistency in this formation over an area much larger than the AMI. In addition, direct measurement from other producing wells has also been used to confirm consistency in reservoir properties such as porosity, thickness and stratigraphic conformity. Most importantly, production from other producing wells confirms that horizontal wells across the AMI have similar performance with respect to initial production, decline curve shape and estimated ultimate reserve recovery.

While vertical well control exists across all of the AMI most of the existing producing horizontal wells were drilled without benefit of a direct offset producing lateral section. These wells all encountered proven reserves in the Mississippian formation. The proven undeveloped locations within the AMI are generally all offsets to the horizontal wells drilled and producing to date, or are offset by proven vertical production along the well bore path of the proved undeveloped location. Of the proved undeveloped drilling locations identified in the reserve report, only approximately 12% are not offsets of other historically producing wells. Those approximately 12% proved undeveloped drilling locations are generally characterized by the second offset interior to known production. All proved undeveloped drilling locations identified in the reserve report demonstrate a “reasonable certainty” of proven reserves based on the consistency of the analogous reservoir and performance data.

Netherland Sewell.    Netherland Sewell, the independent petroleum engineering consultant, estimated all of the proved reserve information in this registration statement, in accordance with the definitions and guidelines of the SEC and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. For the purposes of the reserve report, Netherland Sewell used technical and economic data including, but not limited to, well test data, production data, historical price and cost information, and property ownership interests. The reserves in the reserve report have been estimated using deterministic methods. Netherland Sewell used standard engineering and geosciences methods, or a combination of methods, such as performance analysis and analogy, that they considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and guidelines. A substantial portion of these reserves are for undeveloped locations and producing wells that lack sufficient production history upon which performance-

 

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related estimates of reserves can be based. Therefore, these reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. Netherland Sewell’s expertise is in petroleum engineering, geoscience, and petrophysical interpretation, not legal or accounting matters; they are not accountants, attorneys, or landmen. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, the conclusions from Netherland Sewell necessarily represent only informed professional judgment. The titles to the properties have not been examined by Netherland Sewell, nor has the actual degree or type of interest owned been independently confirmed. The data used in Netherland Sewell’s estimates were obtained from SandRidge and the non-confidential files of Netherland Sewell and were accepted as accurate. Supporting geoscience, field performance, and work data are on file in their office. The technical persons responsible for preparing the reserves estimates presented meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Netherland Sewell are independent petroleum engineers, geologists, geophysicists, and petrophysicists; Netherland Sewell does not own an interest in these properties and are not employed on a contingent basis.

Well Locations

SandRidge has over 253 drilling locations within the AMI and may drill some of the PUD Wells on units that encompass land controlled by third-party operators in order to maximize recovery in the field and also maximize the perforated length of each PUD Well drilled. If SandRidge drills one or more PUD Wells in which it has less than a 57.0% net revenue interest, it will be obligated to drill, or cause to be drilled, additional PUD Wells above the planned number for the trust in order to make the total number of wells equal 123. For instance, if SandRidge drilled one well in which it has a 50% net revenue interest, and such well was drilled to a perforated length of 2,000 feet, such well would count for purposes of the development agreement as only 0.702 PUD Wells (i.e., 2,000/2,500 X 50%/57.0). In order to compensate for this, SandRidge would be obligated to drill, or cause to be drilled, an additional PUD Well with a perforated length of 2,500 feet and a 17.0% net revenue interest so that the trust still received one development well.

 

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Additional Information Regarding the Underlying Properties

Drilling Activity.    The following table sets forth information with respect to the Producing Wells SandRidge completed during 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 SandRidge had a working interest and net wells refer to gross wells multiplied by SandRidge’s weighted average working interest. As of December 31, 2010, there were 5 gross (4.2 net) wells drilling or awaiting completion.

		2010																2009
		Gross				Percent				Net				Percent				Gross				Percent				Net				Percent
Development:
Productive			26				100	%			19.9				100	%			6				100	%			1.6				100	%
Dry			0				0	%			0.0				0	%			0				0	%			0.0				0	%
Total			26				100	%			19.9				100	%			6				100	%			1.6				100	%
Exploratory:
Productive			4				100	%			4.0				100	%			0				100	%			0.3				100	%
Dry			0				0	%			0.0				0	%			0				0	%			0.0				0	%
Total			4				100	%			4.0				100	%			0				100	%			0.3				100	%
Total:
Productive			30				100	%			23.9				100	%			0				100	%			1.9				100	%
Dry			0				0	%			0.0				0	%			0				0	%			0.0				0	%
			30				100	%			23.9				100	%			0				100	%			1.9				100	%

Productive Wells.    The following table sets forth the number of Producing Wells within the AMI in which SandRidge owned working interests and from which SandRidge will convey the royalty interests to the trust. 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 in which SandRidge has an interest and net wells are the sum of SandRidge’s fractional working interests owned in gross wells.

 

Oil

Natural Gas

Total

Gross

Net

Gross

Net

Gross

Net

Productive Wells

37

27

0

0

37

27

Developed and Undeveloped Acreage.    The following table sets forth information regarding developed and undeveloped acreage held by SandRidge within the AMI at December 31, 2010:

 

Developed Acreage(1)

Undeveloped Acreage(2)

Gross(3)

Net(4)

Gross(3)

Net(4)

Acreage Held by SandRidge within the AMI

38,017

24,508

25,483

18,093

 

(1)	Developed acres are acres spaced or assigned to productive wells.

(2)	Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.

 

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(3)	A gross acre is an acre in which SandRidge owns a working interest. The number of gross acres is the total number of acres in which SandRidge owns a working interest.

(4)	A net acre is deemed to exist when the sum of SandRidge’s fractional ownership working interests in gross acres equals one. The number of net acres is the sum of SandRidge’s fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage is established prior to such date, in which event the lease will remain in effect until production has ceased. The following table sets forth as of December 31, 2010 the expiration periods of the gross and net acres that are subject to leases in the acreage summarized in the above table.

 

		Acres Expiring
Twelve Months Ending		Gross				Net
December 31, 2011			11,222				7,261
December 31, 2012			1,530				1,101
December 31, 2013			11,563				8,923
December 31, 2014 and later			585				338
Other(1)			0				0
Total			24,900				17,622

 

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

Sale and Abandonment of the Underlying Properties

SandRidge and any transferee will have the right to abandon its interest in any well or property comprising a portion of the Underlying Properties if, in its opinion, such well or property ceases to produce or is not capable of producing in commercially paying quantities. To reduce or eliminate the potential conflict of interest between SandRidge and the trust in determining whether a well is capable of producing in commercially paying quantities, SandRidge and any transferee, as applicable, will be required under the applicable conveyance to act as a reasonably prudent operator in the AMI under the same or similar circumstances would act if it were acting with respect to its own properties, disregarding the existence of the royalty interests as a burden affecting such property.

After completion of its drilling obligation, SandRidge generally may sell all or a portion of its interests in the Underlying Properties, subject to and burdened by the royalty interests, without the consent of the trust unitholders. In addition, SandRidge may, without the consent of the trust unitholders, require the trust to release royalty interests with an aggregate value to the trust not to exceed $5.0 million during any 12-month period. These releases will be made only in connection with a sale by SandRidge of Underlying Properties and are conditioned upon the trust receiving an amount equal to the fair value to the trust of such royalty interests. Any net sales proceeds paid to the trust are distributable to trust unitholders for the quarter in which they are received. SandRidge has not identified for sale any of the Underlying Properties.

 

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Marketing and Post-Production Services

Pursuant to the terms of the conveyances creating the royalty interests, SandRidge will have the responsibility to market, or cause to be marketed, the oil and natural gas production related to the Underlying Properties. The terms of the conveyances creating the royalty interests do not permit SandRidge to charge any marketing fee when determining the proceeds upon which the royalty payments will be calculated. As a result, the proceeds to the trust from the sales of oil and natural gas production from the Underlying Properties will be determined based on the same price (net of post-production costs) that SandRidge receives for oil and natural gas production attributable to SandRidge’s remaining interest in the Underlying Properties.

A wholly owned subsidiary of SandRidge markets the majority of SandRidge’s operated production. Such subsidiary enters into oil and natural gas sales arrangements with large aggregators of supply and these arrangements may be on a month-to-month basis or may be for a term of up to one year or longer. The oil and natural gas is sold at a market price and subsequently any applicable post-production costs will be deducted. The primary aggregators of supply with whom SandRidge currently does business in the AMI are Atlas Pipeline Mid-Continent WestOk, LLC and Shell Trading US Company.

Following this offering, post-production costs will be deducted from proceeds paid to the trust. SandRidge may provide post-production services itself or contract with others to provide post-production services, including gathering, transportation, processing and other reasonable post-production services, including transportation on downstream interstate pipelines. Such post-production costs will be expressed either (1) as a cost per Bbl or MMBtu or (2) as a percentage of the gross production from a well. The trust’s cash available for distribution will be reduced by SandRidge’s deductions for these post-production costs.

Post-production costs may be deducted by the ultimate purchaser of the oil and natural gas prior to payment being made to SandRidge or its marketing affiliate for such production. At other times, SandRidge or its marketing affiliate will make payments directly to the third parties providing such post-production services. In either instance, the trust’s cash available for distribution will be reduced by the costs paid by SandRidge for such post-production services provided by third parties. If the post-production costs are expressed as a percentage of the gross production from a well, then the volume of production from that well actually available for sale is less the applicable percentage charged, and as a result the reserves associated with that well that are attributable to the royalty interest are reduced accordingly.

The cost of marketing and post-production services is included within the assumed differentials from NYMEX pricing discussed above under “Target Distributions and Subordination and Incentive Thresholds.”

Regardless of whether the post-production costs are based upon a cost per Bbl or per MMBtu or a percentage of gross production from a well, such costs may increase or decrease in the future. The post-production costs attributable to third party arrangements may be costs established by arms-length negotiations or pursuant to a state or federal regulatory proceeding. SandRidge will be permitted to deduct from the proceeds available to the trust other post-production costs necessary to make the oil and natural gas from the Underlying Properties marketable, so long as such costs do not materially exceed the charges prevailing in the area for similar services.

SandRidge expects to enter into oil and natural gas supply arrangements and post-production service arrangements for the oil and natural gas to be produced from the PUD Wells that are similar to those in place with respect to the Producing Wells. Any new oil and natural gas supply arrangements or those entered into for providing post-production services, will be utilized in determining the proceeds for the Underlying Properties.

 

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Title to Properties

The Underlying Properties are subject to certain burdens that are described in more detail below. To the extent that these burdens and obligations affect SandRidge’s rights to production and the value of production from the Underlying Properties, they have been taken into account in calculating the trust’s interests and in estimating the size and the value of the reserves attributable to the 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 by SandRidge directly from the mineral owner, through assignments of oil and natural gas leases to SandRidge by the lessee who originally obtained the 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.

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 the burdens and obligations affecting the Underlying Properties and the royalty interests are conventional in the industry for similar properties. SandRidge also believes that the burdens and obligations do not, in the aggregate, materially interfere with the use of the Underlying Properties and will not materially adversely affect the value of the royalty interest.

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

 

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Competition and Markets

The oil and natural gas industry is highly competitive. SandRidge competes with major oil and gas companies and independent oil and gas companies for leases, equipment, personnel and markets for the sale of oil and natural gas. Many of these competitors are financially stronger than SandRidge, but even financially troubled competitors can affect the market because of their need to sell oil and natural gas at any price to attempt to maintain cash flow. The trust will be subject to the same competitive conditions as SandRidge and other companies in the oil and natural gas industry.

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

Future price fluctuations for oil and natural gas will directly impact trust distributions, estimates of reserves attributable to the trust’s interests, and estimated and actual future net revenues to the trust. In view of the many uncertainties that affect the supply and demand for oil and natural gas, neither the trust nor SandRidge can make reliable predictions of future supply and demand for oil and natural gas, future oil and natural gas prices or the effect of future oil and natural gas prices on the trust.

Regulation

Oil and Natural Gas Regulation.    The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission. Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. The Federal Energy Regulatory Commission’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.

Sales of oil, natural gas and natural gas liquids are not currently regulated and are made at market prices. Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. Neither SandRidge nor the trust can predict whether new legislation to regulate oil and natural gas prices might be proposed, what proposals, if any, might actually be enacted by Congress or state legislatures, and what effect, if any, the proposals might have on the operations of the Underlying Properties.

Environmental Regulation.    The exploration, development and production of oil and natural gas are subject to 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, among other things, require permits to conduct drilling, water withdrawal and waste disposal operations; govern the amounts and types of substances that may be disposed or released into the environment; limit or prohibit construction or drilling activities in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; require investigatory and remedial actions to mitigate pollution conditions arising from SandRidge’s operations or attributable to former operations; 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.

 

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The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on the proceeds available to the trust under the royalty interests. Moreover, accidental releases or spills may occur in the course of SandRidge’s operations on the Underlying Properties, and there can be no assurance that SandRidge will not incur significant costs and liabilities as a result of such releases or spills, including any third party claims for damage to property and natural resources or personal injury.

The following is a summary of the more significant existing environmental, 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 SandRidge’s 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 found 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 and property damage allegedly caused by the release of hazardous substances into the environment. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. SandRidge generates materials in the course of its operations, including with respect to the Underlying Properties, that may be regulated as hazardous substances.

SandRidge generates wastes 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. In the course of its operations, SandRidge generates petroleum hydrocarbon wastes and ordinary industrial wastes that are subject to regulation under the RCRA. SandRidge is in substantial compliance with all regulations regarding the handling and disposal of oil and gas exploration and production wastes from its operations, including with respect to the Underlying Properties.

SandRidge currently owns or leases, and in the past may have owned or leased, properties that have been used to explore for and produce oil and natural gas. Although SandRidge may have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons and wastes may have been disposed of or released on or under the properties owned or leased by SandRidge or on or under the other locations where these hydrocarbons and wastes have been taken for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons and wastes was not under SandRidge’s control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, SandRidge could be required to remove or remediate previously disposed wastes, to clean up contaminated property and to perform remedial operations to prevent future contamination.

 

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Air Emissions.    The Clean Air Act, as amended, and comparable state laws and regulations restrict the emission of air pollutants from many sources and also impose various monitoring and reporting requirements. These laws and regulations may require SandRidge to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with air permit requirements or utilize 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.

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

Oil and natural gas may be recovered from the Underlying Properties through the use of hydraulic fracturing, combined with sophisticated horizontal 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 but is not subject to regulation at the federal level. The EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with results of the study anticipated to be available by late 2012, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. Legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states, but not Oklahoma, have adopted regulations that could restrict hydraulic fracturing in certain circumstances. If new laws or regulations that significantly restrict hydraulic fracturing are adopted at the Oklahoma state level, such legal requirements could make it more difficult or costly for SandRidge to perform fracturing to stimulate production in the Mississippian play and thereby affect the determination of whether a well is commercially viable. In addition, if hydraulic fracturing is regulated at the federal level, SandRidge’s fracturing activities, including with respect to its operations at the Underlying Properties, could become subject to additional permit requirements or operational restrictions and also to associated permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that SandRidge is ultimately able to produce in commercial quantities from the Underlying Properties.

Climate Change.    In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and certain other 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 federal Clean Air Act. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Accordingly, the EPA has proposed regulations that would require a reduction in emissions of

 

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GHGs from motor vehicles and adopted regulations that could trigger permit review for GHG emissions from certain stationary sources. In addition, in October 2009, the EPA published a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, including sources emitting more than 25,000 tons of GHGs on an annual basis, beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA published a final rule that expands its October 2009 final rule on reporting of GHG emissions to include owners and operators of onshore oil and natural gas production, effective December 30, 2010. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHG gases from, SandRidge’s equipment and operations could require SandRidge to incur costs to reduce emissions of GHGs associated with its operations or could adversely affect demand for the oil and natural gas it produces. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if any such effects were to occur, they could have an adverse effect on SandRidge’s assets and operations.

In addition, Congress has actively considered legislation to reduce emissions of GHGs and President Obama has indicated his support of legislation to reduce GHG emissions through an emission allowance system. Even if such legislation is not adopted at the national level, almost one-half of the states have begun taking actions to control and/or reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Although most of the state-level initiatives have to date focused on large sources of GHG emissions, such as coal-fired electric plants, it is possible that smaller sources of emissions could become subject to GHG emission limitations or allowance purchase requirements in the future. Any future federal laws or implementing regulations that may be adopted to address GHG emissions could require SandRidge to incur increased operating costs, could adversely affect demand for the oil and natural gas that it produces, and could have a material adverse effect on SandRidge’s business, financial condition and results of operations.

Employee Health and Safety.    The operations of SandRidge are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in SandRidge’s operations and that this information be provided to employees, state and local government authorities and citizens. SandRidge believes that it is in substantial compliance with all applicable laws and regulations relating to worker health and safety.

State Regulation.    Oklahoma regulates the drilling for, and the production and gathering of, oil and natural gas, including requirements relating to drilling permits, the location, spacing and density of wells, unitization and pooling of interests, the method of drilling, casing and equipping of wells, the protection of fresh water sources, the orderly development of common sources of supply of oil and natural gas, the operation of wells, allowable rates of production, the use of fresh water in oil and natural gas operations, saltwater injection and disposal operations, the plugging and abandonment of wells and the restoration of surface properties, the prevention of waste of oil and natural gas resources, the protection of the correlative rights of oil and natural gas owners and, where necessary to avoid unfair, unjust or discriminatory service, the fees, terms and conditions for the gathering of natural gas. The effect of these regulations may be to limit the number of wells that SandRidge may drill, impact the locations at which SandRidge may drill wells, restrict the amounts of oil and natural gas that may be produced from SandRidge’s wells and increase the costs of its operations. Realized prices for the first sale of oil and natural gas are not subject to state regulation in Oklahoma.

 

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DESCRIPTION OF THE ROYALTY INTERESTS

The royalty interests will be conveyed to the trust by SandRidge by means of conveyance instruments that will be recorded in the appropriate real property records in the counties where the oil and natural gas properties to which the Underlying Properties relate are located.

The royalty interests will be conveyed from SandRidge’s interest in the Producing Wells and the PUD Wells. The PDP Royalty Interest entitles the trust to receive 90% of the proceeds (exclusive of any production or development costs but after deducting post-production costs and any applicable taxes) from the sale of production of oil and natural gas attributable to SandRidge’s net revenue interest in the Producing Wells. The PUD Royalty Interest entitles the trust to receive 50% of the proceeds (exclusive of any production or development costs but after deducting post-production costs and any applicable taxes) from the sale of production of oil and natural gas attributable to SandRidge’s net revenue interest in the PUD Wells.

Generally, the percentage of production proceeds to be received by the trust with respect to a well will equal the product of (i) the percentage of proceeds to which the trust is entitled under the terms of the conveyances (90% for the Producing Wells and 50% for the PUD Wells) multiplied by (ii) SandRidge’s net revenue interest in the well. SandRidge on average owns a 56.4% net revenue interest in the Producing Wells. Therefore, the trust will have an average 50.7% net revenue interest in the Producing Wells. SandRidge on average owns a 57.0% net revenue interest in the properties in the AMI from which the PUD Wells will be drilled and based on this net revenue interest, the trust would have an average 28.5% net revenue interest in the PUD Wells. SandRidge’s actual net revenue interest in any particular PUD Well may differ from this average, and will depend on SandRidge’s working interest and the royalty interests and similar revenue burdens owed to third parties with respect to such well.

PDP Royalty Interest

The PDP Royalty Interest entitles the trust to receive an amount of cash for each calendar quarter equal to 90% of the proceeds (exclusive of any production or development costs but after deducting post-production costs and any applicable taxes) from the sale of oil and natural gas production attributable to SandRidge’s net revenue interest in the Producing Wells. Proceeds from the sale of oil and natural gas production attributable to SandRidge’s net revenue interest in the Producing Wells in any calendar quarter means, for any calendar quarter commencing on or after January 1, 2011, the amount calculated based on actual production volumes attributable to SandRidge’s net revenue interest in the Producing Wells, in each case after deducting the trust’s proportionate share of:

 

•

any taxes levied on the severance or production of the oil and natural gas produced from the Producing Wells and any property taxes attributable to the oil and natural gas produced from the Producing Wells; and

 

•

post-production costs, which will generally consist of costs incurred to gather, store, compress, transport, process, treat, dehydrate and market the oil and natural gas produced, as applicable.

Proceeds payable to the trust from the sale of oil and natural gas production attributable to the Producing Wells in any calendar quarter will not be subject to any deductions for any expenses attributable to exploration, drilling, development, operating, maintenance or any other costs incident to the production of oil and natural gas production attributable to the Producing Wells, including any costs to plug and abandon a Producing Well.

 

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PUD Royalty Interest

The PUD Royalty Interest entitles the trust to receive an amount of cash for each calendar quarter equal to 50% of the proceeds (exclusive of any production or development costs but after deducting post-production costs and any applicable taxes) from the sale of estimated oil and natural gas production attributable to SandRidge’s net revenue interest in the PUD Wells. Proceeds from the sale of oil and natural gas production attributable to SandRidge’s net revenue interest in the PUD Wells in any calendar quarter means, for any calendar quarter commencing on or after January 1, 2011, the amount calculated based on actual production volumes attributable to SandRidge’s net revenue interest in the PUD Wells, in each case after deducting the trust’s proportionate share of:

 

•

any taxes levied on the severance or production of the oil and natural gas produced from the PUD Wells and any property taxes attributable to the oil and natural gas produced from the PUD Wells; and

 

•

post-production costs, which will generally consist of costs incurred to gather, store, compress, transport, process, treat, dehydrate and market the oil and natural gas produced, as applicable.

Proceeds payable to the trust from the sale of oil and natural gas production attributable to the PUD Wells in any calendar quarter will not be subject to any deductions for any expenses attributable to exploration, drilling, development, operating, maintenance or any other costs incident to the production of oil and natural gas production attributable to the PUD Wells, including any costs to drill a PUD Well.

Sale of the Perpetual Royalties

The trust will begin to liquidate on the Termination Date and will soon thereafter wind up its affairs and terminate. The Term Royalties will automatically revert to SandRidge at the Termination Date, while the Perpetual Royalties will be sold and the proceeds thereof will be distributed to the unitholders at the Termination Date or soon thereafter. SandRidge will have a first right of refusal to purchase the Perpetual Royalties at the Termination Date.

The conveyances provide that the trustee will use commercially reasonable efforts to retain a third-party advisor to market the Perpetual Royalties within 30 business days of the Termination Date. If the trustee receives a bona fide offer from a proposed purchaser other than SandRidge and wants to sell all or part of the Perpetual Royalties, it will be required to give notice (the “Offer Notice”) to SandRidge, identifying the proposed purchaser and setting forth the proposed sale price, payment terms and other material terms and conditions under which the trustee is proposing to sell. SandRidge would then have 30 days from receipt of the Offer Notice to elect, by notice to the trustee, to purchase the subject properties offered for sale on the terms and conditions set forth in the Offer Notice. If SandRidge makes such election, the proposed purchaser would be entitled to receive reimbursement of its reasonable and documented expenses incurred in connection with its review and analysis of the subject properties and bid preparation. SandRidge and the trust would share equally the cost of reimbursement to the proposed purchaser.

If SandRidge does not give notice within the 30-day period following the Offer Notice, the trustee may sell such properties to the identified purchaser on terms and conditions that are substantially the same as those previously set forth in such Offer Notice. Moreover, if, after a reasonable marketing period, no bid is received on any or all of the Perpetual Royalties from any party other than SandRidge, then SandRidge shall obtain, at the trust’s expense, and deliver to the trustee, a fairness opinion from a nationally-recognized valuation firm with expertise in valuing oil and natural gas properties stating that the proposed sale price to be paid by SandRidge to the trust for the properties is fair to the trust.

 

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Additional Features of the Royalty Interests

Reasonably Prudent Operator Standard.    Under the conveyances, SandRidge is obligated to act as a reasonably prudent operator in the AMI under the same or similar circumstances as it would if it were acting with respect to its own properties, disregarding the existence of the royalty interests as burdens affecting such properties. Accordingly, there may be situations where SandRidge will be obligated to drill on one or more of the over 250 potential drilling locations within the AMI, including the 123 drilling locations identified in the reserve report, that are not those identified locations underlying the reserve report.

True-up.    The conveyances provide that if SandRidge’s net revenue interest with respect to the properties underlying the Producing Wells is greater than what was warranted to the trust in the conveyances, SandRidge will have the right to offset against amounts owed to the trust, the difference between what the trust actually receives from the PDP Royalty Interest and what the trust should have received from the PDP Royalty Interest had SandRidge’s net revenue interest been the amount warranted.

Controversies.    If a controversy arises as to the sales price of any production, then for purposes of determining gross proceeds:

 

•

amounts withheld or placed in escrow by a purchaser are not considered to be received by the owner of the underlying property until actually collected;

 

•

amounts received by the owner of the underlying property and promptly deposited with a nonaffiliated escrow agent will not be considered to have been received until disbursed to it by the escrow agent; and

 

•

amounts received by the owner of the underlying property and not deposited with an escrow agent will be considered to have been received.

Overpayments.    The trustee is not obligated to return any cash received from the royalty interests. Any overpayments made to the trust by SandRidge due to adjustments to prior calculations of proceeds or otherwise will reduce future amounts payable to the trust until SandRidge recovers the overpayments.

Sale of Underlying Properties.    The conveyances generally permit SandRidge to sell, without the consent or approval of the trust unitholders, 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. Notwithstanding the foregoing, the conveyances provide that SandRidge may not sell any of the Underlying Properties subject to the PUD Royalty Interest until it has satisfied the drilling obligation pursuant to the terms of the development agreement. The trust unitholders are not entitled to any proceeds of any sale of SandRidge’s interest in the Underlying Properties that remains subject to and burdened by the royalty interests. Following such sale, the proceeds attributable to the transferred property will be calculated as described in this prospectus, and paid by the purchaser or transferee to the trust. As a result, any additional costs resulting from the sold property will not reduce the proceeds paid to the trust from the Underlying Properties retained by SandRidge. SandRidge will require any purchaser of any of the Underlying Properties to enter into an agreement to provide information SandRidge will require to perform its obligations under the administrative services agreement.

Exchange, Release and Addition of Acreage.    SandRidge may at its option at any time prior to the completion of its drilling obligation, cause the trust to exchange leased acreage subject to the royalty interests, free and clear of such royalty interests, for other leased acreage within the AMI. Such leased acreage exchanged to the trust shall then be subject to the royalty interests as set forth

 

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in the conveyances. In no event may any exchange of acreage be effected unless SandRidge certifies to the trust that, among other things, all of the aggregate acreage attributable to the exchanged leases shall not exceed five percent of the acreage subject to the royalty interest.

In addition, SandRidge may, at its option and without the consent of the trust unitholders, require the trust to release acreage subject to the royalty interest with an aggregate value to the trust of up to $5.0 million during any 12-month period. These releases will be made only in connection with a sale by SandRidge of a portion of the Underlying Property and are conditioned upon the trust receiving an amount equal to the fair value to the trust of such released royalty interests.

In the event SandRidge acquires any additional leases in the AMI prior to the completion of its drilling obligation, SandRidge may at its option make such additional leases subject to the royalty interests.

Abandonment of Underlying Property.    SandRidge or any transferee of an Underlying Property will have the right to abandon any well or property if it reasonably believes the well or property ceases to produce or is not capable of producing in commercially paying quantities. In making such decisions, SandRidge or any transferee of an Underlying Property is required under the applicable conveyance to act as a reasonably prudent operator in the AMI under the same or similar circumstances would act if it were acting with respect to its own properties, disregarding the existence of the royalty interests as burdens affecting such property. Upon termination of the lease, that portion of the royalty interests relating to the abandoned property will be extinguished.

Maintenance of Books and Records.    SandRidge must maintain books and records sufficient to determine the amounts payable for the royalty interests to the trust. Quarterly and annually, SandRidge must deliver to the trustee a statement of the computation of the proceeds for each computation period as well as quarterly drilling and production results. Because SandRidge files reports with the SEC, those reports will be publicly available. See “Where You Can Find More Information.”

Reservation of Rights.    Pursuant to the conveyances, SandRidge will expressly except and reserve all right, title and interest in and to any well and appurtenant production facilities not expressly conveyed to the trust.

 

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DESCRIPTION OF THE TRUST AGREEMENT

Creation and Organization of the Trust; Amendments

The trust was created under Delaware law as a separate legal entity to acquire and hold the royalty interests for the benefit of the trust unitholders pursuant to an agreement between SandRidge, the trustee and the Delaware trustee. The royalty interests are 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. Neither SandRidge nor other operators of the Underlying Properties have any contractual commitments to the trust to provide additional funding or to conduct further drilling on or to maintain their ownership interest in any of these properties other than the obligations of SandRidge to designate and drill the PUD Wells. After the conveyance of the royalty interests, however, SandRidge will retain an interest in each of the Underlying Properties. For a description of the Underlying Properties and other information relating to them, see “The Underlying Properties.”

The trust agreement provides that the trust’s activities will be 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 and the derivatives agreement with SandRidge. As a result, the trust will not be permitted to acquire other oil and natural gas properties or royalty interests. Additionally, following the completion of this offering the trust is not able to issue any additional trust units.

The beneficial interest in the trust is divided into 25,300,000 trust units. Each trust unit represents an equal undivided beneficial interest in the property of the trust. Please read “Description of the Trust Units” for additional information concerning the trust units.

Amendment of the trust agreement generally requires a vote of holders of a majority of the outstanding trust units and a majority of the outstanding common units (excluding common units owned by SandRidge and its affiliates) voting in person or by proxy at a meeting of such unitholders at which a quorum is present. At any time that SandRidge and its affiliates collectively own less than 10% of the outstanding trust units, however, the standard for approval will be a majority of the outstanding trust units, including units owned by SandRidge, voting in person or by proxy at a meeting of the unitholders at which a quorum is present. However, no amendment may:

 

•

increase the power of the trustee to engage in business or investment activities;

 

•

decrease the incentive threshold or increase the subordination threshold or change the portion of the quarterly cash distributions payable as an incentive distribution;

 

•

alter the rights of the trust unitholders as among themselves; or

 

•

permit the trustee to distribute the royalty interests in kind.

Amendments to the trust agreement’s provisions addressing the following matters may not be made without SandRidge’s consent:

 

•

dispositions of the trust’s assets;

 

•

indemnification of the trustee;

 

•

reimbursement of out-of-pocket expenses of SandRidge when acting as the trust’s agent;

 

•

termination of the trust; and

 

•

amendments of the trust agreement.

 

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Certain amendments to the trust agreement do not require the vote of the trust unitholders. The trustee may, without approval of the trust unitholders, from time to time supplement or amend the trust agreement in order to cure any ambiguity or to correct or supplement any defective or inconsistent provisions or to evidence or implement any changes required by applicable law provided such supplement or amendment is not adverse to the interest of the trust unitholders. The business and affairs of the trust will be managed by the trustee. SandRidge operates 73% of the Producing Wells and expects to operate at least 70% of the PUD Wells during the subordination period, but will have no ability to manage or influence the management of the trust, except through its limited voting rights as a holder of trust units.

Assets of the Trust

Upon completion of this offering, the assets of the trust will consist of the PDP Royalty Interest and the PUD Royalty Interest, the derivatives agreement, the administrative services agreement, the development agreement that obligates SandRidge to drill the PUD Wells, and any cash and temporary investments being held for the payment of expenses and liabilities and for distribution to the trust unitholders. See “The Trust” for more information.

Duties and Powers of the Trustee

The duties of the trustee are specified in the trust agreement and by the laws of the State of Delaware, except as modified by the trust agreement. The trustee’s principal duties consist of:

 

•

collecting cash proceeds attributable to the royalty interests;

 

•

paying expenses, charges and obligations of the trust from the trust’s assets;

 

•

determining whether cash distributions exceed subordination or incentive thresholds, and making cash distributions to the unitholders and SandRidge (with respect to incentive distributions) in accordance with the trust agreement;

 

•

causing to be prepared and distributed a Schedule K-1 for each trust unitholder and to prepare and file tax returns on behalf of the trust;

 

•

causing to be prepared and filed reports required to be filed under the Securities Exchange Act of 1934, as amended, and by the rules of any securities exchange or quotation system on which the trust units are listed or admitted to trading; and

 

•

taking any action it deems necessary and advisable to best achieve the purposes of the trust.

If a trust liability is contingent or uncertain in amount or not yet currently due and payable, the trustee may create a cash reserve to pay for the liability. If the trustee determines that the cash on hand and the cash to be received are insufficient to cover the trust’s liability, the trustee may cause the trust to borrow funds required to pay the liabilities. The trust may borrow the funds from any person, including the trustee or its affiliates. The terms of such indebtedness, if funds were loaned by the entity serving as trustee or Delaware trustee, would be similar to the terms which such entity would grant to a similarly situated commercial customer with whom it did not have a fiduciary relationship, and such entity shall be entitled to enforce its rights with respect to any such indebtedness as if it were not then serving as trustee or Delaware trustee. If the trust borrows funds, the trust unitholders will not receive distributions until the borrowed funds are repaid.

The trustee intends to withhold $1.0 million from the first distribution to unitholders to establish a cash reserve available to the trustee to pay trust administrative expenses. If the trustee uses such cash reserve (or any portion thereof) to pay or reimburse trust liabilities or expenses, no

 

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further distributions will be made to unitholders (except in respect of any previously determined quarterly cash distribution amount) until the cash reserve is replenished. This cash reserve will be part of the trust estate and will bear interest at the same rate as other cash on hand in the trust estate. Upon the dissolution of the trust, the balance of the cash reserve (including accrued interest thereon) will be distributed to trust unitholders on a pro rata basis.

Each quarter, the trustee will pay trust obligations and expenses and distribute to the trust unitholders the remaining proceeds received from the royalty interests. The cash held by the trustee as a reserve against future liabilities must be invested in:

 

•

interest bearing obligations of the United States government;

 

•

money market funds that invest only in United States government securities;

 

•

repurchase agreements secured by interest-bearing obligations of the United States government; or

 

•

bank certificates of deposit.

Alternatively, cash held for distribution at the next distribution date may be held in a non-interest bearing account.

The trust may not acquire any asset except the royalty interests and cash and temporary cash investments, and it may not engage in any investment activity except investing cash on hand.

The trust may merge or consolidate with or into, or convert into, one or more limited partnerships, general partnerships, corporations, business trusts, limited liability companies, or associations or unincorporated businesses if such transaction is agreed to by the trustee and approved by the affirmative vote of the holders of a majority of the outstanding trust units and a majority of the outstanding common units (excluding common units owned by SandRidge and its affiliates) in each case voting in person or by proxy at a meeting of such holders at which a quorum is present and such transaction is permitted under the Delaware Statutory Trust Act and any other applicable law. At any time that SandRidge and its affiliates collectively own less than 10% of the outstanding trust units, however, the standard for approval will be a majority of the outstanding trust units, including units owned by SandRidge voting in person or by proxy at a meeting of such holders at which a quorum is present.

The trustee may sell the royalty interests under any of the following circumstances:

 

•

the sale is requested by SandRidge, following the satisfaction of its drilling obligation, in accordance with the provisions of the trust agreement; or

 

•

the sale is approved by holders representing a majority of the outstanding trust units and a majority of the outstanding common units (excluding common units owned by SandRidge and its affiliates) in each case voting in person or by proxy at a meeting of such holders at which a quorum is present; except that at any time that SandRidge and its affiliates collectively own less than 10% of the outstanding trust units, the standard for approval will be a majority of the outstanding trust units, including units owned by SandRidge voting in person or by proxy at a meeting of such holders at which a quorum is present.

Upon dissolution of the trust the trustee must sell the royalty interests. No trust unitholder approval is required in this event.

The trustee will distribute the net proceeds from any sale of the royalty interests and other assets to the trust unitholders after payment or reasonable provision for payment of the liabilities of the trust.

 

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The trustee may amend or supplement the conveyances, the development agreement, the administrative services agreement, the registration rights agreement or the Drilling Support Lien, without the approval of the trust unitholders, to cure ambiguities, to correct or supplement defective or inconsistent provisions, to grant any benefit to all trust unitholders, to add collateral to the Drilling Support Lien or to change the name of the trust, provided, however, that any such supplement or amendment does not adversely affect the interest of the trust unitholders. Furthermore, the trustee, acting alone, may amend the administrative services agreement without the approval of trust unitholders if such amendment would not increase the cost or expense of the trust or create an adverse economic impact on the trust unitholders. All other permitted amendments may only be made by the affirmative vote of a majority of the trust units and a majority of the outstanding common units (excluding common units owned by SandRidge and its affiliates) in each case voting in person or by proxy at a meeting of such holders at which a quorum is present; except that at any time that SandRidge and its affiliates collectively own less than 10% of the outstanding trust units, the standard for approval will be a majority of the outstanding trust units, including units owned by SandRidge voting in person or by proxy at a meeting of such holders at which a quorum is present.

Liabilities of the Trust

Because the trust does not conduct an active business and the trustee has little power to incur obligations, it is expected that the trust will only incur liabilities for routine administrative expenses, such as the trustee’s fees and accounting, engineering, legal, tax advisory and other professional fees.

Fees and Expenses

The trust will be responsible for paying legal, accounting, tax advisory, engineering, printing and other administrative and out-of-pocket fees and expenses incurred by or at the direction of the trustee or the Delaware trustee, including tax return and Schedule K-1 preparation and mailing costs; independent auditor fees; and registrar and transfer agent fees. The trust will also be responsible for paying costs associated with annual and quarterly reports to unitholders. Moreover, the trustee’s and the Delaware trustee’s compensation, and the fee payable to SandRidge pursuant to the administrative services agreement will be paid out of the trust’s assets. See “The Trust,” for more information on these costs.

SandRidge Obligation to Fund Trust Expenses in Certain Circumstances

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 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. 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 arms’ length transaction between SandRidge and an unaffiliated third party.

 

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Responsibility and Liability of the Trustee

The duties and liabilities of the trustee are set forth in the trust agreement and by the laws of the State of Delaware. The trust agreement provides that (a) the trustee shall not have any duties or liabilities, including fiduciary duties, except as expressly set forth in the trust agreement and (b) the duties and liabilities of the trustee as set forth in the trust agreement replace any other duties and liabilities, including fiduciary duties, to which the trustee might otherwise be subject.

The trustee will not make business decisions affecting the assets of the trust. Therefore, substantially all of the trustee’s functions under the trust agreement are expected to be ministerial in nature. See “—Duties and Powers of the Trustee,” above. The trust agreement, however, provides that the trustee may:

 

•

charge for its services as trustee;

 

•

retain funds to pay for future expenses and deposit them with one or more banks or financial institutions (which may include the trustee to the extent permitted by law);

 

•

lend funds at commercial rates to the trust to pay the trust’s expenses; and

 

•

seek reimbursement from the trust for its out-of-pocket expenses.

In discharging its duty to trust unitholders, the trustee may act in its discretion and will be liable to the trust unitholders only for willful misconduct, bad faith or gross negligence. The trustee will not be liable for any act or omission of its agents or employees unless the trustee acted with willful misconduct, bad faith or gross negligence in its selection and retention. The trustee will be indemnified individually or as the trustee for any liability or cost that it incurs in the administration of the trust, except in cases of willful misconduct, bad faith or gross negligence. The trustee will have a lien on the assets of the trust as security for this indemnification and its compensation earned as trustee. Trust unitholders will not be liable to the trustee for any indemnification. See “Description of the Trust Units—Liability of Trust Unitholders.” The trustee will ensure that all contractual liabilities of the trust are limited to the assets of the trust.

Duration of the Trust; Sale of Royalty Interests

The trust will not dissolve until the Termination Date, which is December 31, 2030, unless:

 

•

the trust sells all of the royalty interests;

 

•

cash available for distribution is less than $1.0 million for any four consecutive quarters;

 

•

the holders of a majority of the outstanding trust units and a majority of the outstanding common units (excluding common units owned by SandRidge and its affiliates) in each case voting in person or by proxy at a meeting of such holders at which a quorum is present vote in favor of dissolution; except that at any time that SandRidge and its affiliates collectively own less than 10% of the outstanding trust units, the standard for approval will be a majority of the outstanding trust units, including units owned by SandRidge voting in person or by proxy at a meeting of such holders at which a quorum is present; or

 

•

the trust is judicially dissolved.

The trustee would then sell all of the trust’s assets, either by private sale or public auction, and distribute the net proceeds of the sale to the trust unitholders after payment, or reasonable provision for payment, of all trust liabilities.

 

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Dispute Resolution

To the fullest extent permitted by law, any dispute, controversy or claim that may arise between SandRidge and the trustee relating to the trust will be submitted to binding arbitration before a panel of three arbitrators.

Tax Matters

Trust unitholders will be treated as partners of the trust for U.S. federal income tax purposes. The trust agreement contains tax provisions that generally allocate the trust’s income, gain, loss, deduction and credit among the trust unitholders in accordance with their percentage interests in the trust. The trust agreement also sets forth the tax accounting principles to be applied by the trust.

Miscellaneous

The trustee may consult with counsel, accountants, tax advisors, geologists and engineers and other parties the trustee believes to be qualified as experts on the matters for which advice is sought. The trustee will be protected for any action it takes in good faith reliance upon the opinion of the expert.

The Delaware trustee and the trustee may resign at any time or be removed with or without cause at any time by a vote of not less than a majority of the outstanding common units (excluding common units owned by SandRidge and its affiliates) voting in person or by proxy at a meeting of such holders at which a quorum is present; except that at any time that SandRidge and its affiliates collectively own less than 10% of the outstanding trust units, the standard for approval will be a majority of the outstanding trust units, including units owned by SandRidge, voting in person or by proxy at a meeting of such holders at which a quorum is present. Any successor must be a bank or trust company meeting certain requirements including having combined capital, surplus and undivided profits of at least $20 million, in the case of the Delaware trustee, and $100 million, in the case of the trustee.

The principal offices of the trustee are located at 919 Congress Avenue, Suite 500, Austin, Texas 78701, and its telephone number is 1-800-852-1422.

 

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DESCRIPTION OF THE TRUST UNITS

Each trust unit is a unit of the beneficial interest in the trust and is entitled to receive cash distributions from the trust on a pro rata basis. Each trust unitholder has the same rights regarding each of his trust units as every other trust unitholder has regarding his units. The trust will have 25,300,000 trust units outstanding upon completion of the offering, consisting of 18,975,000 common units and 6,325,000 subordinated units.

Common Units; Subordinated Units

The trust units will initially be comprised of both common units and subordinated units. The common units and subordinated units will have identical rights and privileges, except with respect to their voting rights and rights to receive distributions. For a discussion of unitholders’ voting rights, see “—Voting Rights of Trust Unitholders” below.

The subordinated units will be 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 the applicable quarterly 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 will be 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 the common units. For more information, see “Target Distributions and Subordination and Incentive Thresholds.”

The subordinated units will automatically convert into common units on a one-for-one basis at the end of the fourth full calendar quarter following SandRidge’s satisfaction of its drilling obligation to the trust with respect to the PUD Wells.

Distributions; Income Computations

Cash distributions to trust unitholders will be made by the trust from its available funds for each calendar quarter. Production payments due to the trust with respect to any calendar quarter will be based on actual production volumes attributable to the trust properties during such quarter (as measured at SandRidge metering systems) and actual revenues received for such volumes. During the term of the derivatives agreement, SandRidge will determine the amounts due to (or from) the trust under the derivatives agreement. SandRidge will make a payment to the trust equal to the sum of the production payments and amounts due the trust under the hedging arrangements within 45 days of the end of each calendar quarter. After receipt of such payment, the trustee will determine for such calendar quarter the amount of funds available for distribution to the trust unitholders. Available funds are the excess cash, if any, received by the trust over the trust’s expenses for that quarter. Available funds will be reduced by any cash the trustee decides to hold as a reserve against future liabilities.

The amount of available funds for distribution each quarter will be payable to the trust unitholders of record on or about the 45th day following the end of such calendar quarter or such later date as the trustee determines is required to comply with legal or stock exchange requirements. The trustee will distribute cash on or about the 60th day (or the next succeeding business day following such day if such day is not a business day) following such calendar quarter to each person who was a trust unitholder of record on the quarterly record date, together with interest expected to be earned on the amount of such quarterly distribution from the date of receipt thereof by the trustee to the payment date.

 

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Unless otherwise advised by counsel or the IRS, the trustee will treat the income and expenses of the trust for each month as belonging to the trust unitholders of record on the first business day of the month. Trust unitholders will recognize income and expenses for tax purposes in the month the trust receives or pays those amounts, rather than in the month the trust distributes them. Minor variances may occur. For example, the trustee could establish a reserve in one month that would not result in a tax deduction until a later month. The trustee could also make a payment in one month that would be amortized for tax purposes over several months. See “U.S. Federal Income Tax Considerations.”

Transfer of Trust Units

Trust unitholders may transfer their trust units in accordance with the trust agreement. The trustee will not require either the transferor or transferee to pay a service charge for any transfer of a trust unit. The trustee may require payment of any tax or other governmental charge imposed for a transfer. The trustee may treat the owner of any trust unit as shown by its records as the owner of the trust unit. The trustee will not be considered to know about any claim or demand on a trust unit by any party except the record owner. A person who acquires a trust unit after any quarterly record date will not be entitled to the distribution relating to that quarterly record date. Delaware law will govern all matters affecting the title, ownership or transfer of trust units.

Tax Schedules and Periodic Reports

The trustee will file all required trust federal and state income tax and information returns. The trustee will prepare and mail to trust unitholders a Schedule K-1 that trust unitholders need to correctly report their share of the income and deductions of the trust. The trustee will also cause to be prepared and filed reports required to be filed under the Securities Exchange Act of 1934, as amended, and by the rules of any securities exchange or quotation system on which the trust units are listed or admitted to trading.

Each trust unitholder and his representatives may examine, for any proper purpose, during reasonable business hours the records of the trust and the trustee.

Liability of Trust Unitholders

Under the Delaware Statutory Trust Act, trust unitholders will be 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. No assurance can be given, however, that the courts in jurisdictions outside of Delaware will give effect to such limitation.

Voting Rights of Trust Unitholders

The trustee or trust unitholders owning at least 10% of the outstanding trust units may call meetings of trust unitholders. The trust will be responsible for all costs associated with calling a meeting of trust unitholders unless such meeting is called by the trust unitholders, in which case the trust unitholders will be responsible for all costs associated with calling such meeting of trust unitholders. Meetings must be held in such location as is designated by the trustee in the notice of such meeting. The trustee must send written notice of the time and place of the meeting and the matters to be acted upon to all of the trust unitholders at least 20 days and not more than 60 days before the meeting. Trust unitholders representing a majority of trust units outstanding must be present or represented to have a quorum. Each trust unitholder is entitled to one vote for each trust unit owned.

 

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Unless otherwise required by the trust agreement, a matter may be approved or disapproved by the vote of a majority of the trust units held by the trust unitholders voting in person or by proxy at a meeting where there is a quorum. This is true, even if a majority of the total outstanding trust units did not approve it.

Until such time as SandRidge and its affiliates own less than 10% of the outstanding trust units, the affirmative vote of the holders of a majority of common units (excluding common units owned by SandRidge and its Affiliates) and a majority of trust units voting in person or by proxy at a meeting of such holders at which a quorum is present is required to:

 

•

dissolve the trust (except in accordance with its terms);

 

•

amend the trust agreement, the royalty conveyances, the administrative services agreement, the development agreement, the Drilling Support Lien or the derivatives agreement (except with respect to certain matters that do not adversely affect the right of trust unitholders in any material respect);

 

•

merge or consolidate or convert the trust with or into another entity; or

 

•

approve the sale of all or any material part of the assets of the trust.

In addition, until such time as SandRidge and its affiliates own less than 10% of the outstanding trust units, the affirmative vote of the holders of a majority of common units (excluding common units owned by SandRidge and its affiliates) voting in person or by proxy at a meeting of such holders at which a quorum is present is required to remove the trustee and to appoint a successor trustee.

At any time when SandRidge and its affiliates own less than 10% of the outstanding trust units, the affirmative vote of the holders of a majority of trust units, including units owned by SandRidge voting in person or by proxy at a meeting of such holders at which a quorum is present will be required to take the actions described above.

Certain amendments to the trust agreement may be made by the trustee without approval of the trust unitholders. The trustee must consent before all or any part of the trust assets can be sold except in connection with the dissolution of the trust or limited sales directed by SandRidge in conjunction with its sale of Underlying Properties.

 

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Comparison of Trust Units and Common Stock

Trust unitholders have more limited voting rights than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of trust unitholders or for annual or other periodic re-election of the trustee.

Unitholders should also be aware of the following ways in which an investment in trust units is different from an investment in common stock of a corporation.

 

		Trust units		Common stock
Voting		The trust agreement provides voting rights to trust unitholders to remove and replace (but not elect) the trustee and to approve or disapprove major trust transactions.		Unless otherwise provided in the certificate of incorporation, corporate statutes provide voting rights to stockholders of the corporation to elect directors and to approve or disapprove amendments to the certificate of incorporation and certain major corporate transactions.
Income Tax		The trust is not subject to U.S. federal income tax; trust unitholders are subject to income tax on their allocable share of trust income, gain, loss and deduction.		Corporations are subject to U.S. federal income tax, and their stockholders are taxed on dividends.
Distributions		All trust revenue is distributed to trust unitholders after payment of trust expenses and additions, if any, to trust reserves.		Unless otherwise provided in the certificate of incorporation, stockholders are entitled to receive dividends solely at the discretion of the board of directors.
Business and Assets		The business of the trust is limited to specific assets with a finite economic life.		Unless otherwise provided in the certificate of incorporation, a corporation conducts an active business for an unlimited term and can reinvest its earnings and raise additional capital to expand.
Fiduciary Duties		To the extent provided in the trust agreement, the trustee has limited its fiduciary duties in the trust agreement as permitted by the Delaware Statutory Trust Act so that it will be liable to unitholders only for willful misconduct, bad faith or gross negligence.		Officers and directors have a fiduciary duty of loyalty to the corporation and the stockholders and a duty to exercise due care in the management and administration of a corporation’s affairs.

 

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TRUST UNITS ELIGIBLE FOR FUTURE SALE

General

Prior to this offering, there has been no public market for the common units. Sales of substantial amounts of the common units in the open market, or the perception that those sales could occur, could adversely affect prevailing market prices.

Upon completion of this offering, there will be 25,300,000 trust units outstanding. All of the 12,500,000 common units sold in this offering, or the 14,375,000 common units if the underwriters exercise their over-allotment option in full, will be freely tradable without restriction under the Securities Act. The 6,475,000 common trust units to be held by SandRidge (4,600,000 common trust units if the underwriters exercise their over-allotment in full) following completion of the offering will be “restricted securities” within the meaning of Rule 144 under the Securities Act and may not be sold other than through registration under the Securities Act or pursuant to an exemption from registration, subject to the restrictions on transfer contained in the lock-up agreements described below and in “Underwriting.”

SandRidge Lock-up Agreement

In connection with this offering, SandRidge has agreed, for a period of 180 days after the date of this prospectus, not to offer, sell, contract to sell or otherwise dispose of or transfer any trust units or any securities convertible into or exchangeable for trust units, without the prior written consent of Raymond James & Associates, Inc. and Morgan Stanley & Co. Incorporated, the representatives of the underwriters. See “Underwriting” for a description of this lock-up agreement. Upon the expiration of this lock-up agreement, all of the units held by SandRidge will be eligible for sale in the public market under Rule 144 of the Securities Act, subject to volume limitations and other restrictions contained in Rule 144, or through registration under the Securities Act.

Rule 144

The common units sold in the offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units owned by an “affiliate” of SandRidge or the trust may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

 

•

1.0% of the total number of the securities outstanding, or

 

•

the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about the trust. A person who is not deemed to have been an affiliate of SandRidge or the trust at any time during the three months preceding a sale, and who has beneficially owned common units for at least six months (provided the trust is in compliance with the current public information requirement) or one year (regardless of whether the trust is in compliance with the current public information requirement), would be entitled to sell common units under Rule 144 without regard to the rule’s public information requirements, volume limitations, manner of sale provisions and notice requirements.

 

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Registration Rights Agreement

The trust intends to enter into a registration rights agreement for the benefit of SandRidge and certain of its affiliates and transferees (each, a “holder”). In the registration rights agreement, the trust will agree, for the benefit of each holder, to register the trust units held by such holder. Specifically, the trust will agree:

 

•

subject to the restrictions described above under “—SandRidge Lock-up Agreement” and under “Underwriting—Lock-up Agreement,” 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 three 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.

 

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U.S. FEDERAL INCOME TAX CONSIDERATIONS

This section is a discussion of the material tax considerations that may be relevant to prospective trust unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Covington & Burling LLP, counsel to SandRidge and the trust, insofar as it relates to legal conclusions with respect to matters of U.S. federal income tax law. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”), existing and proposed Treasury regulations promulgated under the Internal Revenue Code (the “Treasury Regulations”) and current administrative rulings and court decisions, all of which are subject to change. Future changes in these authorities may cause the tax consequences to vary substantially from the consequences described below.

The following discussion does not address all U.S. federal income tax matters affecting the trust or the trust unitholders. Moreover, the discussion focuses on trust unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, non-U.S. persons, taxpayers subject to the alternative minimum tax, individual retirement accounts (IRAs), employee benefit plans, real estate investment trusts (REITs) or mutual funds. Accordingly, the trust encourages each prospective trust unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of trust units.

No ruling has been or will be requested from the Internal Revenue Service (the “IRS”) regarding any matter affecting the trust or prospective trust unitholders. Instead, the trust will rely on opinions of counsel. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the trust units and the prices at which trust units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to the trust unitholders, and thus will be borne indirectly by the trust unitholders. Furthermore, the tax treatment of the trust, or of an investment in the trust, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

 

All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Covington & Burling LLP and are based on the accuracy of the representations made by SandRidge and the trust.

For the reasons described below, Covington & Burling LLP has not rendered an opinion with respect to the following specific U.S. federal income tax issues: (1) the treatment of a trust unitholder whose trust units are loaned to a short seller to cover a short sale of trust units (please read “—Tax Consequences of Trust Unit Ownership—Treatment of Short Sales”); (2) whether the trust’s monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “—Disposition of Trust Units—Allocations Between Transferors and Transferees”); and (3) whether percentage depletion will be available to a trust unitholder or the extent of the percentage depletion deduction available to any trust unitholder (please read “—Tax Consequences of Trust Unit Ownership—Tax Treatment of the Perpetual Royalties”).

 

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As used herein, the term “trust unitholder” means a beneficial owner of trust units that for U.S. federal income tax purposes is:

 

•

an individual who is a citizen of the United States or who is resident in the United States for U.S. federal income tax purposes,

 

•

a corporation, or an entity treated as a corporation for U.S. federal income tax purposes, created or organized in or under the laws of the United States, a state thereof or the District of Columbia,

 

•

an estate the income of which is subject to U.S. federal income taxation regardless of its source, or

 

•

a trust if it is subject to the primary supervision of a U.S. court and the control of one or more United States persons (as defined for U.S. federal income tax purposes) or that has a valid election in effect under applicable U.S. Treasury regulations to be treated as a United States person.

The term “non-U.S. trust unitholder” means any beneficial owner of a trust unit (other than an entity that is classified for U.S. federal income tax purposes as a partnership or as a “disregarded entity”) that is not a trust unitholder.

If an entity that is classified for U.S. federal income tax purposes as a partnership is a beneficial owner of trust units, the tax treatment of a member of the entity will depend upon the status of the member and the activities of the entity. The trust encourages any entity that is classified for U.S. federal income tax purposes as a partnership and that is a beneficial owner of trust units, and the members of such an entity, to consult their own tax advisors about the U.S. federal income tax considerations of purchasing, owning, and disposing of trust units.

Classification of the Trust as a Partnership

Although the trust is formed as a statutory trust under Delaware law, the trust’s classification for U.S. federal income tax purposes is based on its characteristics rather than its form. Based on such characteristics, it is expected that, as described below, the trust will be treated for federal and applicable state income tax purposes as a partnership and trust unitholders will be treated as partners in that partnership.

A partnership is not a taxable entity and incurs no U.S. federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss, deduction and credit of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable to the partner unless the amount of cash distributed to him is in excess of the partner’s adjusted basis in his partnership interest as of the end of the taxable year in which the distribution is made.

Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to in this discussion as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the exploration, development, production and marketing of oil and natural gas and interest income (other than from a financial business). Other types of qualifying income include gains from the sale of real property and income from certain hedging transactions. The trust anticipates that substantially all of its gross income will be qualifying income. Based upon the factual representations made by the trust and SandRidge and a review of the applicable legal authorities, Covington & Burling LLP is of the opinion that at least 90% of the trust’s gross income will constitute qualifying income.

 

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No ruling has been or will be sought from the IRS and the IRS has made no determination as to the trust’s status for federal income tax purposes or whether the trust’s operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, the trust will rely on the opinion of Covington & Burling LLP on such matters. It is the opinion of Covington & Burling LLP that, based upon the Internal Revenue Code, Treasury Regulations, published revenue rulings and court decisions and the representations described below, the trust will be classified as a partnership for federal income tax purposes.

In rendering its opinion, Covington & Burling LLP has relied on factual representations made by the trust and SandRidge. The representations made by the trust and SandRidge upon which Covington & Burling LLP has relied are:

(a) The trust has not, and will not, elect to be treated as a corporation;

(b) The trust is, and will be organized and operated in accordance with (i) all applicable trust statutes, including the Delaware Statutory Trust Act, (ii) the trust agreement, and (iii) the description thereof in this prospectus;

(c) For each taxable year, more than 90% of the trust’s gross income will be income that Covington & Burling LLP has opined or will opine is qualifying income within the meaning of Section 7704(d) of the Internal Revenue Code; and

(d) Each hedging transaction that the trust treats as resulting in qualifying income will be appropriately identified as a hedging transaction pursuant to applicable Treasury Regulations, and will be associated with oil, gas or products thereof that are held or will be held by the trust in activities that Covington & Burling LLP has opined or will opine result in qualifying income.

The trust believes that these representations are true and expects that these representations will continue to be true in the future.

If the trust fails to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require the trust to make adjustments with respect to the trust’s unitholders allocable share of trust income, gain, loss or deduction or pay other amounts), the trust will be treated as if it had transferred all of its assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which the trust fails to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in the trust. This deemed contribution and liquidation should be tax-free to the trust unitholders and the trust. Thereafter, the trust would be treated as an association taxable as a corporation for federal income tax purposes.

If the trust were treated as an association taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, the trust’s items of income, gain, loss and deduction would be reflected only on the trust’s tax return rather than being passed through to the trust unitholders, and the trust’s net income would be taxed to the trust at corporate rates. In addition, any distribution made to a trust unitholder would be treated as either taxable dividend income, to the extent of the trust’s current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the trust unitholder’s tax basis in his trust units, or taxable capital gain, after the trust unitholder’s tax basis in his trust units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a trust unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the trust units.

 

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The discussion below is based on Covington & Burling LLP’s opinion that the trust will be classified as a partnership for U.S. federal income tax purposes.

Partner Status

Trust unitholders will be treated as partners of the trust for U.S. federal income tax purposes. Also, trust unitholders whose trust units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their trust units will be treated as partners of the trust for U.S. federal income tax purposes.

A beneficial owner of trust units whose trust units have been transferred to a short seller to complete a short sale would appear, as a result, to lose his status as a partner with respect to those trust units for U.S. federal income tax purposes. Please read “—Tax Consequences of Trust Unit Ownership—Treatment of Short Sales.” Income, gain, deductions or losses would not appear to be reportable by a trust unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a trust unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These unitholders are urged to consult their own tax advisors with respect to their tax considerations related to holding trust units. The references to “unitholders” in the discussion that follows are to persons who are treated as partners in the trust for federal income tax purposes.

Tax Classification of the PDP Royalty Interest and the PUD Royalty Interest

For U.S. federal income tax purposes, the Perpetual PDP Royalty and the Perpetual PUD Royalty will have the tax characteristics of mineral royalty interests to the extent they are, at the time of their creation, reasonably expected to have an economic life that corresponds substantially to the economic life of the mineral property or properties burdened thereby. Payments out of production that are received in respect of a mineral interest that constitutes a royalty interest for U.S. federal income tax purposes are taxable under current law as ordinary income subject to an allowance for cost or percentage depletion in respect of such income.

In contrast, the Term PDP Royalty and the Term PUD Royalty will have the tax characteristics of production payments governed by Section 636 of the Internal Revenue Code to the extent they may not, at the time of their creation, be reasonably expected to extend in substantial amounts over the entire productive lives of the mineral property or properties they burden. Payments out of production that are received in respect of a mineral interest that constitutes a production payment for U.S. federal income tax purposes are treated under current law as consisting of a receipt of principal and interest on a nonrecourse debt obligation, with the interest component being taxable as ordinary income.

In the event that a portion of a single royalty interest terminates by its terms prior to the point in time that the economically productive life of the burdened mineral property is substantially exhausted and the remaining portion continues to burden the property until its economically productive life is substantially exhausted, the federal income tax characteristics of the royalty interest are determined as if it comprised two separate interests, with the terminating portion being treated as a production payment and the continuing portion being treated as a royalty interest.

Based on the reserve report and representations made by SandRidge regarding the expected economic life of the Underlying Properties and the expected duration of the Term Royalties and the Perpetual Royalties, the Term PDP Royalty will and the Term PUD Royalty should be treated as “production payments” under Section 636 of the Internal Revenue Code, and thus as nonrecourse

 

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debt instruments of SandRidge for U.S. federal income tax purposes. The Perpetual PDP Royalty will and the Perpetual PUD Royalty should be treated as continuing, nonoperating economic interests in the nature of royalties payable out of production from the mineral interests they burden.

Consistent with this characterization, SandRidge and the trust intend to treat the Perpetual Royalties as mineral royalty interests for U.S. federal income tax purposes. In addition, SandRidge and the trust intend to treat the Term Royalties as debt instruments for U.S. federal income tax purposes subject to the Treasury Regulations applicable to contingent payment debt instruments (the “CPDI regulations”), and the trust will agree to be bound by SandRidge’s application of the CPDI regulations, including SandRidge’s determination of the rate at which interest will be deemed to accrue on the such interests. The remainder of this discussion assumes that the Term Royalties will be treated in accordance with that agreement and SandRidge’s determinations and that the Perpetual Royalties will be treated as mineral royalty interests. No assurance can be given that the IRS will not assert that such interests should be treated differently. Such different treatment could affect the amount, timing and character of income, gain or loss in respect of an investment in trust units and could require a trust unitholder to accrue interest income at a rate different than the “comparable yield” described below. Please read “—Tax Consequences of Trust Unit Ownership—Tax Treatment of the Term Royalties,” and “—Tax Consequences of Trust Unit Ownership—Tax Treatment of the Perpetual Royalties.”

Tax Consequences of Trust Unit Ownership

Flow-Through of Taxable Income.    As a partnership for U.S. federal income tax purposes, the trust will not be a taxable entity required to pay any federal income tax. Instead, each trust unitholder will be required to report on his income tax return his allocable share of the trust’s income, gains, losses, deductions and credits without regard to whether the trust makes cash distributions to him. Consequently, the trust may allocate taxable income to a trust unitholder even if he has not received a cash distribution.

Accounting Method and Taxable Year.    The trust will use the year ending December 31 as its taxable year and the accrual method of accounting for U.S. federal income tax purposes. Each trust unitholder will be required to include in income his share of the trust’s income, gain, loss, deduction and credit for the trust’s taxable year ending within or with his taxable year. In addition, a trust unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his trust units following the close of the trust’s taxable year but before the close of his taxable year must include his share of the trust’s income, gain, loss, deduction and credit in his taxable income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than 12 months of the trust’s income, gain, loss, deduction and credit. Please read “—Disposition of Trust Units—Allocations Between Transferors and Transferees.”

A trust unitholder’s initial tax basis for his trust units will be the amount he paid for the trust units. That basis will be increased by his share of the trust’s income and gain and decreased, but not below zero, by distributions from the trust, by the trust unitholder’s share of the trust’s losses, if any, by depletion deductions taken by him to the extent such deductions do not exceed his proportionate allocated share of the adjusted tax basis of the Perpetual Royalties, and by his share of the trust’s expenditures that are not deductible in computing taxable income and are not required to be capitalized. Please read “—Disposition of Trust Units—Recognition of Gain or Loss.”

Allocation of Income, Gain, Loss, Deduction and Credit.    In general, if the trust has a net profit, the trust’s items of income, gain, loss, deduction and credit will be allocated among the trust unitholders in accordance with their percentage interests in the trust. At any time that

 

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distributions are made to the common units in excess of distributions to the subordinated trust units, or incentive distributions are made in respect of the subordinated trust units, gross income will be allocated to the recipients to the extent of these distributions. If the trust has a net loss, that loss will be allocated first to the subordinated trust units to the extent of their positive capital accounts and thereafter to the trust unitholders in accordance with their percentage interests in the trust.

Specified items of the trust’s income, gain, loss, deduction and credit will be allocated under Section 704(c) of the Internal Revenue Code to account for any difference between the tax basis and fair market value of any property treated as having been contributed to the trust by SandRidge or certain of its affiliates that exists at the time of such contribution, together, referred to in this discussion as the “Contributed Property.” These “Section 704(c) Allocations” are required to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and the “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity.” The effect of these 704(c) Allocations to a unitholder purchasing trust units from the trust in this offering will be essentially the same as if the tax bases of the trust’s assets were equal to their fair market value at the time of this offering. Finally, although the trust does not expect that its operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of the trust’s income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.

An allocation of items of the trust’s income, gain, loss, deduction or credit, other than an allocation required by Section 704(c) of the Internal Revenue Code to eliminate the Book-Tax Disparity, will generally be given effect for U.S. federal income tax purposes in determining a unitholder’s share of an item of income, gain, loss, deduction or credit only if the allocation has substantial economic effect. In any other case, a unitholder’s share of an item will be determined on the basis of his interest in the trust, which will be determined by taking into account all the facts and circumstances, including:

 

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his relative contributions to the trust;

 

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the interests of all the partners in profits and losses;

 

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the interest of all the partners in cash flow; and

 

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the rights of all the partners to distributions of capital upon liquidation.

Covington & Burling LLP is of the opinion that, with the exception of the issues described in “Disposition of Trust Units—Allocations Between Transferors and Transferees,” allocations under the trust agreement will be given effect for U.S. federal income tax purposes in determining a partner’s share of an item of income, gain, loss, deduction or credit.

Treatment of Trust Distributions.    Distributions by the trust to a trust unitholder generally will not be taxable to the trust unitholder for U.S. federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his trust units immediately before the distribution. The trust’s cash distributions in excess of a unitholder’s tax basis (if any) generally will be considered to be gain from the sale or exchange of the trust units, taxable in accordance with the rules described under “—Disposition of Trust Units” below.

Ratio of Taxable Income to Distributions.    The trust estimates that a purchaser of trust units in this offering who owns those trust units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2013, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be approximately

 

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         or less of the cash distributed with respect to that period. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond the trust’s control. Further, the estimates are based on current tax law and tax reporting positions that the trust will adopt and with which the IRS could disagree. Accordingly, the trust cannot assure unitholders that these estimates will prove to be correct. The actual percentage of distributions that will correspond to taxable income could be higher or lower than expected, and any differences could be material and could materially affect the value of the trust units.

Tax Treatment of the Term Royalties.    Under the CPDI regulations, the trust generally will be required to accrue income on the Term Royalties which are treated as production payments, and therefore as nonrecourse debt obligations of SandRidge for U.S. federal income tax purposes, in the amounts described below.

The CPDI regulations provide that the trust must accrue an amount of ordinary interest income for U.S. federal income tax purposes, for each accrual period prior to and including the maturity date of the debt instrument that equals:

 

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the product of (i) the adjusted issue price (as defined below) of the debt instrument as of the beginning of the accrual period; and (ii) the comparable yield to maturity (as defined below) of such debt instrument, adjusted for the length of the accrual period;

 

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divided by the number of days in the accrual period; and

 

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multiplied by the number of days during the accrual period that the trust held the debt instrument.

The “issue price” of the debt instrument represented by each production payment held by the trust is the portion of the first price at which a substantial amount of the trust units is sold to the public, excluding sales to bond houses, brokers or similar persons or organizations acting in the capacity of underwriters, placement agents or wholesalers, that is allocable to the production payment based on the relative fair market value of the production payment to the other assets of the trust. The “adjusted issue price” of such a debt instrument is its issue price increased by any interest income previously accrued, determined without regard to any adjustments to interest accruals described below, and decreased by the projected amount of any payments scheduled to be made with respect to the debt instrument at an earlier time (without regard to the actual amount paid). The term “comparable yield” means the annual yield SandRidge would be expected to pay, as of the initial issue date, on a fixed rate debt security with no contingent payments but with terms and conditions otherwise comparable to those of the debt instrument represented by the production payment.

SandRidge and the trust intend to take the position that the comparable yield for each debt instrument held by the trust is an annual rate of 10%, compounded semi-annually. The CPDI regulations require that SandRidge provide to the trust, solely for determining the amount of interest accruals for U.S. federal income tax purposes, a schedule of the projected amounts of payments, which are referred to as projected payments, on the Term Royalties treated as debt instruments held by the trust. These payments set forth on the schedule must produce a total return on such debt instruments equal to their comparable yield. Amounts treated as interest under the CPDI regulations are treated as original issue discount for all purposes of the Internal Revenue Code.

As required by the CPDI regulations, for U.S. federal income tax purposes, the trust must use the comparable yield and the schedule of projected payments as described above in determining the trust’s interest accruals, and the adjustments thereto described below, in respect of the debt instruments held by the trust.

 

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SandRidge’s determinations of the comparable yield and the projected payment schedule are not binding on the IRS and it could challenge such determinations. If it did so, and if any such challenge were successful, then the amount and timing of interest income accruals of the trust would be different from those reported by the trust or included on previously filed tax returns by the trust unitholders.

The comparable yield and the schedule of projected payments are not determined for any purpose other than for the determination for U.S. federal income tax purposes of the trust’s interest accruals and adjustments thereof in respect of the debt instruments held by the trust and do not constitute a projection or representation regarding the actual amounts payable to the trust.

For U.S. federal income tax purposes, the trust is required under the CPDI regulations to use the comparable yield and the projected payment schedule established by SandRidge in determining interest accruals and adjustments in respect of the production payments, unless the trust timely discloses and justifies the use of a different comparable yield and projected payment schedule to the IRS. Pursuant to the terms of the conveyance, SandRidge and the trust have agreed (in the absence of an administrative determination or judicial ruling to the contrary) to be bound by SandRidge’s determination of the comparable yield and projected payment schedule.

If, during any taxable year, the trust receives actual payments with respect to a debt instrument held by the trust that in the aggregate exceed the total amount of projected payments for that taxable year, the trust will incur a “net positive adjustment” under the CPDI regulations equal to the amount of such excess. The trust will treat a “net positive adjustment” as additional interest income for such taxable year.

If the trust receives in a taxable year actual payments with respect to a debt instrument held by the trust that in the aggregate are less than the amount of projected payments for that taxable year, the trust will incur a “net negative adjustment” under the CPDI regulations equal to the amount of such deficit. This adjustment will (a) reduce the trust’s interest income on the debt instrument held by the trust for that taxable year, and (b) to the extent of any excess after the application of (a) give rise to an ordinary loss to the extent of the trust’s interest income on such debt instrument during prior taxable years, reduced to the extent such interest was offset by prior net negative adjustments. Any negative adjustment in excess of the amount described in (a) and (b) will be carried forward, as a negative adjustment to offset future interest income in respect of that debt instrument held by the trust. If either of the Term Royalties is not treated as a production payment (and hence not as a debt instrument) for U.S. federal income tax purposes, the trust intends to take the position that its basis in the Term Royalty is recouped in proportion to the production from the Term Royalty.

Neither the trust nor the trust unitholders are entitled to claim depletion deductions with respect to the Term Royalties.

Tax Treatment of the Perpetual Royalties.    The payments received by the trust in respect of the Perpetual Royalties treated as mineral royalty interests for U.S. federal income tax purposes should be treated as ordinary income. Trust unitholders should be entitled to deductions for the greater of either cost depletion or (if otherwise allowable) percentage depletion with respect to such income. Although the Internal Revenue Code requires each trust unitholder to compute his own depletion allowance and maintain records of his share of the adjusted tax basis of the underlying royalty interest for depletion and other purposes, the trust intends to furnish each of the trust unitholders with information relating to this computation for U.S. federal income tax purposes. Each trust unitholder, however, remains responsible for calculating his own depletion allowance and maintaining records of his share of the adjusted tax basis of the Perpetual Royalties for depletion and other purposes.

 

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Percentage depletion is generally available with respect to trust unitholders who qualify under the independent producer exemption contained in Section 613A(c) of the Internal Revenue Code. For this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil, oil and natural gas, or derivative products or the operation of a major refinery. Percentage depletion is calculated as an amount generally equal to 15% (and, in the case of marginal production, potentially a higher percentage) of the trust unitholder’s gross income from the depletable property for the taxable year. The percentage depletion deduction with respect to any property is limited to 100% of the taxable income of the trust unitholder from the property for each taxable year, computed without the depletion allowance. A trust unitholder that qualifies as an independent producer may deduct percentage depletion only to the extent the trust unitholder’s average daily production of domestic oil, or the natural gas equivalent, does not exceed 1,000 barrels. This depletable amount may be allocated between oil and natural gas production, with 6,000 cubic feet of domestic oil and natural gas production regarded as equivalent to one barrel of crude oil. The 1,000-barrel limitation must be allocated among the independent producer and controlled or related persons and family members in proportion to the respective production by such persons during the period in question.

In addition to the foregoing limitations, the percentage depletion deduction otherwise available is limited to 65% of a trust unitholder’s total taxable income from all sources for the year, computed without the depletion allowance, the deduction for domestic production activities, net operating loss carrybacks, or capital loss carrybacks. Any percentage depletion deduction disallowed because of the 65% limitation may be deducted in the following taxable year if the percentage depletion deduction for such year plus the deduction carryover does not exceed 65% of the trust unitholder’s total taxable income for that year. The carryover period resulting from the 65% net income limitation is unlimited.

In addition to the limitations on percentage depletion discussed above, on February 1, 2010, the White House released President Obama’s budget proposal for the fiscal year 2011. The President’s budget proposes to eliminate certain tax preferences applicable to taxpayers engaged in the exploration or production of natural resources. Specifically, the budget proposes to repeal the deduction for percentage depletion with respect to wells, in which case only cost depletion would be available. It is uncertain whether this or any other legislative proposals will ever be enacted and, if so, when it would become effective.

Trust unitholders that do not qualify under the independent producer exemption are generally restricted to depletion deductions based on cost depletion. Cost depletion deductions are calculated by (i) dividing the trust unitholder’s allocated share of the adjusted tax basis in the underlying mineral property by the number of mineral units (barrels of oil and thousand cubic feet of natural gas) remaining as of the beginning of the taxable year and (ii) multiplying the result by the number of mineral units sold within the taxable year. The total amount of deductions based on cost depletion cannot exceed the trust unitholder’s share of the total adjusted tax basis in the property.

The foregoing discussion of depletion deductions does not purport to be a complete analysis of the complex legislation and Treasury Regulations relating to the availability and calculation of depletion deductions by the trust unitholders. Further, because depletion is required to be computed separately by each trust unitholder and not by the trust, no assurance can be given, and counsel is unable to express any opinion, with respect to the availability or extent of percentage depletion deductions to the trust unitholders for any taxable year. The trust encourages each prospective trust unitholder to consult his tax advisor to determine whether percentage depletion would be available to him.

 

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Tax Treatment Upon Sale of the Perpetual Royalties at Termination Date.    The sale of the Perpetual Royalties by the trust at or shortly after the Termination Date will generally give rise to long-term capital gain or loss to the trust unitholders for U.S. federal income tax purposes, except that any gain will be taxed at ordinary income rates to the extent of depletion deductions that reduced the trust unitholder’s adjusted basis in the Perpetual Royalties. Each trust unitholder will be responsible for calculating his gain or loss based on the difference between his pro-rata share of the amount realized on the sale by the trust and his adjusted basis in the Perpetual Royalties, and if a gain is realized, the portion thereof taxable as ordinary income by reason of depletion deductions previously claimed by such trust unitholder. However, the trust intends to furnish each of the trust unitholders with information relating to this calculation for U.S. federal income tax purposes in connection with the final partnership tax return for the trust.

Limitations on Deductibility of Losses.    It is not anticipated that the trust will generate losses. Nevertheless, should losses result, trust unitholders must consult their own tax advisors as to the applicability to them of loss limitation rules that could operate to limit the deductibility to a trust unitholder of his share of the trust’s losses such as the basis limitation, the “at risk” rules and the passive loss rules. Special passive loss limitation rules apply with respect to publicly-traded partnerships.

Limitations on Interest Deductions.    The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

 

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interest on indebtedness properly allocable to property held for investment;

 

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the trust’s interest expense attributed to portfolio income; and

 

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the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a trust unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a trust unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment or qualified dividend income. The IRS has indicated that the net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders for purposes of the investment interest deduction limitation. In addition, the trust unitholder’s share of the trust’s portfolio income will be treated as investment income.

Entity-Level Withholdings.    If the trust is required or elects under applicable law to pay any federal, state, local or foreign income tax on behalf of any trust unitholder or any former trust unitholder, the trust is authorized to pay those taxes from its funds. That payment, if made, will be treated as a distribution of cash to the trust unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, the trust is authorized to treat the payment as a distribution to all current trust unitholders. The trust is authorized to amend its trust agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of trust units. Payments by the trust as described above could give rise to an overpayment of tax on behalf of an individual trust unitholder in which event the trust unitholder would be required to file a claim in order to obtain a credit or refund.

 

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Treatment of Short Sales.    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 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. As a result, during this period:

 

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any of the trust’s income, gain, loss, deduction or credit with respect to those trust units would not be reportable by the trust unitholder;

 

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any cash distributions received by the trust unitholder as to those trust units would be fully taxable; and

 

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all of these distributions would appear to be ordinary income.

Covington & Burling LLP has not rendered an opinion regarding the tax treatment of a trust unitholder whose trust units are loaned to a short seller to cover a short sale of trust units; therefore, trust unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and loaning their trust units. The IRS has previously announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read “—Disposition of Trust Units—Recognition of Gain or Loss.”

Alternative Minimum Tax.    Each trust unitholder will be required to take into account his distributive share of any items of the trust’s income, gain, loss, deduction or credit for purposes of the alternative minimum tax. The current minimum tax rate for non-corporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective trust unitholders are urged to consult with their tax advisors as to the impact of an investment in trust units on their liability for the alternative minimum tax.

Tax Rates.    Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 35% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than 12 months) of individuals is 15%. However, absent new legislation extending the current rates, beginning January 1, 2013, the highest marginal U.S. federal income tax rate applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. Moreover, these rates are subject to change by new legislation at any time.

The recently enacted Health Care and Education Reconciliation Act of 2010 will impose a 3.8% Medicare tax on certain investment income earned by individuals, estates and trusts for taxable years beginning after December 31, 2012. For these purposes, investment income generally includes a trust unitholder’s allocable share of the trust’s income and gain realized by a trust unitholder from a sale of trust units. In the case of an individual, the tax will be imposed on the lesser of (i) the trust unitholder’s net income from all investments, and (ii) the amount by which the trust unitholder’s adjusted gross income exceeds $250,000 (if the trust unitholder is married and filing jointly or a surviving spouse), $125,000 (if the trust unitholder is married and filing separately) or $200,000 (if the trust unitholder is not married). In the case of an estate or trust, the tax will be imposed on the lesser of (1) the undistributed net investment income of the estate or trust, or (2) the excess of the adjusted gross income of the estate or trust over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

Section 754 Election.    The trust will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election will generally permit the trust to adjust a subsequent trust unit purchaser’s tax basis in the trust’s assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect his purchase

 

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price of trust units acquired from another trust unitholder. The Section 743(b) adjustment belongs to the purchaser and not to other trust unitholders. For purposes of this discussion, a trust unitholder’s inside basis in the trust’s assets will be considered to have two components: (1) his share of tax basis in the trust’s assets (“common basis”) and (2) his Section 743(b) adjustment to that basis.

A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of the trust’s assets immediately prior to the transfer. In such a case, as a result of the election, the transferee would have a higher tax basis in his share of the trust’s assets for purposes of calculating, among other items, cost depletion deductions on the Perpetual Royalties, and his share of any gain on a sale of the trust’s assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those trust units’ share of the aggregate tax basis of the trust’s assets immediately prior to the transfer. Thus, the fair market value of the trust units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in the trust if it has a substantial built-in loss immediately after the transfer. Generally a built-in loss or a basis reduction is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of the trust’s assets and other matters. For example, the allocation of the Section 743(b) adjustment among the trust’s assets must be made in accordance with the Internal Revenue Code. The trust cannot assure unitholders that the determinations it makes will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in the trust’s opinion, the expense of compliance exceed the benefit of the election, the trust may seek permission from the IRS to revoke its Section 754 election. If permission is granted, a subsequent purchaser of trust units may be allocated more income than he would have been allocated had the election not been revoked.

Initial Tax Basis and Amortization.    The initial tax basis of the portion of the PDP Royalty Interest treated as a royalty interest in minerals and the portion treated as a production payment, and the initial basis of the portion of the PUD Royalty Interest treated as a royalty interest in minerals and the portion treated as a production payment will be effectively equal on a per-unit basis to the portion of the unit price allocated to each based on each such portion’s relative fair market value.

The costs incurred in selling the trust units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon the trust’s termination. There are uncertainties regarding the classification of costs as organizational expenses, which may be amortized by the trust, and as syndication expenses, which may not be amortized by the trust. The underwriting discounts and commissions the trust incurs will be treated as syndication expenses.

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

 

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Disposition of Trust Units

Recognition of Gain or Loss.    Gain or loss will be recognized on a sale of trust units equal to the difference between the amount realized and the trust unitholder’s tax basis for the trust units sold. A trust unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received. The amount realized should be reduced by the unused net negative adjustments attributable to the trust units disposed of as described above under “—Tax Consequences of Trust Unit Ownership—Tax Treatment of the Term Royalties.” A trust unitholder’s adjusted tax basis in his trust units will be equal to the trust unitholder’s original purchase price for the trust units, increased by income and decreased by losses or deductions previously allocated to the trust unitholder and by distributions to the trust unitholder and depletion deductions claimed by the trust unitholder.

Prior distributions from the trust in excess of cumulative net taxable income for a trust unit that decreased a unitholder’s tax basis in that trust unit will, in effect, become taxable income if the trust unit is sold at a price greater than the trust unitholder’s tax basis in that trust unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a trust unitholder, other than a “dealer” in trust units, on the sale or exchange of a trust unit will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of trust units held for more than 12 months will generally be taxed at a maximum U.S. federal income tax rate of 15% through December 31, 2012 and 20% thereafter (absent new legislation extending or adjusting the current rate). However, a portion, which will likely be substantial, of this gain or loss will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to “unrealized receivables” the trust owns. The term “unrealized receivables” includes potential recapture items, including depletion recapture. Ordinary income attributable to unrealized receivables such as depletion recapture may exceed net taxable gain realized upon the sale of a trust unit and may be recognized even if there is a net taxable loss realized on the sale of a trust unit. Thus, a trust unitholder may recognize both ordinary income and a capital loss upon a sale of trust units. Net capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling trust unitholder who can identify trust units transferred with an ascertainable holding period to elect to use the actual holding period of the trust units transferred. Thus, according to the ruling discussed above, a trust unitholder will be unable to select high or low basis trust units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, he may designate specific trust units sold for purposes of determining the holding period of trust units transferred. A trust unitholder electing to use the actual holding period of trust units transferred must consistently use that identification method for all subsequent sales or exchanges of trust units. A trust unitholder considering the purchase of additional trust units or a sale of trust units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

 

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Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

 

•

a short sale;

 

•

an offsetting notional principal contract; or

 

•

a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees.    In general, the trust’s taxable income and losses will be determined annually, will be allocated on a monthly basis and will be subsequently apportioned among the trust unitholders in proportion to the number of trust units owned by each of them as of the opening of the applicable exchange on which the trust units are then traded on the first business day of the month, which is referred to in this prospectus as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of the trust’s assets other than in the ordinary course of business will be allocated among the trust unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a trust unitholder transferring trust units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Internal Revenue Code, and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations. Recently, however, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations; however, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. Accordingly, Covington & Burling LLP is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee trust unitholders. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the trust unitholder’s interest, the trust’s taxable income or losses might be reallocated among the trust unitholders. The trust is authorized to revise its method of allocation between transferor and transferee trust unitholders, as well as trust unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A trust unitholder who owns trust units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of the trust’s income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

 

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Notification Requirements.    A trust unitholder who sells any of his trust units is generally required to notify the trust in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of trust units who purchases trust units from another trust unitholder is also generally required to notify the trust in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, the trust is required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify the trust of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who affects the sale or exchange through a broker who will satisfy such requirements.

Constructive Termination.    The trust will be considered to have been terminated for tax purposes if there are sales or exchanges which, in the aggregate, constitute 50% or more of the total interests in the trust’s capital and profits within a twelve-month period. For purposes of measuring whether the 50% threshold is reached, multiple sales of the same interest are counted only once. A constructive termination results in the closing of the trust’s taxable year for all trust unitholders. In the case of a trust unitholder reporting on a taxable year other than a calendar year, the closing of the trust’s taxable year may result in more than 12 months of the trust’s taxable income or loss being includable in his taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in the trust filing two tax returns (and trust unitholders may receive two Schedule K-1’s) for one fiscal year and the cost of the preparation of these returns will be borne by all trust unitholders. The trust would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code. A termination could also result in penalties if the trust was unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject the trust to, any tax legislation enacted before the termination.

Tax-Exempt Organization and Certain Other Investors

Ownership of trust units by employee benefit plans, other tax-exempt organizations, non-resident aliens, non-U.S. corporations and other non-U.S. persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them. If a potential investor is a tax-exempt entity or a non-U.S. person, then it should consult a tax advisor before investing in the trust units.

Tax-Exempt Organizations.    Employee benefit plans and most other organizations exempt from U.S. federal income tax including 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 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. In general, trust property would be debt-financed if the trust incurs debt to acquire the property or otherwise incurs or maintains a debt that would not have been incurred or maintained if the property had not been acquired and a trust unit would be debt-financed if the trust unitholder incurs debt to acquire the trust unit or otherwise incurs or maintains a debt that would not have been incurred or maintained if the trust unit had not been acquired.

Non-U.S. Persons.    The trust will be required to withhold (at a 30% rate or lower applicable treaty rate) on interest and royalty income allocable to non-U.S. trust unitholders.

 

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Moreover, each of the PDP Royalty Interest and the PUD Royalty Interest will be treated as a “United States real property interest” for U.S. federal income tax purposes. However, as long as the trust units are regularly traded on an established securities market, gain realized by a non-U.S. trust unitholder on a sale of trust units will be subject to U.S. federal income tax only if:

 

•

the gain is, or is treated as, effectively connected with business conducted by the non-U.S. trust unitholder in the United States, and in the case of an applicable tax treaty, is attributable to a U.S. permanent establishment maintained by the non-U.S. trust unitholder;

 

•

the non-U.S. trust unitholder is an individual who is present in the United States for at least 183 days in the year of the sale and certain other conditions are met; or

 

•

the non-U.S. trust unitholder owns currently, or owned at certain earlier times, directly or by applying certain attribution rules, more than 5% of the trust units.

Administrative Matters

Trust Information Returns and Audit Procedures.    The trust intends to furnish to each trust unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of the trust’s income, gain, loss and deduction for the trust’s preceding taxable year. In preparing this information, which will not be reviewed by counsel, the trust will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each trust unitholder’s share of income, gain, loss and deduction. The trust cannot assure unitholders that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither the trust nor Covington & Burling LLP can assure prospective trust unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit the trust’s U.S. federal income tax information returns. Adjustments resulting from an IRS audit may require each trust unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his return. Any audit of a trust unitholder’s return could result in adjustments not related to the trust’s returns as well as those related to the trust’s returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. The trust agreement names SandRidge as the trust’s Tax Matters Partner.

The Tax Matters Partner has made and will make some elections on behalf of the trust and the trust unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against trust unitholders for items in the trust’s returns. The Tax Matters Partner may bind a trust unitholder with less than a 1% profits interest in the trust to a settlement with the IRS unless that trust unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the trust unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any trust unitholder having at least a 1% interest in profits or by any group of trust unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each trust unitholder with an interest in the outcome may participate.

 

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A trust unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on the trust’s return. Intentional or negligent disregard of this consistency requirement may subject a trust unitholder to substantial penalties.

Nominee Reporting.    Persons who hold an interest in the trust as a nominee for another person are required to furnish to the trust:

(a) the name, address and taxpayer identification number of the beneficial owner and the nominee;

(b) whether the beneficial owner is:

(i) a person that is not a United States person;

(ii) a non-U.S. government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

(iii) a tax-exempt entity;

(c) the amount and description of units held, acquired or transferred for the beneficial owner; and

(d) specific information including the dates of acquisitions and transfers, means of acquisitions and transfers and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to the trust. The nominee is required to supply the beneficial owner of the trust units with the information furnished to the trust.

Accuracy-Related Penalties.    An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

(1) for which there is, or was, “substantial authority”; or

(2) as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of trust unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, the trust must disclose the pertinent facts on its return. In addition, the trust will make a reasonable effort to furnish sufficient information for trust unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit trust unitholders to avoid liability for this penalty. More stringent rules apply to “tax shelters,” which the trust does not believe includes it, or any of the trust’s investments, plans or arrangements.

 

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A substantial valuation misstatement exists if (a) the value of any property, or the tax basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or tax basis, (b) the price for any property or services (or for the use of property) claimed on any such return with respect to any transaction between persons described in Internal Revenue Code Section 482 is 200% or more (or 50% or less) of the amount determined under Section 482 to be the correct amount of such price, or (c) the net Internal Revenue Code Section 482 transfer price adjustment for the taxable year exceeds the lesser of $5 million or 10% of the taxpayer’s gross receipts.

No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). The penalty is increased to 40% in the event of a gross valuation misstatement. The trust does not anticipate making any valuation misstatements.

Reportable Transactions.    If the trust were to engage in a “reportable transaction,” the trust (and possibly the unitholders) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single year, or $4 million in any combination of 6 successive tax years. The trust’s participation in a reportable transaction could increase the likelihood that the trust’s U.S. federal income tax information return (and possibly the unitholders’ tax return) would be audited by the IRS. Please read “—Trust Information Returns and Audit Procedures.”

Moreover, if the trust were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, unitholders may be subject to the following provisions of the American Jobs Creation Act of 2004:

 

•

accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “—Accuracy-Related Penalties”;

 

•

for those persons otherwise entitled to deduct interest on federal tax deficiencies, non-deductibility of interest on any resulting tax liability; and

 

•

in the case of a listed transaction, an extended statute of limitations.

The trust does not expect to engage in any “reportable transactions.”

 

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STATE TAX CONSIDERATIONS

The following is intended as a brief summary of certain information regarding state income taxes and other state tax matters affecting individuals who are trust unitholders. Trust unitholders are urged to consult their own legal and tax advisors with respect to these matters.

Prospective investors should consider state and local income tax consequences of an investment in the common units. The trust will own royalty interests burdening specified oil and natural gas properties located in Alfalfa, Garfield, Grant, Major and Woods counties in Oklahoma. If the trust is treated as a partnership for Federal income tax purposes, it will also be treated as a partnership for Oklahoma income tax purposes. Trust unitholders will be subject to Oklahoma income tax on all trust royalty income allocable to the unitholders; accordingly, trust unitholders will be required to file Oklahoma state income tax returns and pay taxes in Oklahoma, and may be subject to penalties for failure to comply with such requirements. The highest marginal rates for the payment of Oklahoma state income taxes are 5.5% for individuals, trusts and estates, and 6% for corporations. Generally, Oklahoma taxpayers are entitled to a depletion allowance on oil and natural gas income for state income tax purposes equal to the greater of cost depletion or percentage depletion, with the percentage depletion allowance for most taxpayers being 22%, but not in excess of 50% of the gross income from the property; however, each trust unitholder should consult their own legal and tax advisors to determine the Oklahoma depletion allowance specifically applicable to such unitholder. Although payments to out-of-state interest owners, including beneficial owners such as trust unitholders, in respect of Oklahoma oil and natural gas income generally are subject to withholding for Oklahoma income tax purposes at the rate of 5%, an exception exists for publicly traded partnerships that furnish detailed information concerning beneficial owners to the Oklahoma Tax Commission. The trust plans to furnish such information and comply with those Oklahoma Tax Commission requirements as necessary to avoid withholding for Oklahoma state income tax purposes. Although Oklahoma municipalities are statutorily authorized to assess income taxes, no municipality has enacted such a tax. If any Oklahoma municipality were to enact an income tax, the tax could not be levied on nonresidents of the municipality.

 

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ERISA CONSIDERATIONS

The Employee Retirement Income Security Act of 1974, as amended (referred to as “ERISA”), regulates qualified pension plans, profit-sharing plans, stock bonus plans, simplified employee pension plans, Keogh plans, tax deferred annuities or IRAs established or maintained by an employer or employee organization, and other employee benefit plans to which it applies. ERISA also contains standards for persons who are fiduciaries of those plans. In addition, the Internal Revenue Code provides similar requirements and standards which are applicable to qualified plans, which include these types of plans, and to individual retirement accounts, whether or not subject to ERISA.

A fiduciary of a qualified plan should carefully consider fiduciary standards under ERISA regarding the qualified plan’s particular circumstances before authorizing an investment in trust units. Among other things, a fiduciary should consider:

 

•

whether the investment satisfies the prudence requirements of Section 404(a)(1)(B) of ERISA;

 

•

whether the investment satisfies the diversification requirements of Section 404(a)(1)(C) of ERISA; and

 

•

whether the investment is in accordance with the documents and instruments governing the qualified plan as required by Section 404(a)(1)(D) of ERISA.

A fiduciary should also consider whether an investment in common units might result in direct or indirect nonexempt prohibited transactions under Section 406 of ERISA and Internal Revenue Code Section 4975. In deciding whether an investment involves a prohibited transaction, a fiduciary must determine whether there are plan assets in the transaction. The Department of Labor has published regulations concerning whether or not a qualified plan’s assets would be deemed to include an interest in the underlying assets of an entity for purposes of the reporting, disclosure and fiduciary responsibility provisions of ERISA and analogous provisions of the Internal Revenue Code. These regulations provide that the underlying assets of an entity will not be considered “plan assets” if the equity interests in the entity are a publicly offered security. SandRidge expects that at the time of the sale of the trust units in this offering, they will be publicly offered securities.

However, the prohibited transaction rules are complex, and persons involved in prohibited transactions are subject to penalties. For that reason, potential qualified plan investors should consult with their counsel to determine the consequences under ERISA and the Internal Revenue Code of their acquisition and ownership of trust units.

 

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UNDERWRITING

Subject to the terms and conditions in an underwriting agreement dated , 2011, the underwriters named below, for whom Raymond James & Associates, Inc. and Morgan Stanley & Co. Incorporated, acting as representatives, have severally agreed to purchase from SandRidge the number of trust units set forth opposite their names:

 

Underwriter		Number of Trust Units
Raymond James & Associates, Inc.
Morgan Stanley & Co. Incorporated
Total			12,500,000

The underwriting agreement provides that the obligations of the underwriters to purchase and accept delivery of the trust units offered by this prospectus are subject to approval by their counsel of legal matters and to other conditions set forth in the underwriting agreement. The underwriters are obligated to purchase and accept delivery of all of the trust units offered by this prospectus if any of the units are purchased, other than those covered by the option to purchase additional trust units described below.

The underwriters propose to offer the trust units directly to the public at the public offering price indicated on the cover page of this prospectus and to various dealers at that price less a concession not in excess of $             per unit. If all of the trust units are not sold at the public offering price, the underwriters may change the public offering price and other selling terms. The trust units are offered by the underwriters as stated in this prospectus, subject to receipt and acceptance by them. The underwriters reserve the right to reject an order for the purchase of the trust units in whole or in part.

Option to Purchase Additional Trust Units

The trust has granted the underwriters an option, exercisable for 30 days after the date of this prospectus, to purchase from time to time up to an aggregate of 1,875,000 additional trust units to cover over-allotments, if any, at the public offering price less the underwriting discounts and commissions set forth on the cover page of this prospectus. If the underwriters exercise this option, each underwriter, subject to certain conditions, will become obligated to purchase its pro rata portion of these additional units based on the underwriters’ percentage purchase commitment in this offering as indicated in the table above. The underwriters may exercise the option to purchase additional trust units only to cover over-allotments made in connection with the sale of the trust units offered in this offering.

Discounts and Expenses

The following table shows the amount per unit and total underwriting discounts the trust will pay to the underwriters (dollars in thousands, except per unit). The amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional trust units.

 

Per Unit

No Exercise

Full Exercise

Price to public

$

$

$

Underwriting discounts and commissions

Proceeds to trust (before expenses)

 

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The trust will pay Raymond James & Associates, Inc. a structuring fee of $             (or $             if the underwriters exercise their option to purchase additional trust units to cover over-allotments) for evaluation, analysis and structuring of the trust.

The expenses of this offering that are payable by the trust are estimated to be $             (exclusive of underwriting discounts and commissions). In no event will the maximum amount of compensation to be paid to members of the Financial Industry Regulatory Authority, Inc. (“FINRA”) in connection with this offering exceed 10% plus 0.5% for bona fide due diligence expenses.

Indemnification

SandRidge has agreed to indemnify the underwriters and persons who control the underwriters against certain liabilities that may arise in connection with this offering, including liabilities under the Securities Act of 1933 and liabilities arising from breaches of representations and warranties contained in the underwriting agreement.

Lock-up Agreement

Subject to specified exceptions, SandRidge has agreed with the underwriters, for a period of 180 days after the date of this prospectus, without the prior written consent of Raymond James & Associates, Inc. and Morgan Stanley & Co. Incorporated:

 

•

not to offer, sell, contract to sell, announce the intention to sell or pledge any of the trust units;

 

•

not to grant or sell any option or contract to purchase any of the trust units;

 

•

not to enter into any swap or other agreement that transfers any of the economic consequences of ownership of or otherwise transfer or dispose of, directly or indirectly, any of the trust units (except for the hedging contracts underlying the derivatives agreement between SandRidge and the trust and other than commodity hedges effected by SandRidge in the ordinary course of its business); and

 

•

not to enter into any hedging, collar or other transaction or arrangement that is designed or reasonably expected to lead to or result in a transfer, in whole or in part, of any of the economic consequences of ownership of the trust units, whether or not such transfer would be for any consideration.

This agreement also prohibits SandRidge from entering into any of the foregoing transactions with respect to any securities that are convertible into or exchangeable for the trust units.

Raymond James & Associates, Inc. and Morgan Stanley & Co. Incorporated may, in their discretion and at any time without notice, release all or any portion of the securities subject to this agreement. Raymond James & Associates, Inc. and Morgan Stanley & Co. Incorporated do not have any present intent or any understanding to release all or any portion of the securities subject to this agreement.

The 180-day period described in the preceding paragraphs will be extended if:

 

•

during the last 17 days of the 180-day period, the trust issues a release concerning distributable cash or announces material news or a material event relating to the trust occurs; or

 

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•

prior to the expiration of the 180-day period, the trust announces that it will release distributable cash during the 16-day period beginning on the last day of the 180-day period, in which case the restrictions described in the preceding paragraphs will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release, the announcement of the material news or the occurrence of the material event.

Stabilization

Until this offering is completed, rules of the SEC may limit the ability of the underwriters and various selling group members to bid for and purchase the trust units. As an exception to these rules, the underwriters may engage in activities that stabilize, maintain or otherwise affect the price of the trust units, including:

 

•

short sales,

 

•

syndicate covering transactions,

 

•

imposition of penalty bids, and

 

•

purchases to cover positions created by short sales.

Stabilizing transactions consist of bids or purchases made for the purpose of preventing or retarding a decline in the market price of the trust units while this offering is in progress. Stabilizing transactions may include making short sales of trust units, which involve the sale by the underwriter of a greater number of trust units than it is required to purchase in this offering and purchasing trust units from SandRidge or in the open market to cover positions created by short sales. Short sales may be “covered” shorts, which are short positions in an amount not greater than the underwriters’ option to purchase additional trust units referred to above, or may be “naked” shorts, which are short positions in excess of that amount.

Each underwriter may close out any covered short position either by exercising its option to purchase additional trust units, in whole or in part, or by purchasing trust units in the open market. In making this determination, each underwriter will consider, among other things, the price of trust units available for purchase in the open market compared to the price at which the underwriter may purchase trust units pursuant to the option to purchase additional trust units.

A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the trust units in the open market that could adversely affect investors who purchased in this offering. To the extent that the underwriters create a naked short position, they will purchase trust units in the open market to cover the position.

The underwriters also may impose a penalty bid on selling group members. This means that if the underwriters purchase trust units in the open market in stabilizing transactions or to cover short sales, the underwriters can require the selling group members that sold those trust units as part of this offering to repay the selling concession received by them.

As a result of these activities, the price of the trust units may be higher than the price that otherwise might exist in the open market. If the underwriters commence these activities, they may discontinue them without notice at any time. The underwriters may carry out these transactions on the New York Stock Exchange or otherwise.

 

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Discretionary Accounts

The underwriters may confirm sales of the trust units offered by this prospectus to accounts over which they exercise discretionary authority but do not expect those sales to exceed 5% of the total trust units offered by this prospectus.

Listing

The trust intends to apply to have the units approved for listing on the New York Stock Exchange under the symbol “SDT.” In connection with the listing of the trust units on the New York Stock Exchange, the underwriters will undertake to sell round lots of 100 units or more to a minimum of 400 beneficial owners.

IPO Pricing

Prior to this offering, there has been no public market for the trust units. Consequently, the initial public offering price for the trust units will be determined by negotiations among SandRidge and the underwriters. The primary factors to be considered in determining the initial public offering price will be:

 

•

estimates of distributions to trust unitholders,

 

•

overall quality of the oil and natural gas properties attributable to the Underlying Properties,

 

•

industry and market conditions prevalent in the energy industry,

 

•

the information set forth in this prospectus and otherwise available to the representatives and

 

•

the general conditions of the securities markets at the time of this offering.

Electronic Prospectus

A prospectus in electronic format may be available on the Internet sites or through other online services maintained by one or more of the underwriters and selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the underwriter or the selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with SandRidge to allocate a specific number of trust units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the underwriters on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriter’s or any selling group member’s website and any information contained in any other website maintained by the underwriters or any selling group member is not part of this prospectus or the registration statement of which this prospectus forms a part, has not been approved or endorsed by SandRidge or any underwriters or any selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

 

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Conflicts/Affiliates

The underwriters and their affiliates may provide in the future investment banking, financial advisory or other financial services for SandRidge and its affiliates, for which they may receive advisory or transaction fees, as applicable, plus out-of-pocket expenses, of the nature and in amounts customary in the industry for these financial services. Affiliates of Morgan Stanley & Co. Incorporated are lenders under the SandRidge credit facility being repaid with the offering proceeds being paid to SandRidge and will therefore receive a portion of the proceeds of this offering.

FINRA Rules

Because FINRA is expected to view the trust units offered hereby as interests in a direct participation program, this offering is being made in compliance with Rule 2310 of the FINRA Conduct Rules. Investor suitability with respect to the trust units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

 

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LEGAL MATTERS

Richards, Layton & Finger, P.A., as special Delaware counsel to the trust, will give a legal opinion as to the validity of the trust units. Covington & Burling LLP, counsel to SandRidge, will give opinions as to certain other matters relating to the offering, including the tax opinion described in the section of this prospectus captioned “U.S. Federal Income Tax Considerations.” Certain legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Vinson & Elkins L.L.P.

EXPERTS

Certain information appearing in this prospectus regarding the December 31, 2010 estimated quantities of reserves of the Underlying Properties and royalty interests owned by the trust, the future net revenues from those reserves and their present value is based on estimates of the reserves and present values prepared by or derived from estimates prepared by Netherland Sewell & Associates, Inc., independent petroleum engineers.

Certain estimates of SandRidge’s proved reserves of oil and natural gas that are incorporated by reference in this prospectus were based in part upon engineering reports prepared by independent petroleum engineers Netherland, Sewell & Associates, Inc., DeGolyer and MacNaughton and Lee Keeling and Associates, Inc. and, with respect to proved reserves of oil and natural gas as of December 31, 2009 of Arena Resources, Inc., Williamson Petroleum Consultants, Inc. These estimates are referred to or incorporated by reference herein in reliance on the authority of such firms as experts in such matters.

The financial statements of SandRidge and management’s assessment of the effectiveness of internal control over financial reporting (which is included in Management’s Report on Internal Control over Financial Reporting) incorporated in this Prospectus by reference to SandRidge’s Annual Report on Form 10-K for the year ended December 31, 2009 have been so incorporated in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

The consolidated financial statements for the year ended December 31, 2009 of Arena Resources, Inc. (“Arena”) are incorporated in this prospectus by reference to Arena’s Annual Report on Form 10-K for the year ended December 31, 2009, filed with the SEC on March 1, 2010 (as amended on April 30, 2010). Such historical financial statements of Arena and the effectiveness of Arena’s internal control over financial reporting have been audited by Hansen, Barnett & Maxwell, P.C., an independent registered public accounting firm, as stated in their reports dated March 1, 2010 and incorporated herein.

The Statements of Revenues and Direct Operating Expenses of the SandRidge Mississippian Formation Underlying Properties for the year ended December 31, 2009 and the nine months ended September 30, 2010, included in this prospectus, have been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

The Statement of Assets and Trust Corpus of the SandRidge Mississippian Trust I as of December 30, 2010, included in this prospectus, has been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

 

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WHERE YOU CAN FIND MORE INFORMATION

The trust and SandRidge have filed with the SEC a registration statement on Form S-1 and Form S-3 regarding the common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding the trust, SandRidge and the common units offered by this prospectus, you may wish to review the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statement of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains a website on the Internet at http://www.sec.gov. The trust’s and SandRidge’s registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC’s web site.

SandRidge files annual, quarterly and current reports, proxy statements and other information with the SEC) (File No. 001-33784) pursuant to the Exchange Act. SandRidge’s SEC filings are available to the public through the SEC’s website.

This prospectus includes through incorporation by reference certain of the reports and other information that SandRidge has filed with the SEC. This means that SandRidge is disclosing important information to you by referring to those documents. The information that SandRidge later files with the SEC is incorporated by reference herein and will automatically update and supersede this information. SandRidge hereby incorporates by reference into this prospectus the documents listed below that SandRidge has filed with the SEC and any future filings that it makes with the SEC under Sections 13(a), 13(c), 14 or 15(d) of the Exchange Act (excluding any information furnished under Item 2.02 or Item 7.01 on any Current Report on Form 8-K) prior to the later of (i) the closing date of the offering and (ii) the completion of the offering of the common units:

 

•

SandRidge’s Annual Report on Form 10-K for the year ended December 31, 2009, filed with the SEC on March 1, 2010;

 

•

SandRidge’s Quarterly Reports on Form 10-Q for the periods ended March 31, 2010, June 30, 2010 and September 30, 2010, filed with the SEC on May 7, 2010, August 9, 2010 and November 8, 2010, respectively;

 

•

SandRidge’s Current Reports on Form 8-K/A filed with the SEC on March 8, 2010 and December 22, 2010, and Current Reports on Form 8-K filed with the SEC on each of April 5, 2010 (two filings), April 28, 2010, May 28, 2010, June 2, 2010, June 8, 2010, July 16, 2010 (as amended on September 20, 2010), October 21, 2010, October 28, 2010, November 10, 2010, December 21, 2010, December 27, 2010 and January 10, 2011; and

 

•

SandRidge’s definitive proxy statement on Schedule 14A, filed with the SEC on April 26, 2010.

SandRidge’s recent annual, quarterly and current reports, and any amendments thereto, that it files with the SEC are made available, free of charge, over the Internet through SandRidge’s website at http:www.sandridgeenergy.com as soon as reasonably practicable after SandRidge electronically files them with or furnishes them to the SEC. You may also request copies of any of SandRidge’s filings with the SEC, which it will provide at no cost to you, by contacting SandRidge’s Investor Relations department at 405-429-5515 or investors@sdrge.com. Please note that SandRidge’s website and the information contained in and linked to it are not incorporated in this prospectus.

 

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GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS AND TERMS RELATED TO THE TRUST

In this prospectus the following terms have the meanings specified below.

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

BBtu.    Billion British Thermal Units.

BBtu/d.    Billion British Thermal Units per day.

Bcfe.    Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.

Boe.    Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.

Boe/d.    Barrels of oil equivalent per day.

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

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

Condensate.    A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

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

Development costs.    Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and 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 lease, 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.

 

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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.

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 geologic barriers, or by 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.

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

MBbls.    Thousand barrels of oil or other liquid hydrocarbons.

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

MBoe.    Thousand barrels of oil equivalent.

Mcf.    Thousand cubic feet of natural gas.

MMBbls.    Million barrels of oil or other liquid hydrocarbons.

MMBoe.    Million barrels of oil equivalent.

MMBtu.    Million British Thermal Units.

MMcf.    Million cubic feet of natural gas.

MMcf/d.    MMcf per day.

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

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

 

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Production costs.

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

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

(B) Repairs and maintenance.

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

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

(E) Severance taxes.

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

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

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

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

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

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

 

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

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

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

Pulling units.    Pulling units are used in connection with completions and workover operations.

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

Rental tools.    A variety of rental tools and equipment, ranging from trash trailers to blow out preventors to sand separators, for use in the oil field.

Reserves.    Estimated remaining quantities of oil and gas and related substances anticipated to be economically producible as of a given date, 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 gas or related substances to market, and all permits and financing required to implement the project.

Included Note: 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 gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Roustabout services.    The provision of manpower to assist in conducting oil field operations.

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.

 

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Trucking.    The provision of trucks to move our drilling rigs from one well location to another and to deliver water and equipment to the field.

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 gas regardless of whether such acreage contains proved reserves.

Undeveloped oil and 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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INDEX TO FINANCIAL STATEMENTS

TABLE OF CONTENTS

 

SANDRIDGE MISSISSIPPIAN FORMATION UNDERLYING PROPERTIES
Report of Independent Registered Public Accounting Firm			F-2
Statements of Revenues and Direct Operating Expenses for the Year Ended December  31, 2009 and the Nine Months Ended September 30, 2010			F-3
Notes to Statements of Revenues and Direct Operating Expenses			F-4
SANDRIDGE MISSISSIPPIAN TRUST I
Report of Independent Registered Public Accounting Firm			F-8
Statement of Assets and Trust Corpus as of December 30, 2010			F-9
Notes to Statement of Assets and Trust Corpus			F-10
UNAUDITED PRO FORMA FINANCIAL INFORMATION
Unaudited Pro Forma Statements of Assets and Trust Corpus as of September 30, 2010			F-14
Unaudited Pro Forma Statements of Distributable Income for the Trust for the Year Ended December  31, 2009 and the Nine Months Ended September 30, 2010			F-15
Notes to Unaudited Pro Forma Financial Information			F-16

 

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Report of Independent Registered Public Accounting Firm

To Board of Directors and Stockholders of SandRidge Energy, Inc.:

We have audited the accompanying statements of revenues and direct operating expenses of the SandRidge Mississippian Formation Underlying Properties, described in Note 1, for the year ended December 31, 2009 and the nine month period ended September 30, 2010. These financial statements are the responsibility of SandRidge Energy, Inc.’s management. Our responsibility is to express an opinion on these financial statements based on our 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 audit to obtain reasonable assurance about whether the statements of revenues and direct operating expenses of the SandRidge Mississippian Formation Underlying Properties are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the statements of revenues and direct operating expenses of the SandRidge Mississippian Formation Underlying Properties. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of the SandRidge Mississippian Formation Underlying Properties for year ended December 31, 2009 and the nine month period ended September 30, 2010 in conformity with accounting principles generally accepted in the United States of America.

The accompanying statements reflect the revenues and direct operating expenses of the SandRidge Mississippian Formation Underlying Properties as described in Note 1 to the financial statements and are not intended to be a complete presentation of the financial position, results of operations or cash flows of the SandRidge Mississippian Formation Underlying Properties.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

January 5, 2011

 

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SANDRIDGE MISSISSIPPIAN FORMATION UNDERLYING PROPERTIES

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

(In Thousands)

 

		Year Ended December 31, 2009				Nine Months Ended September 30, 2010
Oil and natural gas revenue		$	550			$	11,823
Direct operating expenses:
Lease operating expense			294				1,675
Production taxes and other post-production expenses			40				1,141
Total direct operating expenses			334				2,816
Revenues in excess of direct operating expenses		$	216			$	9,007

 

 

 

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

 

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SANDRIDGE MISSISSIPPIAN FORMATION UNDERLYING PROPERTIES

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

1. Basis of Presentation

The accompanying statements present the revenues and direct operating expenses for the year ended December 31, 2009 and the nine-month period ended September 30, 2010 of working interests in certain oil and natural gas properties located in Oklahoma (“Underlying Properties”) owned by SandRidge Energy, Inc. (“SandRidge”) from which royalty interests to be conveyed to SandRidge Mississippian Trust I (the “Trust”) will be derived. As of September 30, 2010 the Underlying Properties consisted of 27 producing wells, the first of which began production in April 2009, as well as horizontal development wells to be drilled to the Mississippian formation within the Area of Mutual Interest (“AMI”), which consists of approximately 63,500 gross acres (42,600 net acres) in Alfalfa, Garfield, Grant, Major and Woods counties, Oklahoma, in which SandRidge owned an average of approximately 67.125% of the working interests.

The accompanying statements of revenues and direct operating expenses are presented on the accrual basis of accounting and were derived from the historical accounting records of SandRidge. Revenues and direct operating expenses relate to the historical net revenue interest and net working interest, respectively, in the Underlying Properties. Oil and natural gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price when delivery has occurred and title has transferred, and if collectability of the revenue is probable. Revenues are reported net of existing overriding and other royalties due to third parties. Direct operating expenses include lease and well repairs, maintenance, utilities, payroll, production taxes, gathering and transportation and other direct operating expenses. The amounts presented represent 100% of SandRidge’s interests in the Underlying Properties.

During the periods presented, the Underlying Properties were not accounted for as a separate division by SandRidge and therefore certain costs such as depreciation, depletion and amortization, accretion of asset retirement obligation, general and administrative expenses, interest, and corporate income taxes were not allocated to the individual properties. Historical statements reflecting financial position, results of operations and cash flows from operating, investing and financing activities prepared in accordance with generally accepted accounting principles are not presented because the information necessary to prepare such statements is neither readily available on an individual property basis nor practicable to obtain in these circumstances. Accordingly, the statements of revenues and direct operating expenses of the Underlying Properties are presented in lieu of the financial statements required under Rule 3-01 and 3-02 of the Securities and Exchange Commission Regulation S-X.

2. Subsequent Events

Events occurring after September 30, 2010 were evaluated through January 5, 2011 to ensure that any subsequent events that met the criteria for recognition and/or disclosure in this report have been included.

3. Supplemental Oil and Natural Gas Reserve and Standardized Measure Information (Unaudited)

The following oil and natural gas reserve information was prepared by SandRidge based upon information provided by SandRidge’s reserve engineers and is presented in accordance with ASC Topic 932, Extractive Activities—Oil and Gas.

 

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Oil and Gas Reserve Quantities

Proved oil and natural gas reserves are those quantities of oil and natural gas that, by analysis of geosciences 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.

The following table presents the estimated remaining net proved, proved developed and proved undeveloped oil and natural gas reserves of the Underlying Properties, all of which are located in the continental United States, estimated by SandRidge’s petroleum engineers, and the related summary of changes in estimated quantities of net remaining proved reserves during the year ended December 31, 2009 and the nine-month period ended September 30, 2010. These reserves represent the total proved reserves for the remaining economic life of the Underlying Properties and do not represent the reserves that will be owned by the Trust. A table setting forth the reserves that will be owned by the Trust can be found on page F-19.

 

		Oil (Bbls)				Gas (Mcf)
Proved Reserves
As of December 31, 2008			—				—
Extensions and discoveries (a)			386,964				1,470,626
Production			(6,878	)			(40,534	)
As of December 31, 2009			380,086				1,430,092
Revisions of previous estimates			217,431				4,562,805
Extensions and discoveries (a)			13,306,327				80,435,915
Production			(132,595	)			(651,995	)
As of September 30, 2010			13,771,249				85,776,817
Proved developed reserves:
As of December 31, 2009			82,033				738,183
As of September 30, 2010			2,295,004				21,509,848
Proved undeveloped reserves:
As of December 31, 2009			298,053				691,909
As of September 30, 2010			11,476,245				64,266,969

 

(a)

Extensions and discoveries for the year ended December 31, 2009 and nine months ended September 30, 2010 are a result of the discovery and production from wells drilled horizontally in the Mississippian formation in northern Oklahoma on acreage owned by SandRidge. The formation had previously been drilled and produced from vertical wells. During the year ended December 31, 2009 and the nine months ended September 30, 2010, SandRidge drilled or participated in the drilling of 5 and 22 wells, respectively, from which a portion of royalty interests conveyed to the Trust will be derived. These wells demonstrated consistent levels of production and provided reasonable certainty that wells to be drilled within the acreage qualified for Proved Undeveloped classification.

 

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Standardized Measure of Discounted Future Net Cash Flows

Certain information concerning the assumptions used in computing the valuation of proved developed reserves and their inherent limitations are discussed below. SandRidge believes such information is essential for a proper understanding and assessment of the data presented. These assumptions are summarized as follows:

 

•

Pricing is applied based upon 12-month average market prices, using the first-day-of-the-month price for each month, at December 31, 2009 and September 30, 2010 adjusted for fixed or determinable contracts that were in existence at period end. The calculated weighted average per unit prices for the Underlying Properties’ proved reserves and future net revenues were as follows:

 

		December 31, 2009				September 30, 2010
Oil (per Bbl)		$	54.86			$	71.95
Natural gas (per Mcf)		$	3.51			$	4.09

 

•

Future development and production costs are determined based upon actual cost at period end.

 

•

The standardized measure of discounted future net cash flows includes projections of future abandonment costs at period end.

 

•

Future income taxes are not computed because the Underlying Properties are not tax paying entities and because taxable income for the Trust will be passed through to the Trust unitholders.

 

•

An annual discount factor of 10% is applied to the future net cash flows.

Extensive judgments are involved in estimating the timing of production and the costs that will be incurred throughout the remaining lives of the properties. Accordingly, the estimates of future net cash flows from proved reserves and the present value may be materially different from subsequent actual results. The standardized measure of discounted net cash flows does not purport to present, nor should it be interpreted to present, the fair value of the Underlying Properties’ oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, and anticipated future changes in prices and costs. The following table presents future net cash flows relating to the Underlying Properties based on the standardized measure in ASC Topic 932 (in thousands).

 

		December 31, 2009
Future cash inflows from production		$	25,868
Future production costs			(7,822	)
Future development costs (a)			(4,800	)
Undiscounted future net cash flows			13,246
10% annual discount			(7,808	)
Standardized measure of discounted future net cash flows		$	5,438

 

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		September 30, 2010
Future cash inflows from production		$	1,341,638
Future production costs			(303,562	)
Future development costs (a)			(181,680	)
Undiscounted future net cash flows			856,396
10% annual discount			(534,056	)
Standardized measure of discounted future net cash flows		$	322,340

 

(a)	Includes future abandonment costs.

Changes in the standardized measure of future net cash flows related to proved oil and gas reserves are as follows for the year ended December 31, 2009 and the nine-month period ended September 30, 2010.

 

Present value as of December 31, 2008		$	—
Changes during the period:
Revenues less production and other costs			(216	)
Extensions and discoveries			5,654
Net change for the period			5,438
Present value as of December 31, 2009			5,438
Changes during the period:
Revenues less production and other costs			(9,007	)
Net changes in prices, production and other costs			1,541
Development costs incurred			5,642
Net changes in future development costs			(842	)
Extensions and discoveries			304,945
Revisions of previous quantity estimates			8,932
Accretion of discount			527
Timing differences and other (a)			5,164
Net change for the period			316,902
Present value as of September 30, 2010		$	322,340

 

(a)	The change in timing differences and other are related to revisions in estimated time of production and development.

 

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of SandRidge Energy, Inc:

We have audited the accompanying statement of assets and trust corpus of SandRidge Mississippian Trust I as of December 30, 2010 (date of formation). This financial statement is the responsibility of the Trust’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

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

As described in Note 2, this financial statement was 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.

In our opinion, the financial statement referred to above presents fairly, in all material respects, the assets and trust corpus of SandRidge Mississippian Trust I at December 30, 2010 (date of formation), on the basis of accounting described in Note 2.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

January 5, 2011

 

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SANDRIDGE MISSISSIPPIAN TRUST I

STATEMENT OF ASSETS AND TRUST CORPUS

 

		As of December 30, 2010
Assets:
Cash		$	1,000
Total Assets		$	1,000
Trust Corpus:
Trust corpus		$	1,000
Total		$	1,000

 

 

 

The accompanying notes are an integral part of this statement.

 

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SANDRIDGE MISSISSIPPIAN TRUST I

NOTES TO STATEMENT OF ASSETS AND TRUST CORPUS

1. Organization of the Trust

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 (the “Trust Agreement”) among and by SandRidge Energy, Inc. (“SandRidge”), as trustor, The Bank of New York Mellon Trust Company, N.A., as Trustee (the “Trustee”), and The Corporation Trust Company, as Delaware Trustee (the “Delaware Trustee”).

The Trust was created to acquire and hold royalty interests for the benefit of Trust unitholders pursuant to an agreement between SandRidge, the Trustee and the Delaware Trustee. These royalty interests are interests in underlying properties consisting of SandRidge’s interests in specified oil and gas properties located in the Mississippian formation in Alfalfa, Garfield, Grant, Major and Woods counties, Oklahoma (the “Underlying Properties”). These properties consist of 36 producing wells at December 30, 2010, the first of which began production in April 2009, one additional well undergoing completion operations (together, the “Underlying PDP Properties”) and 123 horizontal oil and natural gas development wells to be drilled to the Mississippian formation (“Underlying PUD Properties”) in an area of mutual interest.

The royalty interests are 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. After the conveyance of royalty interests, SandRidge will retain interests in each of the Underlying PDP Properties and Underlying PUD properties. The Trust Agreement will provide that the Trust’s business activities will be 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 and a commodity derivatives agreement with SandRidge described below.

The Trust will enter into a development agreement with SandRidge that will obligate SandRidge to drill, or cause to be drilled, the equivalent of 123 horizontal oil and natural gas development wells (as defined in the agreement) by December 31, 2014. In the event of delays, SandRidge will have until December 31, 2015 to fulfill its drilling obligation. Additionally, SandRidge will agree 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 development wells until SandRidge has fulfilled its drilling obligation. A wholly owned subsidiary of SandRidge will grant to the Trust a lien covering its interest in the AMI (except the Underlying PDP Properties or any other wells already producing and not subject to the royalty interests) in order to secure the estimated amount of the drilling costs for the Trust’s interests in the Underlying PUD Properties. These liens will be released over time as SandRidge fulfills its drilling obligation under the development agreement.

The Trust will enter into an administrative services agreement with SandRidge pursuant to which SandRidge will provide the Trust with certain accounting, tax preparation, bookkeeping and informational services related to the royalty interests. In return for these services, the Trust will pay SandRidge an annual fee of $200,000 in addition to reimbursement for SandRidge’s actual out-of-pocket fees, costs and expenses incurred in connection with the provision of any of the services under the agreement. The administrative services agreement will terminate on the earliest of: (i) December 31, 2030, (ii) termination of the royalty interests or disposal of the royalty interests held by the Trust, (iii) if properties are transferred by SandRidge to a third party, upon 90-days written notice by either SandRidge or the Trustee, provided SandRidge has met its drilling

 

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obligation and the transferee of such properties agrees to assume responsibility to provide the services in place of SandRidge and (iv) a date mutually agreed by SandRidge and the Trustee.

SandRidge, as the counterparty, will also enter into a commodity derivatives agreement with the Trust, covering approximately 60% of estimated production attributable to the Trust’s royalty interests through December 31, 2015, to provide the Trust with the benefit of hedging contracts entered into between SandRidge and third parties. The Trust’s receipt of any payments due based on the commodity derivatives agreement depends upon the financial position of SandRidge and SandRidge’s hedge contract counterparties. A default by any of the hedge counterparties could reduce the amount of cash available for distributions to the Trust unitholders. The Trust does not have the ability to enter into its own hedges.

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. Fifty percent of the royalty interests will automatically revert to SandRidge at the Termination Date, while the remaining royalty interests will be sold and the proceeds will be distributed to the Trust unitholders at the Termination Date or soon thereafter. SandRidge will have a right of first refusal to purchase the remaining fifty percent of the royalty interests at the Termination Date.

2. Significant Accounting Policies

The following is a summary of the significant accounting policies followed by the Trust.

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

 

•

Revenues are recorded when received and distributions to Trust unitholders are recorded when paid.

 

•

Trust expenses are recorded when paid.

 

•

Cash reserves may be established for certain contingencies that would not generally be recorded under generally accepted accounting principles.

 

•

Amortization of the investment in royalty interests is calculated on the units of production method. Such amortization is charged directly to the Trust corpus, and does not affect cash earnings. The Trust evaluates impairment of the investment in royalty interest by comparing the undiscounted cash flows expected to be realized from the investment in royalty interest to its carrying value, net of accumulated amortization.

While these statements differ from financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”), the modified cash basis of reporting revenues, expenses and distributions is considered to be the most meaningful because quarterly distributions to the Trust unitholders are based on net cash receipts. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.

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

 

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Cash.    Cash consists of highly liquid instruments with maturities of three months or less at the time of acquisition.

Use of Estimates.    The preparation of financial statements requires the Trust to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

3. Income Taxes

The Trust is a Delaware statutory trust and is not required to pay federal or state income taxes.

4. Distributions to Unitholders

The Trust will make quarterly cash distributions of the cash received from SandRidge, after deducting trust administrative expenses paid on or about 60 days after the completion of each quarter through (and including) the quarter ending December 31, 2030, the Termination Date. The first quarterly distribution, which will cover the first and second quarters of 2011, is expected to be made on or about August 30, 2011 to record unitholders as of August 15, 2011. Upon termination of the Trust, 50% of each of the PDP royalty interest and the PUD royalty interest will be sold, and the net proceeds therefrom will be distributed pro rata to the unitholders soon after the Termination Date. Because payments to the Trust will be generated by depleting assets and the Trust has a finite life with the production from the Underlying Properties diminishing over time, a portion of each distribution will represent a return of original investment to the unitholders.

5. Trust Operating Expenses

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. 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 arms’ length transaction between SandRidge and an unaffiliated third party.

 

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SANDRIDGE MISSISSIPPIAN TRUST I

UNAUDITED PRO FORMA FINANCIAL INFORMATION

The following unaudited pro forma statement of assets and trust corpus and unaudited pro forma statements of distributable income for SandRidge Mississippian Trust I (the “Trust”) have been prepared to illustrate the conveyance of royalty interests in certain Underlying Properties to the Trust by SandRidge Energy, Inc. (“SandRidge”). The unaudited pro forma statement of assets and trust corpus presents the beginning statement of assets and trust corpus of the Trust as of September 30, 2010, giving effect to the initial funding of the Trust and the royalty interests conveyance as if those transactions occurred on that date. The unaudited pro forma statement of distributable income presents the statements of historical revenue and direct operating expenses of the Underlying Properties for the year ended December 31, 2009 and the nine-month period ended September 30, 2010, giving effect to the royalty interests conveyance as if it occurred on January 1, 2009, reflecting only pro forma adjustments expected to have a continuing impact on the combined results.

These unaudited pro forma financial statements are for informational purposes only. They do not purport to present the results that would have actually occurred had the royalty interests conveyance been completed on the assumed dates or for the periods presented, or which may be realized in the future.

To produce the pro forma financial information, management made certain estimates. The accompanying pro forma statement of assets and trust corpus assumes a September 30, 2010 Trust formation and conveyance of the royalty interests by SandRidge. The accompanying unaudited pro forma statements of distributable income for the year ended December 31, 2009 and the nine-month period ended September 30, 2010, have been prepared assuming conveyance of royalty interests at the beginning of the period presented.

These estimates are based on the most recently available information. To the extent there are significant changes in these amounts, the assumptions and estimates herein could change significantly. These unaudited pro forma statements of distributable income should be read in conjunction with “Discussion and Analysis of Historical Results from the Producing Wells” included in this prospectus and the historical financial statements of the Trust and the Underlying Properties, including the related notes, included in this prospectus, and of SandRidge, incorporated by reference from its Annual Report on Form 10-K for the year ended December 31, 2009 and its Quarterly Report on Form 10-Q for the nine months ended September 30, 2010.

 

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SANDRIDGE MISSISSIPPIAN TRUST I

UNAUDITED PRO FORMA STATEMENTS OF ASSETS AND TRUST CORPUS

AS OF SEPTEMBER 30, 2010

(In Thousands)

 

		Historical				Adjustments				Pro Forma
Assets:
Cash (a)		$	—			$	1			$	1
Investment in Royalty Interest (b)			—				185,106				185,106
Total Assets		$	—			$	185,107			$	185,107
Trust Corpus:
Trust Units Issued and Outstanding (a)(b)(c)		$	—			$	185,107			$	185,107

 

 

The accompanying notes are an integral part of this unaudited pro forma financial information.

 

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SANDRIDGE MISSISSIPPIAN TRUST I

UNAUDITED PRO FORMA STATEMENTS OF DISTRIBUTABLE INCOME

(In Thousands, Except Per Unit Data)

 

		Year Ended December 31, 2009				Nine Months Ended September 30, 2010
Historical results:
Oil and natural gas revenue		$	550			$	11,823
Direct operating expenses:
Lease operating expense			294				1,675
Production taxes and other post-production expenses			40				1,141
Revenues in excess of operating expenses before pro forma adjustments			216				9,007
Pro Forma Adjustments:
Direct operating expenses:
Elimination of historical lease operating expense (d)			294				1,675
Pro forma gross net proceeds			510				10,682
Overriding royalty interest percentage			90	%			90	%
Net proceeds to trust			459				9,614
Less:
Trust general and administrative expenses (e)(f)			900				675
Distributable income (f)(g)		$	(441	)		$	8,939
Distributable income per unit (c)(f)		$	(0.02	)		$	0.35

 

The accompanying notes are an integral part of this unaudited pro forma financial information.

 

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SANDRIDGE MISSISSIPPIAN TRUST I

NOTES TO UNAUDITED PRO FORMA FINANCIAL INFORMATION

1. Basis of Presentation

SandRidge Mississippian Trust I (the “Trust”) is a Delaware statutory trust formed in December 2010 by SandRidge Energy, Inc. to own royalty interests in 36 producing horizontal oil and gas wells producing from the Mississippian formation in Alfalfa, Garfield, Grant, Major and Woods counties, Oklahoma, together with 1 additional well undergoing completion operations (the “Producing Wells”) and royalty interests in 123 horizontal oil and natural gas development wells to be drilled (the “PUD Wells”) within an Area of Mutual Interest (“AMI”). The AMI consists of approximately 63,500 gross acres (42,600 net acres) in the Mississippian formation in Oklahoma. SandRidge holds approximately 780,000 acres in the AMI. SandRidge is obligated to drill, or cause to be drilled, the 123 development wells from its drilling locations in the AMI. Until SandRidge has satisfied its drilling obligation, it will not be permitted to drill and complete any well on lease acreage included within the AMI for its own account. Also, a wholly owned subsidiary of SandRidge will grant to the Trust a lien on SandRidge’s interest in the AMI (except currently producing wells) in order to secure its drilling obligation to the Trust. The royalty interests will be conveyed from SandRidge’s interest in the Producing Wells and the PUD Wells in the AMI (the “Underlying Properties”). The royalty interest in the Producing Wells (the “PDP Royalty Interest”) entitles the Trust to receive 90% of the proceeds (exclusive of any production or development costs but after deducting post-production costs and any applicable taxes) from the sale of oil and natural gas production attributable to SandRidge’s interest in the Producing Wells. The royalty interest in the PUD Wells (the “PUD Royalty Interest”) entitles the Trust to receive 50% of the proceeds (exclusive of any production or development costs but after deducting post-production costs and any applicable taxes) from the sale of oil and natural gas production attributable to SandRidge’s interest in the PUD Wells.

SandRidge, as the counterparty, will also enter into a commodity derivatives agreement with the Trust, covering approximately 60% of estimated production attributable to the Trust’s royalty interests through December 31, 2015, to provide the Trust with the benefit of hedging contracts entered into between SandRidge and third parties. The Trust’s receipt of any payments due based on the commodity derivatives agreement depends upon the financial position of SandRidge and SandRidge’s hedge contract counterparties. A default by any of the hedge counterparties could reduce the amount of cash available for distributions to the Trust unitholders. The Trust does not have the ability to enter into its own hedges. The effects of such commodity derivatives agreement have not been reflected in these pro forma financial statements as the terms of the derivatives agreement have not been determined as of the date of filing of this registration statement.

The unaudited pro forma statement of assets and trust corpus assumes the Trust formation and the conveyance of the royalty interests at September 30, 2010. The unaudited pro forma statements of distributable income assume the conveyance of the royalty interests as of the beginning of the period presented.

In order to provide support for cash distributions on the common units, SandRidge has agreed to subordinate 6,325,000 of the Trust units it will retain following this offering (the “subordinated units”), which will constitute 25% of the outstanding Trust units. The subordinated units will be 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 the applicable quarterly subordination threshold. If there is not sufficient cash to fund such a distribution on all the common units, the distribution to be made with respect to the subordinated units will be 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 the common units. Each quarterly subordination threshold is equal to 80% of the target cash distribution level for the corresponding

 

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quarter (each, a “subordination threshold”). In exchange for agreeing to subordinate these trust units, and in order to provide additional financial incentive to SandRidge to satisfy its drilling obligation and perform operations in the Underlying Properties in an efficient and cost-effective manner, SandRidge will be entitled to receive incentive distributions (the “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 cash distribution for such quarter (each, an “incentive threshold”).

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, at the end of the fourth full calendar quarter following SandRidge’s satisfaction of its drilling obligation to the Trust with respect to the PUD wells. SandRidge currently expects that it will complete its drilling obligation on or before December 31, 2014 and that, accordingly, the subordinated units will convert into common units on or before December 31, 2015. In the event of delays, SandRidge will have until December 31, 2015 under its contractual obligation to drill all the PUD Wells in which event the subordinated units would convert into common units on or before December 31, 2016. The period during which the subordinate units are outstanding is referred to as the “subordination period.”

SandRidge believes that the assumptions used provide a reasonable basis for presenting the effects directly attributable to this transaction.

The unaudited pro forma financial information should be read in conjunction with the Statement of Assets and Trust Corpus for the Trust and the Statements of Revenues and Direct Operating Expenses for the Underlying Properties and related notes, respectively, for the periods presented.

2. Trust Accounting Policies

The Unaudited Pro Forma Statements of Distributable Income were derived from the historical accounting records of the Underlying Properties.

Income determined on the basis of generally accepted accounting principles would include all expenses incurred for the period presented. However, the Trust serves as a pass-through entity, with expenses for depletion, interest and income taxes being based upon the status and elections of the Trust unitholders. In addition, the royalty interest will not be burdened by field and lease operating expenses. Thus, the statement purports to show distributable income, defined as income of the Trust available for distribution to the Trust unitholders before application of those unitholders’ additional expenses, if any, for depreciation, depletion and amortization, interest and income taxes. The revenues are reflected net of existing royalties and overriding royalties and have been reduced by gathering and any other post-production expenses. Actual cash receipts may vary due to timing delays of actual cash receipts from the property purchasers and due to wellhead and pipeline volume balancing agreements or practices.

Investment in royalty interest is periodically assessed to determine whether its aggregate value has been impaired below its total capitalized cost based on the Underlying Properties. The Trust will provide a write-down to the investment in the royalty interest to the extent the total capitalized costs, less accumulated depletion, exceed undiscounted future net revenues attributable to the proved oil and natural gas reserves of the Underlying Properties.

3. Income Taxes

The Trust is a Delaware statutory trust and is not required to pay federal or state income taxes. Accordingly, no provision for federal or state income taxes has been made.

 

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4. Pro Forma Adjustments

The following adjustments were made in the preparation of the unaudited pro forma financial information:

 

(a)

SandRidge transferred $1,000 to the Trust on December 30, 2010, constituting the initial Trust estate.

 

(b)

Reflects SandRidge’s conveyance of the royalty interests to the Trust in exchange for all of the net proceeds of this offering as well as common and subordinated units representing an assumed 50% beneficial interest in the Trust. The investment in royalty trust is recorded at the historical cost of SandRidge which was determined by allocating the historical net book value of SandRidge’s full cost pool according to the fair value of the conveyed royalty interests of the Underlying Properties relative to the fair value of SandRidge’s total full cost pool.

 

(c)

Assumes issuance of 25,300,000 Trust units.

 

(d)

Historical well production and lease production expenses are not deducted in determining net revenue attributable to royalty interests and in determining distributable income. Royalty interests, as defined in the conveyance, will bear a pro rata share of the taxes on production and property, if any, and applicable gathering and other post-production expenses relating to making the production saleable.

 

(e)

The Trust’s general and administrative expenses are estimated at $900,000 annually. Such expenses include trustee fees, administrative service fees and costs associated with being a public entity.

 

(f)

The trustee intends to withhold $1,000,000 from the first quarterly distribution to establish a cash reserve to cover Trust administration expenses. The establishment of such reserve has not been reflected in the pro forma statements of distributable income due to its non-recurring nature.

 

(g)

Assumes that no incentive threshold was reached during the period.

5. Pro Forma Supplemental Oil and Natural Gas Reserve and Standardized Measure Information

Information with respect to the oil and natural gas producing activities of the Trust’s royalty interests in the Underlying Properties is presented in the following tables. The information was derived from reserve reports which were prepared by SandRidge’s reserve engineers in accordance with ASC Topic 932, Extractive Activities—Oil and Gas.

Oil and Natural Gas Reserve Quantities

Proved oil and natural gas reserves are those quantities of oil and natural gas that, by analysis of geosciences 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.

 

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The following table presents the estimated remaining net proved, proved developed and proved undeveloped oil and natural gas reserves of the Trust’s royalty interests in the Underlying Properties, all of which are located in the continental United States, estimated by SandRidge’s petroleum engineers, and the related summary of changes in estimated quantities of net remaining proved reserves during the year ended December 31, 2009 and the nine-month period ended September 30, 2010.

 

		Historical Underlying Properties								Adjustments (a)								Pro Forma SandRidge Mississippian Trust I
		Oil (Bbls)				Gas (Mcf)				Oil (Bbls)				Gas (Mcf)				Oil (Bbls)				Gas (Mcf)
Proved Reserves
As of December 31, 2008			—				—				—				—				—				—
Extensions and discoveries (1)			386,964				1,470,626				(72,998	)			(271,196	)			313,966				1,199,430
Production			(6,878	)			(40,534	)			688				4,053				(6,190	)			(36,481	)
As of December 31, 2009			380,086				1,430,092				(72,310	)			(267,143	)			307,776				1,162,949
Revisions of previous estimates			217,431				4,562,805				(40,139	)			(1,036,779	)			177,292				3,526,026
Extensions and discoveries (1)			13,306,327				80,435,915				(6,884,914	)			(39,929,017	)			6,421,413				40,506,898
Production			(132,595	)			(651,995	)			13,260				65,200				(119,335	)			(586,795	)
As of September 30, 2010			13,771,249				85,776,817				(6,984,103	)			(41,167,739	)			6,787,146				44,609,078
Proved developed reserves:
As of December 31, 2009			82,033				738,183				(15,634	)			(135,573	)			66,399				602,610
As of September 30, 2010			2,295,004				21,509,848				(473,410	)			(4,707,868	)			1,821,594				16,801,980
Proved undeveloped reserves:
As of December 31, 2009			298,053				691,909				(56,676	)			(131,750	)			241,377				560,339
As of September 30, 2010			11,476,245				64,266,969				(6,510,693	)			(36,459,871	)			4,965,552				27,807,098

 

(1)

Extensions and discoveries for the year ended December 31, 2009 and nine months ended September 30, 2010 are a result of the discovery and production from wells drilled horizontally in the Mississippian formation in northern Oklahoma on acreage owned by SandRidge. The formation had previously been drilled and produced from vertical wells. During the year ended December 31, 2009 and the nine months ended September 30, 2010, SandRidge drilled or participated in the drilling of 5 and 22 wells, respectively, from which a portion of royalty interests conveyed to the Trust will be conveyed. These wells demonstrated consistent levels of production and provided reasonable certainty that wells to be drilled within the acreage qualified for Proved Undeveloped classification.

 

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Standardized Measure of Discounted Future Net Cash Flows

Certain information concerning the assumptions used in computing the valuation of proved developed reserves and their inherent limitations are discussed below. SandRidge believes such information is essential for a proper understanding and assessment of the data presented. These assumptions are summarized as follows:

 

•

Pricing is applied based upon 12-month average market prices, using the first-day-of-the-month price for each month, at December 31, 2009 and September 30, 2010 adjusted for fixed or determinable contracts that were inexistence at period end. The calculated weighted average per unit prices for the Underlying Properties’ proved reserves and future net revenues were as follows:

 

		December 31, 2009				September 30, 2010
Oil (per Bbl)		$	54.86			$	71.95
Natural gas (per Mcf)		$	3.51			$	4.09

 

•

Future development and production costs are determined based upon actual cost at period end.

 

•

The standardized measure of discounted future net cash flows includes projections of future abandonment costs at period end.

 

•

Future income tax expenses are not computed as the Trust is not required to pay state or federal income taxes.

 

•

An annual discount factor of 10% is applied to the future net cash flows.

Extensive judgments are involved in estimating the timing of production and the costs that will be incurred throughout the remaining lives of the properties. Accordingly, the estimates of future net cash flows from proved reserves and the present value may be materially different from subsequent actual results. The standardized measure of discounted net cash flows does not purport to present, nor should it be interpreted to present, the fair value of the Trust’s royalty interests in the Underlying Properties’ oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, and anticipated future changes in prices and costs. The following table presents future net cash flows relating to the Underlying Properties based on the standardized measure in ASC Topic 932 (in thousands).

 

		December 31, 2009
		Historical Underlying Properties				Adjustments				Pro Forma SandRidge Mississippian Trust I
Future cash inflows from production		$	25,868			$	(4,904	)(a)		$	20,964
Future production costs			(7,822	)			6,218	(b)			(1,604	)
Future development costs (1)			(4,800	)			4,800	(c)			—
Undiscounted future net cash flows			13,246				6,114				19,360
10% annual discount			(7,808	)			(1,169	)			(8,977	)
Standardized measure of discounted future net cash flows		$	5,438			$	4,945			$	10,383

 

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		September 30, 2010
		Historical Underlying Properties				Adjustments				Pro Forma SandRidge Mississippian Trust I
Future cash inflows from production		$	1,341,638			$	(671,480	)(a)		$	670,158
Future production costs			(303,562	)			268,363	(b)			(35,199	)
Future development costs (1)			(181,680	)			181,680	(c)			—
Undiscounted future net cash flows			856,396				(221,437	)			634,959
10% annual discount			(534,056	)			198,806				(335,250	)
Standardized measure of discounted future net cash flows		$	322,340			$	(22,631	)		$	299,709

 

(1)	Includes future abandonment costs.

Changes in the standardized measure of future net cash flows related to proved oil and gas reserves are as follows for the year ended December 31, 2009 and the nine-month period ended September 30, 2010.

 

		Historical Underlying Properties				Adjustments				Pro Forma SandRidge Mississippian Trust I
Present value as of December 31, 2008		$	—			$	—			$	—
Changes during the period:
Revenues less production and other costs			(216	)			(243	)(b)			(459	)
Extensions and discoveries			5,654				5,188	(d)			10,842
Net change for the period			5,438				4,945				10,383
Present value as of December 31, 2009			5,438				4,945				10,383
Changes during the period:
Revenues less production and other costs			(9,007	)			(607	)(b)			(9,614	)
Net changes in prices, production and other costs			1,541				545	(b)			2,086
Development costs incurred			5,642				(5,642	)(e)			—
Net changes in future development costs			(842	)			842	(c)			—
Extensions and discoveries			304,945				(24,521	)(d)			280,424
Revisions of previous quantity estimates			8,932				2,987	(a)			11,919
Accretion of discount			527				431	(a)			958
Timing differences and other			5,164				(1,611	)(a)			3,553
Net change for the period			316,902				(27,576	)			289,326
Present value as of September 30, 2010		$	322,340			$	(22,631	)		$	299,709

Adjustments:

 

(a)	Reflects amounts attributable to retained interest of SandRidge in the Underlying Properties.

 

(b)	Production costs to which the Trust’s interest is not subject and amounts attributable to retained interest of SandRidge in the Underlying Properties.

 

(c)	Future development costs to which the Trust’s interest is not subject.

 

(d)	Extensions, discoveries and other additions attributable to the retained interest of SandRidge net of 100% of the future development costs and production costs attributable to the Underlying Properties.

 

(e)	Development costs incurred for the Underlying Properties for the nine-month period ended September 30, 2010.

 

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Annex A

January 4, 2011

Mr. Rodney Johnson

SandRidge Energy, Inc.

123 Robert S. Kerr Avenue

Oklahoma City, Oklahoma 73102

Dear Mr. Johnson:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2010, to the SandRidge Energy, Inc. (SandRidge) interest in certain oil and gas properties located in Oklahoma and referred to herein as the “Cedardale properties”. It is our understanding that the proved reserves estimated in this report constitute approximately 8 percent of all proved reserves owned by SandRidge. A proposed royalty interest in such reserves is to be conveyed to SandRidge Mississippian Trust I with an effective date of January 1, 2011. We completed our evaluation of SandRidge’s reserves on January 4, 2011. The estimates in this report have been prepared in accordance with the definitions and guidelines of the U.S. Securities and Exchange Commission (SEC) and conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas., except that per-well overhead expenses are excluded for the operated properties and future income taxes are excluded for all properties. Definitions are presented immediately following this letter. This report has been prepared for SandRidge’s use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the SandRidge interest in the Cedardale properties, as of December 31, 2010, to be:

 

		Net Reserves								Future Net Revenue (M$)
Category		Oil (MBBL)				Gas (MMCF)				Total				Present Worth at 10%
Proved Developed Producing			3,529.6				29,549.1				291,274.5				148,689.7
Proved Developed Non-Producing			151.6				849.1				11,313.1				5,865.4
Proved Undeveloped			14,844.4				83,128.9				900,531.0				314,933.5
Total Proved			18,525.7				113,527.1				1,203,118.6				469,488.6

Totals may not add because of rounding.

The oil reserves shown include crude oil and condensate. Oil volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

 

 

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The estimates shown in this report are for proved reserves. No study was made to determine whether probable or possible reserves might be established for these properties. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

Future gross revenue to the SandRidge interest is prior to deducting state production taxes and ad valorem taxes. Future net revenue is after deductions for these taxes, future capital costs, operating expenses, and abandonment costs but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability. Our estimates of future net revenue do not include any salvage value for the lease and well equipment but do include Sandridge’s estimates of the costs to abandon the wells and production facilities. Abandonment costs are included as capital costs.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2010. For oil volumes, the average West Texas Intermediate posted price of $75.96 per barrel is adjusted by lease for quality, transportation fees, and regional price differentials. For gas volumes, the average Henry Hub Gas Daily price of $4.376 per MMBTU is adjusted by lease for energy content, transportation fees, fuel consumption shrinkage, and a regional price differential. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $74.60 per barrel of oil and $4.075 per MCF of gas.

Lease and well operating costs used in this report are based on operating expense records of SandRidge. For nonoperated properties, these costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. As requested, lease and well operating costs for the operated properties include only direct lease- and field-level costs. For all properties, headquarters general and administrative overhead expenses of SandRidge are not included. Lease and well operating costs are held constant throughout the lives of the properties. Capital costs are included as required for workovers, new development wells, and production equipment. The future capital costs are held constant to the date of expenditure.

We have made no investigation of potential gas volume and value imbalances resulting from overdelivery or underdelivery to the SandRidge interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on SandRidge receiving its net revenue interest share of estimated future gross gas production.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible. Estimates of reserves may increase or decrease as a result of future operations, changes in regulations, market conditions, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current

 

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development plans, the properties will be operated in a prudent manner, no governmental regulations or controls will be put in place that would impact the ability of SandRidge to recover the reserves and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, such as performance analysis and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and guidelines. A substantial portion of these reserves are for undeveloped locations and producing wells that lack sufficient production history upon which performance-related estimates of reserves can be based. Therefore, these reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from SandRidge and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting geoscience, performance, and work data are on file in our office. The titles to the properties have not been examined by NSAI, nor has the actual degree or type of interest owned been independently confirmed. The technical persons responsible for preparing the reserves estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

 

				Sincerely,
				NETHERLAND, SEWELL & ASSOCIATES, INC.
				Texas Registered Engineering Firm F-002699
				By:		/s/ C.H. (Scott) Rees III
						C.H. (Scott) Rees III, P.E.
						Chairman and Chief Executive Officer
By:		/s/ David T. Miller		By:		/s/ Jay P. Mitchell
		David T. Miller, P.E. 96134				Jay P. Mitchell, P.G. 1649
		Vice President				Vice President
Date Signed: January 4, 2011				Date Signed: January 4, 2011
DTM:AMB

 

 

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC’s Compliance and Disclosure Interpretations.

(1) Acquisition of properties.    Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers’ fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir.    Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

 

(i)

Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

 

(ii)

Same environment of deposition;

 

(iii)

Similar geological structure; and

 

(iv)

Same drive mechanism.

Instruction to paragraph (a)(2):    Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen.    Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate.    Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate.    The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves.    Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

 

(i)

Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

(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.

 

(7) Development costs.    Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and 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 lease 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.

 

(iv)

Provide improved recovery systems.

(8) Development project.    A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

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

(10) Economically producible.    The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

(11) Estimated ultimate recovery (EUR).    Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs.    Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

 

(i)

Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or “G&G” costs.

 

(ii)

Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

 

(iii)

Dry hole contributions and bottom hole contributions.

 

(iv)

Costs of drilling and equipping exploratory wells.

 

(v)

Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well.    An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well.    An extension well is a well drilled to extend the limits of a known reservoir.

(15) 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 geologic barriers, or by 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.

(16) Oil and gas producing activities.

 

(i)

Oil and gas producing activities include:

 

(A)

The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations;

 

(B)

The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

(C)

The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

 

(1)

Lifting the oil and gas to the surface; and

 

(2)

Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

 

(D)

Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i):    The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

 

a.

The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

 

b.

In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i):    For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

 

(ii)

Oil and gas producing activities do not include:

 

(A)

Transporting, refining, or marketing oil and gas;

 

(B)

Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

 

(C)

Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

 

(D)

Production of geothermal steam.

(17) Possible reserves.    Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

 

(i)

When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

 

(ii)

Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

(iii)

Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

 

(iv)

The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

 

(v)

Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

 

(vi)

Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves.    Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

 

(i)

When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

 

(ii)

Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

 

(iii)

Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

 

(iv)

See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate.    The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) 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

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

 

(A)

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

 

(B)

Repairs and maintenance.

 

(C)

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

 

(D)

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

 

(E)

Severance taxes.

 

(ii)

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

(21) Proved area.    The part of a property to which proved reserves have been specifically attributed.

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

 

(i)

The area of the reservoir considered as proved includes:

 

(A)

The area identified by drilling and limited by fluid contacts, if any, and

 

(B)

Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

 

(ii)

In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

 

(iii)

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

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Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

(iv)

Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

 

(A)

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

 

(B)

The project has been approved for development by all necessary parties and entities, including governmental entities.

 

(v)

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.

(23) Proved properties.    Properties with proved reserves.

(24) Reasonable certainty.    If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology.    Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves.    Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, 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 gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26):    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).

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

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

(28) Resources.    Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

(29) Service well.    A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well.    A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.

(31) Undeveloped oil and gas reserves.    Undeveloped oil and gas reserves are 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 shall be 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 can be 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.

 

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

(iii)

Under no circumstances shall estimates for undeveloped reserves be 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, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties.    Properties with no proved reserves.

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January 5, 2011

Mr. Rodney Johnson

SandRidge Energy, Inc.

123 Robert S. Kerr Avenue

Oklahoma City, Oklahoma 73102

Dear Mr. Johnson:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2010, to the proposed royalty interest to be owned by SandRidge Mississippian Trust I (SRMT) in certain oil and gas properties located in Oklahoma and referred to herein as the “Cedardale properties”. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves to be owned by SRMT. Such reserves are associated with a proposed royalty interest currently owned by SandRidge Energy, Inc. to be conveyed to SRMT with an effective date of January 1, 2011. We completed our evaluation of SRMT’s reserves on January 5, 2011. The estimates in this report have been prepared in accordance with the definitions and guidelines of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for SRMT’s use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the SRMT proposed royalty interest in the Cedardale properties, as of December 31, 2010, to be:

 

		Net Reserves								Future Net Revenue (M$)
Category		Oil (MBBL)				Gas (MMCF)				Total				Present Worth at 10%
Proved Developed Producing			2,793.2				23,010.4				285,949.2				149,558.4
Proved Developed Non-Producing			120.0				671.8				11,272.1				6,134.4
Proved Undeveloped			6,422.1				35,963.7				593,394.0				274,866.3
Total Proved			9,335.2				59,645.9				890,615.3				430,559.1

Totals may not add because of rounding.

The oil reserves shown include crude oil and condensate. Oil volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

The estimates shown in this report are for proved reserves. No study was made to determine whether probable or possible reserves might be established for these properties. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

 

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Future gross revenue to the SRMT proposed royalty interest is prior to deducting state production taxes and ad valorem taxes. Future net revenue is after deductions for these taxes but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. Since SRMT will own a proposed royalty interest rather than a working interest in these properties, it would not incur any costs due to abandonment or possible environmental liability, nor would it realize any salvage value for the lease and well equipment.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2010. For oil volumes, the average West Texas Intermediate posted price of $75.96 per barrel is adjusted by lease for quality, transportation fees, and regional price differentials. For gas volumes, the average Henry Hub Gas Daily price of $4.376 per MMBTU is adjusted by lease for energy content, transportation fees, fuel consumption shrinkage, and a regional price differential. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $74.61 per barrel of oil and $4.078 per MCF of gas.

Because SRMT will own no working interest in these properties, lease and well operating costs would not be incurred. However, estimated lease and well operating costs have been used in the determination of the economic limits for the properties. Lease and well operating costs used in this report are based on operating expense records of SandRidge Energy, Inc. and are held constant throughout the lives of the properties. Capital costs have been included to determine whether workovers, new development wells, and production equipment requirements are economic. The future capital costs are held constant to the date of expenditure.

We have made no investigation of potential gas volume and value imbalances resulting from overdelivery or underdelivery to the SRMT proposed royalty interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on SRMT receiving its proposed royalty interest share of estimated future gross gas production.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible. Estimates of reserves may increase or decrease as a result of future operations, changes in regulations, market conditions, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans, the properties will be operated in a prudent manner, no governmental regulations or controls will be put in place that would impact the ability of SRMT to recover the reserves and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred by the working interest owners in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with

 

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the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, such as performance analysis and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and guidelines. A substantial portion of these reserves are for undeveloped locations and producing wells that lack sufficient production history upon which performance-related estimates of reserves can be based. Therefore, these reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from SandRidge Energy, Inc. and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting geoscience, performance, and work data are on file in our office. The titles to the properties have not been examined by NSAI, nor has the actual degree or type of interest owned been independently confirmed. The technical persons responsible for preparing the reserves estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

 

				Sincerely,
				NETHERLAND, SEWELL & ASSOCIATES, INC.
				Texas Registered Engineering Firm F-002699
				By:		/s/ C.H. (Scott) Rees III
						C.H. (Scott) Rees III, P.E.
						Chairman and Chief Executive Officer
By:		/s/ David T. Miller		By:		/s/ Jay P. Mitchell
		David T. Miller, P.E. 96134				Jay P. Mitchell, P.G. 1649
		Vice President				Vice President
Date Signed: January 5, 2011				Date Signed: January 5, 2011

DTM:AMB

 

 

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC’s Compliance and Disclosure Interpretations.

(1) Acquisition of properties.    Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers’ fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir.    Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

 

(i)

Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

 

(ii)

Same environment of deposition;

 

(iii)

Similar geological structure; and

 

(iv)

Same drive mechanism.

Instruction to paragraph (a)(2):    Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen.    Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate.    Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate.    The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves.    Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

 

(i)

Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

(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.

 

(7) Development costs.    Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and 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 lease 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.

 

(iv)

Provide improved recovery systems.

(8) Development project.    A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

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

(10) Economically producible.    The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR).    Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs.    Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

 

(i)

Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or “G&G” costs.

 

(ii)

Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

 

(iii)

Dry hole contributions and bottom hole contributions.

 

(iv)

Costs of drilling and equipping exploratory wells.

 

(v)

Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well.    An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well.    An extension well is a well drilled to extend the limits of a known reservoir.

(15) 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 geologic barriers, or by 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.

(16) Oil and gas producing activities.

 

(i)

Oil and gas producing activities include:

 

(A)

The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations;

 

(B)

The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

(C)

The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

 

(1)

Lifting the oil and gas to the surface; and

 

(2)

Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

 

(D)

Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i):    The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

 

a.

The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

 

b.

In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i):    For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

 

(ii)

Oil and gas producing activities do not include:

 

(A)

Transporting, refining, or marketing oil and gas;

 

(B)

Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

 

(C)

Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

 

(D)

Production of geothermal steam.

(17) Possible reserves.    Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

 

(i)

When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

 

(ii)

Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

(iii)

Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

 

(iv)

The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

 

(v)

Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

 

(vi)

Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves.    Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

 

(i)

When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

 

(ii)

Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

 

(iii)

Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

 

(iv)

See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate.    The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) 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

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

 

(A)

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

 

(B)

Repairs and maintenance.

 

(C)

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

 

(D)

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

 

(E)

Severance taxes.

 

(ii)

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

(21) Proved area.    The part of a property to which proved reserves have been specifically attributed.

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

 

(i)

The area of the reservoir considered as proved includes:

 

(A)

The area identified by drilling and limited by fluid contacts, if any, and

 

(B)

Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

 

(ii)

In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

 

(iii)

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

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

(iv)

Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

 

(A)

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 (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

 

(v)

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.

(23) Proved properties.    Properties with proved reserves.

(24) Reasonable certainty.    If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology.    Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves.    Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, 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 gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26):    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).

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

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

(28) Resources.    Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

(29) Service well.    A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well.    A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.

(31) Undeveloped oil and gas reserves.    Undeveloped oil and gas reserves are 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 shall be 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 can be 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.

 

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

(iii)

Under no circumstances shall estimates for undeveloped reserves be 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, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties.    Properties with no proved reserves.

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ANNEX B

 

Calculation of Target Distributions
		Quarterly Target Distributions
Quarter Ending		Quarters 2011-2020												Quarters 2021-2031
		Subordination Threshold(1)				Target Cash Distribution Quarterly				Incentive Threshold(1)				Quarter Ending		Target Cash Distribution Quarterly
														March 31, 2021		$	0.412
June 30, 2011(2)		$	0.834			$	1.042			$	1.251			June 30, 2021			0.406
September 30, 2011			0.519				0.649				0.779			September 30, 2021			0.402
December 31, 2011			0.500				0.624				0.749			December 31, 2021			0.397
March 31, 2012			0.523				0.654				0.785			March 31, 2022			0.393
June 30, 2012			0.554				0.692				0.830			June 30, 2022			0.388
September 30, 2012			0.583				0.729				0.875			September 30, 2022			0.384
December 31, 2012			0.576				0.720				0.864			December 31, 2022			0.381
March 31, 2013			0.595				0.744				0.893			March 31, 2023			0.376
June 30, 2013			0.614				0.767				0.920			June 30, 2023			0.372
September 30, 2013			0.614				0.768				0.921			September 30, 2023			0.368
December 31, 2013			0.612				0.765				0.918			December 31, 2023			0.365
March 31, 2014			0.630				0.788				0.945			March 31, 2024			0.361
June 30, 2014			0.671				0.838				1.006			June 30, 2024			0.357
September 30, 2014			0.711				0.888				1.066			September 30, 2024			0.354
December 31, 2014			0.734				0.917				1.101			December 31, 2024			0.351
March 31, 2015			0.694				0.867				1.040			March 31, 2025			0.347
June 30, 2015			0.638				0.798				0.957			June 30, 2025			0.344
September 30, 2015			0.596				0.745				0.894			September 30, 2025			0.341
December 31, 2015			0.563				0.704				0.845			December 31, 2025			0.337
March 31, 2016			0.535				0.669				0.803			March 31, 2026			0.332
June 30, 2016			0.511				0.639				0.767			June 30, 2026			0.327
September 30, 2016			0.490				0.613				0.735			September 30, 2026			0.323
December 31, 2016			0.472				0.591				0.709			December 31, 2026			0.318
March 31, 2017							0.570							March 31, 2027			0.314
June 30, 2017							0.552							June 30, 2027			0.310
September 30, 2017							0.536							September 30, 2027			0.306
December 31, 2017							0.521							December 31, 2027			0.302
March 31, 2018							0.508							March 31, 2028			0.298
June 30, 2018							0.495							June 30, 2028			0.294
September 30, 2018							0.482							September 30, 2028			0.290
December 31, 2018							0.471							December 31, 2028			0.286
March 31, 2019							0.462							March 31, 2029			0.282
June 30, 2019							0.454							June 30, 2029			0.278
September 30, 2019							0.447							September 30, 2029			0.274
December 31, 2019							0.440							December 31, 2029			0.271
March 31, 2020							0.434							March 31, 2030			0.267
June 30, 2020							0.428							June 30, 2030			0.263
September 30, 2020							0.422							September 30, 2030			0.260
December 31, 2020							0.417							December 31, 2030			0.256
														March 31, 2031(3)			3.526

 

(1)	For each quarter, the Subordination Threshold equals 80% of the Target Distribution, and the Incentive Threshold equals 120% of the Target Distribution.

(2)	Includes proceeds attributable to the first five months of production from January 1, 2011 to May 31, 2011.

(3)	Includes proceeds attributable to the sale of Perpetual Royalties after the Termination Date.

 

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Until                 , 2011 (25 days after the date of this prospectus), federal securities laws may require all dealers that effect transactions in the trust units, whether or not participating in this offering, to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

12,500,000 Common Units

SandRidge Mississippian Trust I

 

 

PROSPECTUS

 

 

 

RAYMOND JAMES		MORGAN STANLEY

                    , 2011

 

 

 

 

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PART II

INFORMATION REQUIRED IN THE REGISTRATION STATEMENT

 

Item 13/14.

Other Expenses of Issuance and Distribution.

Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the SEC registration fee, the FINRA filing fee and the NYSE listing fee, the amounts set forth below are estimates.

 

SEC registration fee		$	33,379
FINRA filing fee		$	29,250
NYSE listing fee			*
Printing and engraving expenses			*
Fees and expenses of legal counsel			*
Accounting fees and expenses			*
Transfer agent and registrar fees			*
Trustee fees and expenses			*
Miscellaneous			*
Total			*

 

*	To be provided by amendment

 

Item 14/15.

Indemnification of Directors and Officers.

The trust agreement provides that each of the trustee and the Delaware trustee and their respective officers, agents and employees shall be indemnified from the assets of the trust against and from any and all liabilities, expenses, claims, damages or loss incurred by them as trustee or Delaware trustee in the administration of the trust and the trust assets, including, without limitation, any liability, expenses, claims, damages or loss arising out of or in connection with any liability under environmental laws, or in the doing of any act done or performed or omission occurring on account of it being trustee or Delaware trustee or acting in such capacity, except such liability, expense, claims, damages or loss as to which each is liable under the trust agreement. In this regard, the trustee and Delaware trustee shall be liable only for fraud or gross negligence or for acts or omissions in bad faith and shall not be liable for any act or omission of any of their respective agents or employees unless the trustee or Delaware trustee, as applicable, has acted in bad faith or with gross negligence in the selection and retention of such agent or employee. Each of the trustee and the Delaware trustee is entitled to indemnification from the assets of the trust and shall have a lien on the assets of the trust to secure for each the foregoing indemnification.

Article VI of the Amended and Restated Bylaws of SandRidge provides for indemnification of officers, directors and employees of SandRidge to the extent authorized by the General Corporation Law of the State of Delaware. Pursuant to Section 145 of the Delaware General Corporation Law, SandRidge generally has the power to indemnify its present and former directors, officers, employees and agents against expenses incurred by them in connection with any suit to which they are, or are threatened to be made, a party by reason of their serving in such positions so long as they acted in good faith and in a manner they reasonably believed to be in, or not opposed to, the best interests of a corporation, and with respect to any criminal action or proceeding, they had no reasonable cause to believe their conduct was unlawful. With respect to suits by or in the right of a corporation, however, indemnification is not available if such person is adjudged to be liable to the corporation unless the court determines that indemnification is appropriate. In addition, a

 

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corporation has the power to purchase and maintain insurance for such persons. The statute also expressly provides that the power to indemnify authorized thereby is not exclusive of any rights granted under any bylaw, agreement, vote of stockholders or disinterested directors, or otherwise.

Article Nine of the Certificate of Incorporation of SandRidge contains a provision, permitted by Section 102(b)(7) of the Delaware General Corporation Law, limiting the personal monetary liability of directors for breach of fiduciary duty as a director. The Certificate of Incorporation and the Delaware General Corporation Law provide that such provision does not eliminate or limit liability (i) for any breach of the director’s duty of loyalty to SandRidge or its stockholders, (ii) for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, (iii) for unlawful payments of dividends or unlawful stock repurchases or redemptions as provided in Section 174 of the Delaware General Corporation Law or (iv) for any transaction from which the director derived an improper benefit.

The above discussion of SandRidge’s Certificate of Incorporation and Amended and Restated Bylaws and Section 145 of the Delaware General Corporation Law is not intended to be exhaustive and is respectively qualified in its entirety by reference to SandRidge’s Certificate of Incorporation and Amended and Restated Bylaws and the Delaware General Corporation Law.

 

Item 15.

Recent Sales of Unregistered Securities.

None.

 

Item 16.

Exhibits and Financial Statement Schedules.

The following documents are filed as exhibits to this registration statement:

 

Exhibit Number		Description
1.1*		Form of Underwriting Agreement
3.1†		Certificate of Trust of SandRidge Mississippian Trust I
4.1†		Trust Agreement of SandRidge Mississippian Trust I, dated December 30, 2010
4.2*		Form of Amended and Restated Trust Agreement of SandRidge Mississippian Trust I
5.1*		Opinion of Richards, Layton & Finger, P.A. relating to the validity of the trust units to be registered under this Registration Statement
8.1*		Opinion of Covington & Burling LLP relating to tax matters
10.1*		Form of Term Royalty Conveyance (PDP)
10.2*		Form of Term Royalty Conveyance (PUD)
10.3*		Form of Perpetual Royalty Conveyance (PDP)
10.4*		Form of Perpetual Royalty Conveyance (PUD)
10.5*		Form of Assignment of Overriding Royalty Interest
10.6*		Form of Administrative Services Agreement
10.7*		Form of Development Agreement
10.8*		Form of Derivatives Agreement
10.9*		Form of Mortgage
10.10*		Form of Registration Rights Agreement

 

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Exhibit Number		Description
23.1		Consent of PricewaterhouseCoopers LLP
23.2		Consent of Hansen, Barnett & Maxwell, P.C.
23.3		Consent of Netherland, Sewell & Associates, Inc.
23.4†		Consent of DeGolyer and MacNaughton
23.5†		Consent of Lee Keeling and Associates, Inc.
23.6†		Consent of Williamson Petroleum Consultants, Inc.
23.7*		Consent of Richards, Layton & Finger, P.A. (contained in Exhibit 5.1)
23.8*		Consent of Covington & Burling LLP (contained in Exhibit 8.1)
24.1†		Powers of Attorney (included on signature pages of this Registration Statement)
99.1		Summary Reserve Reports of Netherland, Sewell & Associates, Inc. (included as Annex A to the prospectus)

 

*	To be filed by amendment

†	Previously filed

 

Item 17.

Undertakings.

The undersigned registrants hereby undertake that, for purposes of determining any liability under the Securities Act of 1933, each filing of a registrant’s annual report pursuant to section 13(a) or section 15(d) of the Securities Exchange Act of 1934 (and, where applicable, each filing of an employee benefit plan’s annual report pursuant to section 15(d) of the Securities Exchange Act of 1934) that is incorporated by reference in the registration statement shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

The undersigned registrants hereby undertake to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

The undersigned registrants hereby undertake that:

 

(1)

For purpose of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrants pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

 

(2)

For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

 

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Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers, and controlling persons of the registrants pursuant to the foregoing provisions, or otherwise, the registrants have been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrants of expenses incurred or paid by a director, officer or controlling person of a registrant in the successful defense of any action, suit, or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrants will, unless in the opinion of their respective counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by them is against public policy as expressed in the Securities Act of 1933 and will be governed by the final adjudication of such issue.

 

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, SandRidge Mississippian Trust I has duly caused this Amendment No. 1 to the Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Oklahoma City, State of Oklahoma, on February 9, 2011.

 

 

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, SandRidge Energy, Inc. certifies that it has reasonable grounds to believe that it meets all of the requirements for filing on Form S-3 and has duly caused this Amendment No. 1 to the Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Oklahoma City, State of Oklahoma, on February 9, 2011.

 

* * * *

Pursuant to the requirements of the Securities Act of 1933, this Amendment No. 1 to the Registration Statement has been signed by the following persons in the capacities and on the dates indicated.

 

Signature		Title		Date
/s/    TOM L. WARD         Tom L. Ward		Chief Executive Officer and Chairman of the Board (Principal Executive Officer)		February 9, 2011
/s/    JAMES D. BENNETT         James D. Bennett		Executive Vice President and Chief Financial Officer (Principal Financial Officer)		February 9, 2011
/s/    RANDALL D. COOLEY         Randall D. Cooley		Senior Vice President—Accounting (Principal Accounting Officer)		February 9, 2011
* Everett R. Dobson		Director		February 9, 2011
* William A. Gilliland		Director		February 9, 2011
* Daniel W. Jordan		Director		February 9, 2011
* Roy T. Oliver, Jr.		Director		February 9, 2011
* D. Dwight Scott		Director		February 9, 2011

 

*By:		/S/    TOM L. WARD
		Tom L. Ward Attorney-in-fact

 

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