Item 1. Business
General
SandRidge Mississippian Trust II is a statutory trust formed on December 13, 2011 under the Delaware Statutory Trust Act pursuant to a trust agreement by and among SandRidge, as Trustor, The Bank of New York Mellon Trust Company, N.A., as Trustee (the “Trustee”), and The Corporation Trust Company, as Delaware Trustee (the “Delaware Trustee”). The Trust’s affairs are administered by the Trustee, which maintains its offices at 919 Congress Avenue, Austin, Texas 78701. The Trust does not have any employees.
Copies of reports filed by the Trust under the Exchange Act are made available as soon as reasonably practicable after such materials are filed with or furnished to the Securities and Exchange Commission (“SEC”). Certain information concerning the Trust and Trust units as well as a link to the Trust’s filings with the SEC may be obtained at the following web site location: http://sandridgesdr.investorhq.businesswire.com/. Any materials filed with the SEC may be read and copied at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549 or accessed via the SEC’s website at www.sec.gov. The Trust will also provide electronic or paper copies of its filings free of charge upon request to the Trustee.
Formation and Structure. The Trust was created to acquire and hold the Royalty Interests for the benefit of Trust unitholders pursuant to a trust agreement dated December 13, 2011 by and among SandRidge, the Trustee and the Delaware Trustee (as subsequently amended and restated as of April 23, 2012). Concurrent with the initial public offering described below, SandRidge conveyed to the Trust royalty interests in specified oil and natural gas properties in the Mississippian formation in Alfalfa, Grant, Kay, Noble and Woods counties in northern Oklahoma and Barber, Comanche, Harper and Sumner counties in southern Kansas (the “Underlying Properties”). These Royalty Interests were derived from SandRidge’s interests in (a) 54 wells producing at December 31, 2011 and 13 additional wells awaiting completion at that time (together, the “Initial Wells”) and (b) the equivalent of 206 horizontal oil and natural gas development wells to be drilled in the Mississippian formation (“Trust Development Wells”) within an area of mutual interest (“AMI”). As of December 31, 2012, the AMI consisted of approximately 66,200 gross acres (52,200 net acres) in the counties where the Underlying Properties are located.
The Trust issued 49,725,000 Trust units and through an initial public offering in April 2012, the Trust sold 29,900,000 of its common units to the public for net proceeds, after payment of offering expenses, of approximately $590.2 million. The Trust delivered the net proceeds of the offering, which were further reduced by $3.1 million for a structuring fee paid to certain of the underwriters, along with 7,393,750 common units and 12,431,250 subordinated units, to certain wholly owned subsidiaries of SandRidge, in exchange for the conveyance of the Royalty Interests to the Trust. Upon completion of these transactions and as of December 31, 2012, there were 49,725,000 Trust units, consisting of 37,293,750 common and 12,431,250 subordinated units, issued and outstanding. SandRidge owned 7,393,750 Trust common units and 12,431,250 Trust subordinated units at December 31, 2012. The common and subordinated units have identical rights and privileges, except with respect to their rights to receive distributions. See “-Distributions” below.
The Royalty Interests entitle the Trust to receive 80% of the proceeds (after deducting post-production costs and any applicable taxes) from the sale of oil, including natural gas liquids, and natural gas production attributable to SandRidge’s net revenue interest in the Initial Wells and 70% of the proceeds (after deducting post-production costs and any applicable taxes) from the sale of oil including natural gas liquids, and natural gas production attributable to SandRidge’s net revenue interest in the Trust Development Wells beginning on the effective date of the conveyance, January 1, 2012.
Under the terms of conveyances pursuant to which the Royalty Interests were granted to the Trust, SandRidge is obligated to act as a reasonably prudent operator in the AMI under the same or similar circumstances as it would if it were acting with respect to its own properties, disregarding the existence of the
Royalty Interests as burdens affecting such properties. The conveyances generally permit SandRidge to sell all or any part of its interest in the Underlying Properties, if the Underlying Properties are sold, subject to and burdened by the Royalty Interests; however, SandRidge may not sell any of the Underlying Properties subject to the Royalty Interest in the Trust Development Wells until it has satisfied its drilling obligation pursuant to the terms of the development agreement discussed below.
The Trust is passive in nature and neither the Trust nor the Trustee has any control over, or responsibility for, costs relating to the operation of the Underlying Properties. The business and affairs of the Trust are administered by the Trustee. However, the Trustee has no authority over or responsibility for, and no involvement with, any aspect of the oil and gas operations or other activities on the Underlying Properties. The trust agreement generally limits the Trust’s business activities to owning the Royalty Interests and entering into derivative contracts on a limited basis and activities reasonably related thereto, including activities required or permitted by the terms of the conveyances related to the Royalty Interests.
The Trust will dissolve and begin to liquidate on December 31, 2031 (the “Termination Date”) and will soon thereafter wind up its affairs and terminate. At the Termination Date, 50% of the Royalty Interests will revert automatically to SandRidge. The remaining 50% of the Royalty Interests will be retained by the Trust at the Termination Date and thereafter sold, and the net proceeds of the sale, as well as any remaining Trust cash reserves, will be distributed to the unitholders on a pro rata basis. SandRidge has a right of first refusal to purchase the Royalty Interests retained by the Trust at the Termination Date.
Income Tax Considerations. The Trust is treated for federal and applicable state income tax purposes as a partnership. Trust unitholders are treated as partners in that partnership. For United States (“U.S.”) federal income tax purposes, a partnership is not a taxable entity and incurs no U.S. federal income tax liability. With respect to state taxation, a partnership is typically treated in the same manner as it is for U.S. federal income tax purposes. Each partner is required to take into account his or her share of items of income, gain, loss, deduction and credit of the partnership in computing his or her federal income tax liability, regardless of whether cash distributions are made to him or her by the partnership. Distributions by a partnership to a partner are generally not taxable to the partner (but instead reduce tax basis but not below zero) unless the amount of cash distributed to such partner is in excess of the partner’s adjusted tax basis in his or her partnership interest.
Agreements with SandRidge
In conjunction with the conveyance of the Royalty Interests to the Trust, the Trust entered into the following agreements with SandRidge and/or one of its wholly owned subsidiaries on April 23, 2012.
Development Agreement. The Trust entered into a development agreement with SandRidge, effective January 1, 2012, that obligates SandRidge to drill, or cause to be drilled, the Trust Development Wells by December 31, 2016. Additionally, SandRidge agreed not to drill and complete, or allow another person within its control to drill and complete, any other well in the AMI other than the Trust Development Wells until SandRidge fulfills its drilling obligation. Under the terms of the agreement, SandRidge will be credited for having drilled one full Trust Development Well if a well is drilled and perforated for completion with a perforated length of between 3,500 feet and 4,500 feet within the Mississippian formation and SandRidge’s net revenue interest in the well is equal to 47.4%. For wells with a perforated length of less than 3,500 feet or greater than 4,500 feet and for wells in which SandRidge has a net revenue interest greater or less than 47.4%, SandRidge will receive a proportionate credit for such well. The actual number of wells required to be drilled may increase or decrease in proportion to SandRidge’s net revenue interest and the perforated length of each well. The Trust is not responsible for any costs related to the drilling of the Trust Development Wells or any other operating or capital costs associated with the wells.
A wholly owned subsidiary of SandRidge granted to the Trust a lien (the “Drilling Support Lien”) covering its interest in the AMI (except its interest in the Initial Wells) in order to secure the estimated amount of the drilling costs for the Trust’s interests in the undeveloped Underlying Properties. The initial amount recoverable by the Trust pursuant to the Drilling Support Lien could not exceed approximately $269.1 million, which is reduced proportionately as each of the Trust Development Wells is drilled, beginning once SandRidge has
completed 103 Trust Development Wells. The lien is reduced and the properties subject to the lien are released, in each case, as SandRidge fulfills its drilling obligation under the development agreement. The maximum amount potentially recoverable under the Drilling Support Lien was approximately $258.2 million as of December 31, 2012.
Administrative Services Agreement. The Trust entered into an administrative services agreement with SandRidge, effective January 1, 2012, that obligates the Trust to pay SandRidge an annual administrative services fee for accounting, tax preparation, bookkeeping and informational services to be performed by SandRidge on behalf of the Trust. Additionally, the administrative services agreement designates SandRidge as the Trust’s hedge manager, pursuant to which SandRidge has authority to administer the derivative contracts underlying the derivatives agreement (described below), and, on behalf of the Trust, to administer the Trust’s derivative contracts with unaffiliated third parties. For its services under the administrative services agreement, SandRidge receives an annual fee of $300,000, which is payable in equal quarterly installments and will remain fixed for the life of the Trust. SandRidge is also entitled to receive reimbursement for its out-of-pocket fees, costs and expenses incurred in connection with the provision of any of the services under this agreement. The administrative services agreement will terminate on the earliest to occur of: (i) the date the Trust shall have dissolved and commenced winding up in accordance with the trust agreement, (ii) the date that all of the Royalty Interests have been terminated or are no longer held by the Trust, (iii) pertaining to services to be provided with respect to any Underlying Properties transferred by SandRidge, the date that either SandRidge or the Trustee may designate by delivering 90-days’ prior written notice, provided that SandRidge’s drilling obligation has been completed and the transferee of such Underlying Properties assumes responsibility to perform the services in place of SandRidge and (iv) a date mutually agreed to by SandRidge and the Trustee.
Derivatives Agreement and Other Hedging Arrangements. The Trust entered into a derivatives agreement with SandRidge, effective April 1, 2012, that provides the Trust with the economic effect of certain derivative contracts previously entered into by SandRidge with third parties. Under the derivatives agreement, SandRidge pays the Trust amounts it receives from its counterparties and the Trust pays SandRidge any amounts that SandRidge is required to pay such counterparties. Substantially concurrent with the execution of the derivatives agreement, SandRidge novated certain of the derivative contracts underlying the derivatives agreement to the Trust. As a party to these contracts, the Trust receives payment directly from the counterparties, and is required to pay any amounts owed directly to the counterparties. To secure its obligations under these novated contracts, the Trust entered into a collateral agency agreement and granted the counterparties a lien on the Royalty Interests. Under the collateral agency agreement, the Trust pays a $15,000 annual fee to the collateral agent. Under the derivatives agreement, as Trust Development Wells are drilled, SandRidge has the right, under certain circumstances, to assign or novate to the Trust additional derivative contracts. The Trust’s derivative contracts consist of oil fixed price swaps.
Registration Rights Agreement. The Trust entered into a registration rights agreement for the benefit of SandRidge and certain of its affiliates and transferees, pursuant to which the Trust agreed to register the offering of the Trust units held by SandRidge and certain of its affiliates and permitted transferees upon request by SandRidge. Specifically, the Trust agreed:
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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;
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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
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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:
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have been sold pursuant to Rule 144 under the Securities Act if the transferee thereof does not receive “restricted securities”;
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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
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become eligible for resale pursuant to Rule 144 (or any similar rule then in effect under the Securities Act).
The holders will have the right to require the Trust to file no more than five registration statements in aggregate.
In connection with the preparation and filing of any registration statement, SandRidge will bear all costs and expenses incidental to any registration statement, excluding certain internal expenses of the Trust, which will be borne by the Trustee, and any underwriting discounts and commissions, which will be borne by the seller of the Trust units.
Distributions
The Trust makes quarterly cash distributions of substantially all of its cash receipts, after deducting amounts for the Trust’s administrative expenses, property taxes and cash reserves withheld by the Trustee, on or about 60 days following the completion of each quarter. The first distribution covered production for the two-month period from January 1, 2012 to February 29, 2012. The remaining distributions each cover production for a three-month period. The amount of Trust revenues and cash distributions to Trust unitholders depends on:
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the timing of initial production from the Trust Development Wells;
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oil and natural gas prices received;
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volume of oil and natural gas produced and sold;
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amounts realized and paid under derivative arrangements;
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post-production costs and any applicable taxes; and
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the Trust’s general and administrative expenses.
The amount of the quarterly distributions will fluctuate from quarter to quarter, depending on the factors discussed above. There is no minimum required distribution. However, in order to provide support for cash distributions on the common units, SandRidge agreed to subordinate 12,431,250 of the Trust units it received in exchange for conveyance of the Royalty Interests, which constitute 25% of the Trust units issued and outstanding. The subordinated units are entitled to receive pro rata distributions from the Trust each quarter if and to the extent there is sufficient cash to provide a cash distribution on the common units that is no less than 80% of the target distribution for the corresponding quarter (“Subordination Threshold”). If there is not sufficient cash to fund such a distribution on all of the common units, the distribution to be made with respect to the subordinated units is reduced or eliminated for such quarter in order to make a distribution, to the extent possible, of up to the Subordination Threshold amount on all of the common units. In exchange for agreeing to subordinate a portion of its Trust units, and in order to provide additional financial incentive to SandRidge to satisfy its drilling obligation, SandRidge is entitled to receive incentive distributions equal to 50% of the amount by which the cash available for distribution on all of the Trust units in any quarter exceeds 120% of the target distribution for such quarter (“Incentive Threshold”). At the end of the fourth full calendar quarter following SandRidge’s satisfaction of its drilling obligation with respect to the Trust Development Wells, the subordinated units will automatically convert into common units on a one-for-one basis and SandRidge’s right to receive incentive distributions will terminate. After such time, the common units will no longer have the protection of the Subordination Threshold, and all Trust unitholders will share on a pro rata basis in the Trust’s distributions.
The following table sets forth the Subordination Threshold and Incentive Threshold for each remaining quarterly distribution through the fourth quarter of 2017, as set out in the trust agreement and as included in the final prospectus (the “Prospectus”) filed with the SEC by the Trust pursuant to Rule 424(b) under the Securities Act on April 9, 2012.
(1) Due to the timing of the payment of production proceeds to the Trust, each distribution covers production from a three-month period consisting of the first two months of the most recently ended quarter and the final month of the quarter preceding it.
(2) Each of the Subordination Threshold (80% of quarterly target distribution) and Incentive Threshold (120% of quarterly target distribution) terminates after the fourth full calendar quarter following SandRidge’s completion of its drilling obligation.
(3) A distribution of $0.532557 per unit was declared on January 31, 2013 and paid on March 1, 2013. See Note 8 to the financial statements contained in Item 8 of this report for further discussion.
If at any time the Trust’s cash on hand (including available cash reserves) is not sufficient to pay the Trust’s ordinary course administrative expenses as they become due, the Trust may borrow funds from the Trustee or other lenders, including SandRidge, to pay such expenses. The Trustee does not intend to lend funds to the Trust. If such funds are borrowed, no further distributions will be made to unitholders (except in respect of any previously determined quarterly distribution amount) until the borrowed funds have been repaid, except that if SandRidge loans such funds, SandRidge may permit the Trust to make distributions prior to SandRidge being repaid.
Properties
As of December 31, 2012, the Trust’s properties consisted of Royalty Interests in (a) the Initial Wells, (b) 89 additional wells (equivalent to approximately 107 Trust Development Wells under the development agreement) that were drilled and perforated for completion between December 31, 2011 and December 31, 2012 and (c) the equivalent of approximately 99 Trust Development Wells to be drilled within the AMI. The following table presents the number of Initial Wells, Trust Development Wells drilled and Trust Development Wells to be drilled as of April 23, 2012, the date of the Royalty Interests conveyance, and December 31, 2012.
(1) SandRidge is credited for having drilled one full Trust Development Well if a well is drilled and perforated for completion with a perforated length between 3,500 feet and 4,500 feet within the Mississippian formation and SandRidge’s net revenue interest in the well is equal to 47.4%. For wells with a perforated length of less than 3,500 feet or greater than 4,500 feet and for wells in which SandRidge has a net revenue interest greater or less than 47.4%, SandRidge receives proportionate credit for such well.
(2) Date of the Royalty Interests conveyance.
The Royalty Interests were derived from properties producing from or to be drilled horizontally in the Mississippian formation in Oklahoma. The Mississippian formation is an expansive carbonate hydrocarbon system located on the Anadarko Shelf in northern Oklahoma and Kansas. The top of the formation is encountered between 4,000 and 7,000 feet and lies stratigraphically between the Pennsylvanian-aged Morrow formation and the Devonian-aged Woodford Shale formation. The Mississippian formation can reach 1,000 feet in gross thickness and the targeted porosity zone is between 50 and 100 feet in thickness. The formation’s geology is well understood as a result of the thousands of vertical wells drilled and produced there since the 1940s and more than 1,300 horizontal wells drilled there since 2007.
Proved Reserves
The following estimates of net proved oil and natural gas reserves are based on a reserve report as of December 31, 2012 prepared by independent petroleum engineers. The PV-10 and Standardized Measure shown in the table below are not intended to represent the current value of estimated oil and natural gas reserves attributable to the Royalty Interests at December 31, 2012. The reserve report as of December 31, 2012 was based on SandRidge’s drilling schedule and the average price during the 12-month period ended December 31, 2012, using first-day-of-the-month prices for each month. Refer to “Risk Factors” in Item 1A
Item 1A. Risk Factors
Risks Related to the Units
Drilling for and producing oil and natural gas on the Underlying Properties are high risk activities with many uncertainties that could delay the anticipated drilling schedule for the remaining Trust Development Wells and adversely affect future production from the Underlying Properties. Any such delays or reductions in production could decrease cash that is available for distribution to unitholders.
The drilling and completion of the remaining Trust Development Wells are subject to numerous risks beyond the Trust’s and SandRidge’s control, including risks that could delay or change the current drilling schedule for the Trust Development Wells (including the drilling schedule of third-party operators that may drill the remaining Trust Development Wells) and the risk that drilling will not result in commercially viable oil and natural gas production. Drilling for oil and natural gas can be unprofitable if dry wells are drilled and if productive wells do not produce sufficient revenues to return a profit. SandRidge’s and any third-party operators’ decisions to develop or otherwise exploit certain areas within the AMI will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. The estimated costs of drilling, completing and operating wells are uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. A Trust Development Well that is successfully completed may not pay out the capital costs spent to drill it. Drilling and production operations on the Underlying Properties may be curtailed, delayed or canceled as a result of various factors, including the following:
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delays imposed by or resulting from compliance with regulatory requirements including permitting;
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unusual or unexpected geological formations and miscalculations;
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shortages of or delays in obtaining equipment and qualified personnel;
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shortages of or delays in obtaining water for hydraulic fracturing operations;
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equipment malfunctions, failures or accidents;
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lack of available gathering facilities or delays in construction of gathering facilities;
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lack of available capacity on interconnecting transmission pipelines;
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lack of adequate electrical infrastructure;
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unexpected operational events and drilling conditions;
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pipe or cement failures and casing collapses;
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pressures, fires, blowouts and explosions;
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lost or damaged drilling and service tools;
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loss of drilling fluid circulation;
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uncontrollable flows of oil, natural gas, brine, water or drilling fluids;
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natural disasters;
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environmental hazards, such as oil and natural gas leaks, pipeline ruptures and discharges of toxic gases or well fluids;
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adverse weather conditions, such as extreme cold, fires caused by extreme heat or lack of rain and severe storms or tornadoes;
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reductions in oil and natural gas prices;
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oil and natural gas property title problems; and
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market limitations for oil and natural gas.
In the event that drilling of the Trust Development Wells is delayed or the Initial Wells or Trust Development Wells have lower than anticipated production due to one of the factors above or for any other reason, cash distributions to unitholders may be reduced. In addition, wells drilled in the Mississippian formation in the AMI typically produce a large volume of water, which requires the drilling of saltwater disposal wells. SandRidge’s inability to drill these wells or otherwise dispose of the water produced from the Initial Wells and Trust Development Wells in an efficient manner could delay production and therefore the Trust’s receipt of proceeds from the Royalty Interests.
Oil and natural gas prices fluctuate due to a number of factors that are beyond the control of the Trust and SandRidge, and lower prices could reduce proceeds to the Trust and cash distributions to unitholders.
The Trust’s reserves and quarterly cash distributions are highly dependent upon the prices realized from the sale of oil and natural gas. The markets for these commodities are very volatile. Oil and natural gas prices can fluctuate widely in response to a variety of factors that are beyond the control of the Trust and SandRidge. These factors include, among others:
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regional, domestic and foreign supply of, and demand for, oil and natural gas, as well as perceptions of supply of, and demand for, oil and natural gas;
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the price of foreign imports;
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U.S. and worldwide political and economic conditions;
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the level of demand, and perceptions of demand, for oil and natural gas;
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weather conditions and seasonal trends;
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anticipated future prices of oil and natural gas, alternative fuels and other commodities;
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technological advances affecting energy consumption and energy supply;
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the proximity, capacity, cost and availability of pipeline infrastructure, treating, transportation and refining capacity;
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natural disasters and other acts of force majeure;
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domestic and foreign governmental regulations and taxation;
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energy conservation and environmental measures; and
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the price and availability of alternative fuels.
For oil, from January 1, 2009 through December 31, 2012, the highest monthly settled price on the New York Mercantile Exchange (“NYMEX”) was $113.93 per Bbl and the lowest was $41.68 per Bbl. For natural gas, from January 1, 2009 through December 31, 2012, the highest monthly NYMEX settled price was $6.14 per MMBtu (one million British Thermal Units) and the lowest was $2.04 per MMBtu. In addition, the market price of oil and natural gas is generally higher in the winter months than during other months of the year due to increased demand for oil and natural gas for heating purposes during the winter season.
Lower oil and natural gas prices will reduce proceeds to which the Trust is entitled and may ultimately reduce the amount of oil and natural gas that is economic to produce from the Underlying Properties. As a result, SandRidge or any third-party operator of any of the Underlying Properties could determine during periods of low oil and natural gas prices to shut in or curtail production from wells on the Underlying Properties. In addition, the operator of the Underlying Properties could determine during periods of low oil and natural gas prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, SandRidge or any third-party operator may abandon, at its cost, any well or property if it reasonably believes that the well or property can no longer produce oil and natural gas in commercially economic quantities. This could result in termination of the portion of the Royalty Interest
relating to the abandoned well or property, and SandRidge would have no obligation to drill a replacement well. In addition, lower oil and natural gas prices could make it more likely that leases in the undeveloped acreage will expire at the end of their respective primary terms as a result of the failure to establish production from such leasehold acreage in commercially paying quantities prior to such date. The volatility of oil and natural gas prices also reduces the accuracy of target distributions to Trust unitholders. For a discussion of certain risks related to the Trust’s hedging arrangements, see “-The hedging arrangements for the Trust cover only a portion of the production attributable to the Trust, and such arrangements limit the Trust’s ability to benefit from commodity price increases for hedged volumes above the corresponding hedge price.”
Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the Trust and the value of the Trust units.
The value of the Trust units and the amount of future cash distributions to the Trust unitholders will depend upon, among other things, the accuracy of the reserves estimated to be attributable to the Royalty Interests. It is not possible to accurately measure underground accumulations of oil and natural gas in an exact way and estimating reserves is inherently uncertain. As discussed below, the process of estimating oil and natural gas reserves requires interpretations of available technical data and many assumptions. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of the Trust’s reserves. This could result in actual production and revenues for the Underlying Properties being materially less than estimated amounts.
In order to prepare the estimates of reserves attributable to the Underlying Properties and the Trust, production rates and the timing of development expenditures must be projected. In so doing, available geological, geophysical, production and engineering data must be analyzed. The extent, quality and reliability of this data can vary.
In addition, petroleum engineers are required to make subjective estimates of underground accumulations of oil and natural gas based on factors and assumptions that include:
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historical production from the area compared with production rates from other producing areas;
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oil and natural gas prices, production levels, Btu content, production expenses, transportation costs, severance and excise taxes and capital expenditures; and
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the assumed effect of governmental regulation.
Changes in these assumptions or actual production costs incurred and results of actual development could materially decrease reserve estimates. Estimates of reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes, and other factors.
Reserve estimates for fields that do not have a lengthy production history are less reliable than estimates for fields with lengthy production histories. Less production history may contribute to less accurate estimates of reserves, future production rates and the timing of development expenditures. Most of the Initial Wells have been operational for less than one year and estimated reserves vary substantially from well to well and are not directly correlated to perforated lateral length or completion technique. Although SandRidge and Netherland Sewell, the independent third-party engineering firm that estimated the Trust’s reserves, analyzed historical production data from vertical wells drilled in the AMI since the 1940s, there can be no assurance that this data can accurately predict future production from horizontal wells. The lack of operational history for horizontal wells in the Mississippian formation may also contribute to the inaccuracy of estimates of reserves. A material and adverse variance of actual production, revenues and expenditures from those underlying reserve estimates would have a material adverse effect on the financial condition, results of operations and cash flows of the Trust and would reduce cash distributions to Trust unitholders. As with all horizontal drilling programs, there is a risk that some or all of a horizontal well could miss the target reservoir. As a result, the Trust may not receive the benefit of the total amount of reserves reflected in the reserve report, notwithstanding the fact that SandRidge has satisfied its drilling obligation.
The average perforated interval length of the wells assumed for purposes of calculating the proven, undeveloped reserves (exceeding 4,000 feet) is longer than the minimum perforated interval length required for SandRidge to receive credit for one full Trust Development Well under the development agreement (3,500 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 are risks that some or all of a horizontal well could miss the target reservoir and that the quality of the target reservoir is less than that assumed for purposes of the Trust’s reserve reports. Under the development agreement, SandRidge receives credit for drilling a Trust Development Well if the well is drilled in the AMI and perforated horizontally for completion in the Mississippian formation, even if such well does not successfully produce hydrocarbons. As a result, unitholders may not receive the benefit of the total amount of proved undeveloped reserves reflected in the Trust’s reserve reports, even if SandRidge has satisfied its drilling obligation.
In certain circumstances the Trust may have to make cash payments under the hedging arrangements and these payments could be significant; such arrangements are secured by the Trust’s Royalty Interests in the Underlying Properties.
If actual production is below the amounts forecast in the Trust’s summary reserve report dated January 3, 2012 and included as an annex to the Prospectus and oil prices rise, the hedging arrangements entered into by the Trust may result in the Trust having to make cash payments under the hedging arrangements which could, in certain circumstances, be significant. Swap contracts underlying the derivatives agreement between SandRidge and the Trust and swap contracts entered into between the Trust and unaffiliated hedge counterparties provide the Trust with the right to receive from SandRidge or the hedge counterparties, as applicable, the excess of the fixed price specified in the hedge contract over a floating market price, multiplied by the volume of production hedged. If the floating market price exceeds the specified fixed price, the Trust must pay SandRidge or its hedge counterparties, as applicable, this difference in price multiplied by the volume of production hedged, even if the production attributable to the Trust’s Royalty Interests is insufficient to cover the volume of production specified in the applicable hedge contracts. Accordingly, if the production attributable to the Trust’s Royalty Interests is less than the volume hedged and the floating market price exceeds the specified fixed price, the Trust will have to make payments against which it will have insufficient offsetting cash receipts from the sale of production attributable to the Royalty Interests. Furthermore, if one or more of the purchasers of the production attributable to the Underlying Properties defaults on a payment obligation, the Trust may have insufficient cash receipts to make payments under the hedging arrangements. If these payments become too large, the Trust’s liquidity and cash available for distribution may be adversely affected.
In addition, the Trust’s obligations to the counterparties under its direct hedge contracts are secured by a first priority lien on the Royalty Interests. If the Trust fails to make any required payments to its unaffiliated hedge counterparties, these counterparties will have a right to foreclose on the Royalty Interests and may sell the Royalty Interests in order to satisfy the Trust’s payment obligations. Foreclosure by the hedging counterparties could result in the Trust’s loss, without compensation, of a portion or all of the Royalty Interests. The Trust’s hedging arrangements contain a prohibition on the Trust granting additional liens on any of its properties, other than customary permitted liens and liens in favor of the Trustees of the Trust.
Target distributions, Subordination Thresholds and Incentive Thresholds were established 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 the target.
The target distributions, Subordination Thresholds and Incentive Thresholds, as set forth in the Prospectus and described below in Part II Item 7, Trustee’s Discussion and Analysis of Financial Conditions and Results of Operations, were based on SandRidge’s calculations, and SandRidge did not receive an opinion or report on such calculations from any independent accountants, financial advisers, or engineers. Such calculations were based on
assumptions about drilling, production, oil and natural gas prices, hedging activities, capital expenditures, expenses, tax rates and production tax credits under state law, the location of Trust Development Wells and other matters that were inherently uncertain and were subject to significant business, economic, financial, legal, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from the targets. For example, the targets have assumed that oil and natural gas production would be sold at prices based on estimated realized prices for January, February and March 2012, NYMEX settled prices for April 2012, and monthly NYMEX forward pricing as of March 30, 2012for the 32-month period ending December 31, 2014, and assumed price increases after December 31, 2014 of 2.5% annually, capped at $120.00 per Bbl of oil in June 2023 and $6.48 per MMBtu of natural gas in December 2031; however, actual sales prices may be significantly lower. Additionally, the targets assumed that the Trust Development Wells will be drilled on SandRidge’s then-current anticipated schedule at the locations referenced in, the Trust’s reserve reports and that the related Underlying Properties would achieve production volumes set forth in the Trust’s reserve reports; however, the drilling of the Trust Development Wells may be delayed, Trust Development Wells may be drilled at locations with higher post-production expenses and applicable taxes and actual production volumes may be significantly lower than estimated. Further, after wells are completed, production operations may be curtailed, delayed or terminated as a result of a variety of risks and uncertainties, including those described above under “-Drilling for and producing oil and natural gas on the Underlying Properties are high risk activities with many uncertainties that could delay or change the anticipated drilling schedule for the remaining Trust Development Wells and adversely affect future production from the Underlying Properties. Any such delays or reductions in production could decrease cash that is available for distribution to unitholders.”
Furthermore, neither the target distribution nor the Subordination Threshold for each quarter during the subordination period necessarily represents the actual cash distributions unitholders will receive. To the extent actual production volumes or sales prices of oil and natural gas differ from the assumptions used to generate the target distributions, the actual distributions unitholders receive may be lower than the target distribution and the Subordination Threshold for the applicable quarter. For example, drilling of the Trust Development Wells ahead of the schedule assumed when the target distribution amounts were determined could cause actual distributions to fall below the target distribution amounts or Subordination Thresholds in later periods. A cash distribution to Trust unitholders below the target distribution amount or the Subordination Threshold may materially adversely affect the market price of the Trust units.
The subordination of certain Trust units held by SandRidge does not assure that unitholders will in fact receive any specified return on investment in the Trust.
Although SandRidge will not be entitled to receive any distribution on its subordinated units unless there is enough cash for all of the common units to receive a distribution equal to the Subordination Threshold for such quarter (which is 20% below the target distribution level for the corresponding quarter), the subordinated units constitute only a 25% interest in the Trust, and this feature does not guarantee that common units will receive a distribution equal to the Subordination Threshold, or any distribution at all. Additionally, the subordination period will terminate and the subordinated units will automatically convert into common units on a one-for-one basis, following which they will no longer be subject to the Subordination Threshold at the end of the fourth full calendar quarter following SandRidge’s satisfaction of its drilling obligation with respect to the Trust Development Wells. Depending on the prices at which volumes attributable to the Trust are sold, the common units may receive a distribution that is below the Subordination Threshold.
Quarterly cash distributions are made by the Trust based on the proceeds received by the Trust pursuant to the Royalty Interests for the preceding calendar quarter. If a quarterly cash distribution is lower than the target distribution amount or Subordination Threshold for any quarter, the common units will not be entitled to receive any additional distributions nor will the units be entitled to arrearages in any future quarter.
For Trust Development Wells drilled on properties where SandRidge is not the operator, SandRidge will rely on third-party operators to drill the Trust Development Wells, and for those Trust Development Wells where SandRidge is the operator, SandRidge may rely on third-party servicers to conduct the drilling operations.
SandRidge owns a majority working interest in substantially all of the locations on which it expects to drill the Trust Development Wells, and it expects to operate such wells during the subordination period. For Trust Development Wells drilled on properties where SandRidge is not the operator, however, SandRidge will rely on third-party operators to drill the Trust Development Wells. In addition, where SandRidge is the operator of a Trust Development Well, it may rely on third-party servicers to perform the necessary drilling operations. The ability of third-party servicers to perform such drilling operations will depend on those servicers’ financial condition and economic performance and access to capital, which in turn will depend upon the supply and demand for oil and natural gas, prevailing economic conditions and financial, business and other factors. The failure of a third-party servicer to adequately perform operations could delay drilling or completion or reduce production from the Underlying Properties and the cash available for distribution to Trust unitholders. If the Trust Development Wells take longer to be drilled and perforated for completion than currently anticipated, this may delay revenue earned from the production of oil and natural gas by such wells. The revenues distributable to the Trust and the amount of cash distributable to the Trust unitholders would similarly be delayed.
Because SandRidge does not have a majority working interest in the non-operated properties comprising the Underlying Properties, SandRidge may not be able to remove the operator in the event of poor or untimely performance. If the Trust Development Wells take longer to be drilled than currently anticipated, this may delay revenue attributable to the production of oil and natural gas by such wells. The revenues distributable to the Trust and the amount of cash distributable to the Trust unitholders would similarly be delayed.
Production of oil and natural gas on the Underlying Properties could be materially and adversely affected by severe or unseasonable weather.
Production of oil and natural gas on the Underlying Properties could be materially and adversely affected by severe weather. Repercussions of severe weather conditions may include:
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evacuation of personnel and curtailment of operations;
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weather-related damage to drilling rigs or other facilities, resulting in suspension of operations;
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inability to deliver materials to worksites; and
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weather-related damage to pipelines and other transportation facilities.
In addition, hydraulic fracturing operations require significant quantities of water. Any diminished access to water for use in hydraulic fracturing, whether due to usage restrictions or drought or other weather conditions, could curtail operations on the Underlying Properties or otherwise result in delays in operations or increased costs.
Shortages or increases in costs of equipment, services and qualified personnel could delay the drilling of the Trust Development Wells and result in a reduction in the amount of cash available for distribution.
The demand for qualified and experienced personnel to conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling rigs and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher oil and natural gas prices generally stimulate demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. Shortages of field personnel and equipment or price increases could significantly hinder SandRidge’s ability to satisfy its drilling obligation and delay completion of the Trust Development Wells, which would reduce future distributions to Trust unitholders.
Due to the Trust’s lack of industry and geographic diversification, adverse developments in the Trust’s existing area of operation could adversely impact its financial condition, results of operations and cash flows and reduce its ability to make distributions to the unitholders.
The Underlying Properties will be operated for oil and natural gas production only and are focused exclusively in the Mississippian formation in northern Oklahoma and southern Kansas. This concentration could disproportionately expose the Trust’s interests to operational and regulatory risk in that area. Due to the lack of diversification in industry type and location of the Trust’s interests, adverse developments in the oil and natural gas market or the area of the Underlying Properties, including, for example, transportation or treatment capacity constraints, curtailment of production or treatment plant closures for scheduled maintenance, could have a significantly greater impact on the Trust’s financial condition, results of operations and cash flows than if the Royalty Interests were more diversified.
The generation of proceeds for distribution by the Trust depends in part on access to and the operation of gathering, transportation and processing facilities. Limitations in the availability of those facilities could interfere with sales of oil and natural gas production from the Underlying Properties.
The amount of oil and natural gas that may be produced and sold from any well to which the Underlying Properties relate is subject to curtailment in certain circumstances, such as by reason of weather conditions, pipeline interruptions due to scheduled and unscheduled maintenance, failure of tendered oil and natural gas to meet quality specifications of gathering lines or downstream transporters, excessive line pressure which prevents delivery, physical damage to the gathering system or transportation system or lack of contracted capacity on such systems. The curtailments may vary from a few days to several months. In many cases, SandRidge is provided limited notice, if any, as to when production will be curtailed and the duration of such curtailments. If SandRidge is forced to reduce production due to such a curtailment, the revenues of the Trust and the amount of cash distributions to the Trust unitholders would similarly be reduced due to the reduction of proceeds from the sale of production.
Some of the Trust Development Wells on the Underlying Properties may be drilled in locations that currently are not serviced by natural gas gathering and transportation pipelines or locations in which existing gathering and transportation pipelines do not have sufficient capacity to transport additional production. As a result, the natural gas production from certain Trust Development Wells might not be able to be sold until the necessary gathering systems and/or transportation pipelines are constructed or until the necessary transportation capacity on an interstate pipeline is obtained. Any delay in the expansion of such system or the construction or expansion of any other natural gas gathering systems beyond the currently estimated construction schedules, or a delay in the procurement of additional transportation capacity would delay the receipt of any proceeds that may be associated with the natural gas production from the Trust Development Wells.
Title deficiencies with respect to the Underlying Properties could adversely affect SandRidge’s rights to production from the Underlying Properties.
The existence of title deficiencies with respect to the Underlying Properties could reduce the value or render properties worthless, thus adversely affecting the distributions to unitholders. SandRidge does not obtain title insurance covering oil, gas and mineral leaseholds. Additionally, undeveloped leasehold acreage has greater risk of title defects than developed acreage.
Drilling title opinions on all of the Underlying Properties have not yet been obtained. Prior to drilling of a Trust Development Well, SandRidge expects to obtain a drilling title opinion to identify defects in title to the leasehold. Frequently, as a result of title examinations, certain curative work may be required to correct identified title defects, and such curative work entails time and expense. The inability or failure to cure title defects could render some locations undrillable or cause the Trust to lose its rights to some or all production from some of the Underlying Properties, which could result in a reduction in proceeds available for distribution to unitholders and the value of the Trust units if a comparable additional location to drill a Trust Development Well cannot be identified.
The Trust is passive in nature and has no voting rights in SandRidge, managerial, contractual or other ability to influence SandRidge, or control over the field operations of, sale of oil and natural gas from, or development of, the Underlying Properties.
Trust unitholders have no voting rights with respect to SandRidge and, therefore, have no managerial, contractual or other ability to influence SandRidge’s activities or operations of the Underlying Properties. In addition, some of the Trust Development Wells may be operated by third parties unrelated to SandRidge. Such third-party operators may not have the operational expertise of SandRidge within the AMI. Oil and natural gas properties are typically managed pursuant to an operating agreement among the working interest owners in the properties. The typical operating agreement contains procedures whereby the owners of the aggregate working interest in the property designate one of the interest owners to be the operator of the property. Under these arrangements, the operator is typically responsible for making all decisions relating to drilling activities, sale of production, compliance with regulatory requirements and other matters that affect the property. The failure of an operator to adequately perform operations could reduce production from the Underlying Properties and cash available for distribution to unitholders. Neither the Trustee nor the Trust unitholders has any contractual or other ability to influence or control the field operations of, sale of oil and natural gas from, or future development of, the Underlying Properties.
The oil and natural gas reserves estimated to be attributable to the Royalty Interests are depleting assets and production from those reserves will diminish over time. Furthermore, the Trust is precluded from acquiring other oil and natural gas properties or royalty interests to replace the depleting assets and production.
The proceeds payable to the Trust from the Royalty Interests are derived from the sale of the production of oil and natural gas from the Underlying Properties. The oil and natural gas reserves attributable to the Royalty Interests are depleting assets, which means that the reserves of oil and natural gas attributable to the Royalty Interests will decline over time as will the quantity of oil and natural gas produced from the Underlying Properties.
Future maintenance may affect the quantity of proved reserves that can be economically produced from the Underlying Properties to which the wells relate. The timing and size of these projects will depend on, among other factors, the market prices of oil and natural gas. With the exception of SandRidge’s commitment to drill the Trust Development Wells, SandRidge has no contractual obligation to make capital expenditures on the Underlying Properties in the future. Furthermore, for properties on which SandRidge is not designated as the operator, SandRidge has no control over the timing or amount of those capital expenditures. SandRidge also has the right to non-consent and not participate in the capital expenditures on properties for which it is not the operator, in which case SandRidge and the Trust will not receive the production resulting from such capital expenditures. If SandRidge or other operators of the wells to which the Underlying Properties relate do not implement maintenance projects when warranted, the future rate of production decline of proved reserves may be higher than the rate currently expected by SandRidge or estimated in the Trust’s reserve report.
The trust agreement provides that the Trust’s business activities are generally limited to owning the Royalty Interests and entering into the hedging arrangements and activities reasonably related thereto, including activities required or permitted by the terms of the conveyances related to the Royalty Interests. As a result, the Trust is not permitted to acquire other oil and gas properties or royalty interests to replace the depleting assets and production attributable to the Trust.
An increase in the differential between the price realized by SandRidge for oil and natural gas produced from the Underlying Properties and the NYMEX or other benchmark price of oil or natural gas could reduce the proceeds to the Trust and therefore the cash distributions by the Trust and the value of Trust units.
The prices received for oil and natural gas production usually fall below benchmark prices such as NYMEX. The difference between the price received and the benchmark price is called a differential. The amount of the differential depends on a variety of factors, including discounts based on the quality and location of
hydrocarbons produced, Btu content and post-production costs. These factors can cause differentials to be volatile from period to period. Sellers of production have little or no control over the factors that determine the amount of the differential, and cannot accurately predict differentials for natural gas or crude oil. Increases in the differential between the realized price of oil or natural gas and the benchmark price for oil or natural gas could reduce the proceeds to the Trust and therefore the cash distributions made by the Trust and the value of the Trust units. The estimated realized prices for natural gas used to prepare the target distributions the NYMEX futures prices for natural gas, and the estimated realized prices for oil used to prepare the target distributions assumed a of $5.03 per barrel negative differential from the NYMEX futures prices for oil.
The amount of cash available for distribution by the Trust is reduced by post-production costs and applicable taxes associated with the Royalty Interests, Trust expenses and incentive distributions payable to SandRidge.
The Royalty Interests and the Trust bear certain costs and expenses that reduce the amount of cash received by or available for distribution by the Trust to the holders of the Trust units. These costs and expenses include the following:
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the Trust’s share of the costs incurred by SandRidge to gather, store, compress, transport, process, treat, dehydrate and market the oil and natural gas (excluding costs of marketing services provided by SandRidge);
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the Trust’s share of applicable taxes, including taxes on the production of oil and natural gas;
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Trust administrative expenses, including fees paid to the Trustee and the Delaware Trustee, the annual administrative services fee payable to SandRidge, tax return and Schedule K-1 preparation and mailing costs, independent auditor fees and registrar and transfer agent fees, and costs associated with annual and quarterly reports to unitholders; and
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any amounts owed to counterparties under the hedging contracts underlying the derivatives agreement.
In addition, the amount of funds available for distribution to unitholders is reduced by the amount of any cash reserves maintained by the Trustee in respect of anticipated future Trust administrative expenses.
Further, during the subordination period, SandRidge is entitled to receive a quarterly incentive distribution from the Trust equal to 50% of the amount by which cash available to be paid to all unitholders exceeds the Incentive Threshold for the applicable quarter.
The amount of post-production costs, taxes and expenses borne by the Trust and incentive distributions payable to SandRidge may vary materially from quarter-to-quarter. The extent by which the costs and expenses of the Trust are higher or lower in any quarter will directly decrease or increase the amount received by the Trust and available for distribution to the unitholders. Historical post-production costs and taxes, however, may not be indicative of future post-production costs and taxes.
The hedging arrangements for the Trust cover only a portion of the oil and natural gas production attributable to the Trust, and such contracts limit the Trust’s ability to benefit from commodity price increases for hedged volumes above the corresponding hedge price.
Pursuant to the derivatives agreement, SandRidge has provided the Trust with the effect of certain oil and natural gas hedging contracts that it has entered into with third parties. The derivatives agreement covers only a portion of the estimated oil and natural gas production attributable to the Royalty Interests, and will terminate after December 31, 2015. The Trust’s receipt of any payments due to it based on the derivatives agreement depends upon the financial position of SandRidge and SandRidge’s hedge contract counterparties. A default by SandRidge or any of the hedge contract counterparties could reduce the amount of cash available for distribution to the Trust unitholders. See “-SandRidge’s ability to satisfy its obligations to the Trust depends on its financial position, and in the event of a default by SandRidge in its obligation to drill the Trust Development Wells, or in the event of SandRidge’s bankruptcy, it may be expensive and time-consuming for the Trust to exercise its remedies.”
Pursuant to the derivatives agreement, 41% of the expected production and approximately 65% of the expected revenues upon which the target distributions were based from January 1, 2013 through December 31, 2015 have been hedged. The remaining estimated production of oil and natural gas during that time and all production after such time will not be hedged to protect against the price risks inherent in holding interests in oil and natural gas, a commodity that is frequently characterized by significant price volatility. Furthermore, while the use of hedging arrangements limits the downside risk of price declines, they may also limit the Trust’s ability to benefit from increases in oil and natural gas prices above the hedge price on the portion of the production attributable to the Royalty Interests that is hedged. The Trust does not have any ability to terminate the hedging contracts.
The Trust’s counterparty under the derivatives agreement is SandRidge, whose counterparties are Deutsche Bank AG London Branch, Credit Suisse Energy, LLC, and Royal Bank of Canada. In the event that any of the counterparties to the oil and natural gas hedging contracts defaults on its obligations to make payments under such contracts, the cash distributions to the Trust unitholders would likely be materially reduced as the hedge payments are intended to provide additional cash to the Trust during periods of lower oil and natural gas prices. SandRidge will not be required to make payments to the Trust under the derivatives agreement to the extent of payment defaults by SandRidge’s hedge contract counterparties. The Trust has no ability to enter into its own hedges.
The Trust is administered by a Trustee who cannot be replaced except at a special meeting of Trust unitholders.
The business and affairs of the Trust are administered by the Trustee. A unitholder’s voting rights are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of Trust unitholders or for an annual or other periodic re-election of the Trustee. The trust agreement provides that the Trustee may only be removed and replaced by the holders of a majority of the outstanding Trust units, excluding Trust units held by SandRidge, voting in person or by proxy at a special meeting of Trust unitholders at which a quorum is present called by either the Trustee or the holders of not less than 10% of the outstanding Trust units. As a result, it may be difficult for public unitholders to remove or replace the Trustee without the cooperation of holders of a substantial percentage of the outstanding Trust units.
Trust unitholders have limited ability to enforce provisions of the Royalty Interests, and SandRidge’s liability to the Trust is limited.
The trust agreement permits the Trustee and the Trust to sue SandRidge or any other future owner of the Underlying Properties to enforce the terms of the conveyances creating the Royalty Interests. If the Trustee does not take appropriate action to enforce provisions of these conveyances, a Trust unitholder’s recourse would be limited to bringing a lawsuit against the Trustee to compel the Trustee to take specified actions. The trust agreement expressly limits a Trust unitholder’s ability to directly sue SandRidge or any other party other than the Trustee. As a result, Trust unitholders will not be able to sue SandRidge or any future owner of the Underlying Properties to enforce the Trust’s rights under the conveyances. Furthermore, the Royalty Interest conveyances provide that, except as set forth in the conveyances, SandRidge will not be liable to the Trust for the manner in which it performs its duties in operating the Underlying Properties as long as it acts in good faith and, to the fullest extent permitted by law, will owe no fiduciary duties to the Trust or the unitholders.
Courts outside of Delaware may not recognize the limited liability of the Trust unitholders provided under Delaware law.
Under the Delaware Statutory Trust Act, Trust unitholders are entitled to the same limitation of personal liability extended to stockholders of private corporations for profit under the General Corporation Law of the State of Delaware. However, courts in jurisdictions outside of Delaware may not give effect to such limitation.
Sale of trust units by SandRidge could have an adverse impact on the trading price of the common units.
As of March 8, 2013, SandRidge, through SandRidge E&P, owned an aggregate of 7,393,750 common units and 12,431,250 subordinated units. All of the subordinated units will automatically convert into common units at the end of the subordination period. SandRidge may sell Trust units in the public or private markets, and any such sales could have an adverse impact on the price of the common units or on any trading market that may develop. The Trust has granted registration rights to SandRidge, which, if exercised, would facilitate sales of Trust units by SandRidge to the public.
SandRidge could have interests that conflict with the interests of the Trust and Trust unitholders.
As a working interest owner in the Underlying Properties, SandRidge could have interests that conflict with the interests of the Trust and the Trust unitholders. For example:
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Notwithstanding its drilling obligation to the Trust, SandRidge’s interests may conflict with those of the Trust and the Trust unitholders in situations involving the development, maintenance, operation or abandonment of the Underlying Properties. Additionally, SandRidge may, consistent with its obligation to act as a reasonably prudent operator, abandon a well that is uneconomic or not generating revenues from production in excess of its operating costs, even though such well is still generating revenue for the Trust unitholders. Subsequent to fulfilling its drilling obligation, SandRidge may make decisions with respect to expenditures and decisions to allocate resources on projects in other areas that adversely affect the Underlying Properties, including reducing expenditures on these properties, which could cause oil and natural gas production to decline at a faster rate and thereby result in lower cash distributions by the Trust in the future.
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Following the satisfaction of its drilling obligation to the Trust, SandRidge may, without the consent or approval of the Trust unitholders, sell all or any part of its retained interest in the Underlying Properties, if the Underlying Properties are sold subject to and burdened by the Royalty Interests. Such sale may not be in the best interests of the Trust and Trust unitholders. For example, any purchaser may lack SandRidge’s experience in the Mississippian formation or its creditworthiness.
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Following the satisfaction of its drilling obligation to the Trust, SandRidge may, without the consent or approval of the Trust unitholders, require the Trust to release Royalty Interests with an aggregate value of up to $5.0 million during any 12-month period in connection with a sale by SandRidge of a portion of its retained interest in the Underlying Properties. The fair value received by the Trust for such Royalty Interests may not fully compensate the Trust for the value of future production attributable to the Royalty Interests disposed of.
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SandRidge is permitted under the conveyance agreements creating the Royalty Interests to enter into new processing and transportation contracts without obtaining bids from or otherwise negotiating with any independent third parties, and SandRidge will deduct from the Trust’s proceeds any charges under such contracts attributable to production from the Trust properties.
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SandRidge can sell its Trust units regardless of the effects such sale may have on common unit prices or on the Trust itself. Additionally, SandRidge can vote its Trust units in its sole discretion.
In addition, SandRidge has agreed that, if at any time the Trust’s cash on hand (including available cash reserves) is not sufficient to pay the Trust’s ordinary course administrative expenses as they become due, SandRidge will loan funds to the Trust necessary to pay such expenses. Any such loan will be on an unsecured basis, and the terms of such loan will be substantially the same as those which would be obtained in an arms’ length transaction between SandRidge and an unaffiliated third party. If SandRidge provides such funds to the Trust, it would become a creditor of the Trust and its interests as a creditor could conflict with the interests of unitholders.
SandRidge may sell all or a portion of the Underlying Properties, subject to and burdened by the Royalty Interests, after satisfying its drilling obligation to the Trust; any such purchaser could have a weaker financial position and/or be less experienced in oil and natural gas development and production than SandRidge.
Unitholders will not be entitled to vote on any sale of the Underlying Properties if the Underlying Properties are sold subject to and burdened by the Royalty Interests and the Trust will not receive any proceeds from any such sale. The purchaser would be responsible for all of SandRidge’s obligations relating to the Royalty Interests on the portion of the Underlying Properties sold, and SandRidge would have no continuing obligation to the Trust for those properties. Additionally, SandRidge may enter into farmout or joint venture arrangements with respect to the wells burdened by the Trust’s Royalty Interest. Any purchaser, farmout counterparty or joint venture partner could have a weaker financial position and/or be less experienced in oil and natural gas development and production than SandRidge. Finally, as hedge manager to the trust, SandRidge has the ability to negotiate the terms of any novation, assignment or transfer of any hedge contract to which SandRidge is a party.
SandRidge’s ability to satisfy its obligations to the Trust depends on its financial position, and in the event of a default by SandRidge in its obligation to drill the Trust Development Wells, or in the event of SandRidge’s bankruptcy, it would be expensive and time-consuming for the Trust to exercise its remedies.
Pursuant to the terms of the development agreement between SandRidge and the Trust, SandRidge is obligated to drill, or cause to be drilled, the Trust Development Wells at its own expense. SandRidge owns a majority working interest in substantially all of the locations on which it expects to drill the remaining Trust Development Wells, and it expects to operate such wells until completion of its drilling obligation. SandRidge is also the operator of 92% of the Initial Wells together with the wells drilled as Trust Development Wells through December 31, 2012. The conveyances provide that SandRidge is obligated to market, or cause to be marketed, the oil and natural gas production related to the Underlying Properties. Additionally, SandRidge is the counterparty to the Trust’s derivatives agreement and has certain obligations to the Trust under the agreement. In the event that SandRidge defaults on its obligation to make payments under the derivatives agreement, the cash distributions to the Trust unitholders may be materially reduced as these payments are intended to provide additional cash to the Trust during periods of lower oil and natural gas prices. Due to the Trust’s reliance on SandRidge to fulfill these numerous obligations, the value of the Royalty Interests and its ultimate cash available for distribution is highly dependent on SandRidge’s performance.
SandRidge has other drilling obligations, including drilling obligations to two other royalty trusts, which will require it to make capital expenditures over the next several years at the same time it plans to drill the remaining Trust Development Wells. SandRidge’s ability to satisfy its drilling obligation to the Trust will depend on, among other things, the availability of sufficient funds and drilling rigs. More generally, SandRidge’s ability to satisfy its drilling obligation to the Trust and to perform these obligations depends on its future financial condition and economic performance and access to capital, which in turn depends upon the supply and demand for oil and natural gas, prevailing economic conditions and financial, business and other factors, many of which are beyond SandRidge’s control.
In the event that SandRidge defaults on its obligation to drill the remaining Trust Development Wells, the Trust would be entitled to foreclose on the lien granted to the trust by SandRidge E&P in order to secure the estimated amount of the drilling costs for the trust’s interests in the undeveloped Underlying Properties (the “Drilling Support Lien”) to the extent of SandRidge’s remaining interests in the undeveloped portions of the AMI. However, the maximum amount the Trust can recover in such a foreclosure or other action was, as of December 31, 2012, approximately $258.2 million, which amount will be reduced proportionately as each remaining Trust Development Well is drilled and perforated for completion with a perforated length of 3,500 feet. The value of SandRidge’s interests in the undeveloped portions of the AMI secured by the Drilling Support Lien may not be equal to the amount potentially recoverable at any given time, and such interests may be worth considerably less. The process of foreclosing on such collateral would be expensive and time-consuming and would delay the drilling and completion of the remaining Trust Development Wells; such delays and expenses
would reduce Trust distributions by reducing the amount of proceeds available for distribution. Any amounts actually recovered in a foreclosure action would be applied to completion of SandRidge’s drilling obligation, would not result in any distribution to the Trust unitholders and may be insufficient to drill the number of wells needed for the Trust to realize the full value of the Development Well Royalty Interest. Furthermore, the Trust would have to seek a new party to perform the drilling and operations of the wells. The Trust may not be able to find a replacement driller or operator, and it may not be able to enter into a new agreement with such replacement party on favorable terms within a reasonable period of time.
SandRidge will not be required to maintain a segregated account for proceeds payable to the Trust. The proceeds of the Royalty Interests may be commingled, for a period of time, with proceeds of SandRidge’s retained interest in the Underlying Properties for the period of time between SandRidge’s sale of hydrocarbons attributable to the Royalty Interests and the quarterly payment to the Trust of its share of proceeds. It is possible that the Trust may not have adequate facts to trace its entitlement to funds in the commingled pool of funds and that other persons may, in asserting claims against SandRidge’s retained interest, be able to assert claims to the proceeds that should be delivered to the Trust. If there is an event of default under SandRidge’s credit facility, SandRidge must keep its accounts with banks that enter into control agreements with the administrative agent under the credit facility, which would permit the administrative agent to direct payment of funds in such accounts during the pendency of an event of default. In addition, during any bankruptcy of SandRidge, it is possible that payments of the royalties may be delayed or deferred. During the pendency of any SandRidge bankruptcy proceedings, the Trust’s ability to foreclose on the Drilling Support Lien, and the ability to collect cash payments being held in SandRidge’s accounts that are attributable to production from the Trust properties, may be stayed by the bankruptcy court. Delay in realizing on the collateral for the Drilling Support Lien is possible, and it cannot be guaranteed that a bankruptcy court would permit such foreclosure. It is possible that the bankruptcy would also delay the execution of a new agreement with another driller or operator. If the Trust enters into a new agreement with a drilling or operating partner, the new partner might not achieve the same levels of production or sell oil and natural gas at the same prices as SandRidge was able to achieve.
Oil and natural gas wells are subject to operational hazards that can cause substantial losses. SandRidge maintains insurance; however, SandRidge may not be adequately insured for all such hazards.
There are a variety of operating risks inherent in oil and natural gas production and associated activities, such as fires, leaks, explosions, mechanical problems, major equipment failures, blowouts, uncontrollable flow of oil, natural gas, water or drilling fluids, casing collapses, abnormally pressurized formations and natural disasters. The occurrence of any of these or similar accidents that temporarily or permanently halt the production and sale of oil and natural gas at any of the Underlying Properties will reduce Trust distributions by reducing the amount of proceeds available for distribution.
Additionally, if any of such risks or similar accidents occur, SandRidge could incur substantial losses as a result of injury or loss of life, severe damage or destruction of property, natural resources and equipment, regulatory investigation and penalties and environmental damage and clean-up responsibility. If SandRidge experiences any of these problems, its ability to conduct operations and perform its obligations to the Trust could be adversely affected. While SandRidge maintains insurance coverage it deems appropriate for these risks with respect to the Underlying Properties, SandRidge’s operations may result in liabilities exceeding such insurance coverage or liabilities not covered by insurance. If a well is damaged, SandRidge would have no obligation to drill a replacement well or make the Trust whole for the loss.
The operation of the Underlying Properties is subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner and feasibility of conducting operations on the properties, which in turn could negatively impact trust distributions, estimated and actual future net revenues to the trust and estimates of reserves attributable to the trust’s interests.
Oil and natural gas exploration, production, transportation and treatment operations are subject to complex and stringent laws and regulations. In order to conduct operations in compliance with these laws and regulations, numerous permits, approvals and certificates are required from various federal, state and local governmental
authorities. Compliance with these existing laws and regulations may require the incurrence of substantial costs by SandRidge or other operators of the Underlying Properties. Additionally, there has been a variety of regulatory initiatives at the federal and state levels to further regulate oil and natural gas operations in certain locations. Any increased regulation or suspension of oil and natural gas operations, or revision or reinterpretation of existing laws and regulation, could result in delays and higher operating costs. Such costs or significant delays could have a material adverse effect on the operation of the Underlying Properties, which in turn could negatively impact Trust distributions, estimated and actual future net revenues to the Trust and estimates of reserves attributable to the Trust’s interests.
Laws and regulations governing oil and natural gas exploration and production may also affect production levels. SandRidge is required to comply with federal and state laws and regulations governing conservation matters, including provisions related to the unitization or pooling of the oil and natural gas properties; the establishment of maximum rates of production from wells; the spacing of wells; and the plugging and abandonment of wells. These and other laws and regulations can limit the amount of oil and natural gas SandRidge can produce from its wells, limit the number of wells it can drill, or limit the locations at which it can conduct drilling operations, which in turn could negatively impact Trust distributions, estimated and actual future net revenues to the Trust and estimates of reserves attributable to the Trust’s interests.
New laws or regulations, or changes to existing laws or regulations may unfavorably impact SandRidge, could result in increased operating costs and could have a material adverse effect on SandRidge’s financial condition and results of operations. For example, Congress has recently considered, and may continue to consider, legislation that, if adopted in its proposed form, would subject companies involved in oil and natural gas exploration and production activities to, among other items, additional regulation of and restrictions on hydraulic fracturing of wells, and the elimination of most U.S. federal tax incentives and deductions available to oil and natural gas exploration and production activities. In addition, the Dodd-Frank Wall Street Reform and Consumer Protection Act and rules promulgated there under could reduce trading positions in the energy futures markets and materially reduce hedging opportunities for SandRidge, which could adversely affect its revenues and cash flows during periods of low commodity prices, and which could adversely affect the ability to restructure the hedges when it might be desirable to do so.
Additionally, federal and state regulatory authorities may expand or alter applicable pipeline safety laws and regulations, compliance with which may require increased capital costs on the part of SandRidge and third-party downstream oil and natural gas transporters. These and other potential regulations could increase SandRidge’s operating costs, reduce SandRidge’s liquidity, delay SandRidge’s operations, increase direct and third-party post production costs associated with the Trust’s interests or otherwise alter the way SandRidge conducts its business, which could have a material adverse effect on SandRidge’s financial condition, results of operations and cash flows and which could reduce cash received by or available for distribution, including any amounts paid by SandRidge for transportation on downstream interstate pipelines.
The operation of the Underlying Properties is subject to environmental laws and regulations that could adversely affect the cost, manner or feasibility of conducting operations or result in significant costs and liabilities.
The oil and natural gas exploration and production operations on the Underlying Properties are subject to stringent and comprehensive federal, state, and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that are applicable to operations of the Underlying Properties, including the acquisition of permits before conducting drilling; water withdrawal or waste disposal activities; the restriction of types, quantities and concentrations of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the imposition of regulations designed to protect employees from exposure to hazardous substances; and the imposition of substantial liabilities for pollution resulting from operations. Numerous governmental authorities, such as the
EPA and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions. Failure to comply with these laws and regulations may result in litigation; the assessment of administrative, civil and criminal penalties; the imposition of investigatory or remedial obligations; and the issuance of injunctions limiting or preventing some or all operations relating to the Underlying Properties.
There is inherent risk of incurring significant environmental costs and liabilities in the performance of operations at the Underlying Properties due to the handling of petroleum hydrocarbons and wastes, because of air emissions and wastewater discharges related to its operations, and as a result of historical industry operations and waste disposal practices. Under certain environmental laws and regulations, an operator could be subject to joint and several strict liability for the investigation, removal or remediation of previously released materials or property contamination regardless of whether the operator was responsible for the release or contamination or whether the operations were in compliance with all applicable laws at the time the release or contamination occurred. Private parties, including the owners of properties upon which wells are drilled and facilities where petroleum hydrocarbons or wastes are taken for reclamation or disposal may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for contamination even in the absence of non-compliance, with environmental laws and regulations or for personal injury or property damage.
In addition, the risk of accidental spills or releases could expose an operator to significant liabilities that could have a material adverse effect on its financial condition or results of operations. Certain laws related to oil spills impose joint and several strict liability, without regard to fault, for all containment and oil removal costs and a variety of public and private damages including, but not limited to, the costs of responding to a release of oil, natural resource damages, and economic damages suffered by persons adversely affected by an oil spill. Although defenses exist to the liability imposed by those laws, they are limited. If an oil discharge or substantial threat of discharge were to occur, an operator may be liable for costs and damages, which costs and damages could be material to its results of operations and financial position.
Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly construction, drilling, water management, completion, waste handling, storage, transport, disposal or cleanup requirements could require significant expenditures by SandRidge or other operators of the Underlying Properties to attain and maintain compliance and may otherwise have a material adverse effect on the results of operations, competitive position or financial condition of SandRidge or such other operator. SandRidge or such other operator may not be able to recover some or any of these costs from insurance. As a result of any increased cost of compliance, SandRidge or such other operator may decide to discontinue drilling. Additionally, permitting delays may inhibit SandRidge’s ability to drill the remaining Trust Development Wells on schedule.
Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that SandRidge produces while the physical effects of climate change could disrupt SandRidge’s production and cause SandRidge to incur significant costs in preparing for or responding to those effects.
In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present a danger to public health and the environment because such gases are contributing to warming of the Earth’s atmosphere and other climatic changes. These findings allow the agency to adopt and implement regulations that restrict emissions of GHGs under existing provisions of the Clean Air Act. Accordingly, the EPA has adopted rules that require a reduction in emissions of GHGs from motor vehicles and also trigger Clean Air Act construction and operating permit review for GHG emissions from certain stationary sources. The EPA’s endangerment finding and GHG rules were upheld by the United States Court of Appeals for the D.C. Circuit in a June 2012 decision, and a petition for review of the case by the entire D.C. Circuit was denied in December 2012.
The EPA also has adopted rules requiring the reporting of GHG emissions from onshore oil and natural gas production and processing facilities in the United States on an annual basis. SandRidge believes it has complied with all applicable reporting requirements to date. However, the adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, SandRidge’s equipment and operations could require SandRidge to incur additional costs to reduce emissions of GHGs associated with its operations or could adversely affect demand for the oil and natural gas that it produces. Finally, to the extent increasing concentrations of GHG in the Earth’s atmosphere may produce climate change that could have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events such events could have a material adverse effect on the Underlying Properties, and potentially subject SandRidge to greater regulation.
In addition, Congress has considered legislation to reduce emissions of GHGs and more than half of the states have begun taking actions to control and/or reduce emissions of GHGs, primarily through the adoption of a climate change action plan, completion of GHG emission inventories and/or regional GHG cap and trade programs. Any future federal laws or implemented regulations that may be adopted to address GHG emissions could require SandRidge to incur increased operating costs, adversely affect demand for the oil and natural gas that the SandRidge produces and have a material adverse effect on SandRidge’s business, financial condition and results of operations.
Federal and state legislative and regulatory initiatives as well as governmental reviews relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect the level of production from the Underlying Properties.
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations, such as shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing is typically regulated by state oil and gas commissions; however, the EPA has asserted federal regulatory authority over certain hydraulic fracturing practices, including the use of diesel, kerosene and similar compounds in fracturing fluid. In August 2012, the EPA issued final Clean Air Act regulations governing performance standards, including standards for the capture of air emissions released during hydraulic fracturing. However, in January 2013 the EPA submitted an unopposed motion to the United States Court of Appeals for the D.C. Circuit seeking to stay legal challenges to the Clean Air Act regulations while the EPA reconsiders portions of the new rules. Also, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In May 2012, the Bureau of Land Management within the U.S. Department of the Interior issued a proposed rule containing disclosure requirements and other mandates for hydraulic fracturing on federal lands, but in January 2013 it announced that it would be submitting a revised proposed rule. That revised proposed rule is expected to be published in the first quarter of 2013.
Certain states in which SandRidge operates, including Kansas and Oklahoma, and municipalities have adopted, or are considering adopting, regulations that have imposed, or that could impose, more stringent permitting, disclosure, disposal and well construction requirements on exploration and production activities. Local ordinances or other regulations may regulate or prohibit the performance of well drilling in general and hydraulic fracturing in particular. If new laws or regulations that significantly restrict or regulate hydraulic fracturing are adopted at either the state or the federal level, the Company’s fracturing activities could become subject to additional permit requirements, reporting requirements or operational restrictions and also to associated permitting delays, or additional costs could adversely affect the determination of whether a well is commercially viable. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that ultimately can be produced in commercial quantities from the Underlying Properties.
In addition to asserting regulatory authority, a number of federal entities are analyzing, or have been requested to review, a variety of environmental issues associated with unconventional natural gas production, including hydraulic fracturing. In April 2012, President Obama issued an executive order that established a
working group for the purpose of coordinating policy, information sharing, and planning among federal agencies and offices regarding “unconventional natural gas production,” including hydraulic fracturing. In December 2012, the EPA issued an initial progress report on a study begun in 2011 of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a final report expected to be issued in late 2014. The EPA has also announced its intent to propose by 2014 effluent limit guidelines that waste water from shale gas extraction operations must meet before going to a treatment plant; the agency also projects that it will publish an Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Additionally, a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices, and certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources; the SEC to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing; and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. Bills previously have been introduced in both the Senate and the House of Representatives to, among other things, amend the federal Safe Drinking Water Act to repeal provisions that exempt hydraulic fracturing operations from restrictions that otherwise would apply to underground injection of fluids or propping agents. The studies and initiatives described above, depending on their degree of pursuit and any meaningful results obtained, could spur efforts to further regulate hydraulic fracturing under the Safe Drinking Water Act or other regulatory mechanisms.
The Trust is subject to the requirements of the Sarbanes-Oxley Act of 2002, which may impose cost and operating challenges on it.
The Trust is subject to certain of the requirements of the Sarbanes-Oxley Act of 2002 which requires, among other things, maintenance by the Trust of, and reports regarding the effectiveness of, a system of internal control over financial reporting. Complying with these requirements may pose operational challenges and may cause the Trust to incur unanticipated expenses. Any failure by the Trust to comply with these requirements could lead to a loss of public confidence in the Trust’s internal controls and in the accuracy of the Trust’s publicly reported results.
Tax Risks Related to the Units
The Trust’s tax treatment depends on its status as a partnership for U.S. federal income tax purposes. If the U.S. Internal Revenue Service (“IRS”) were to treat the Trust as a corporation for U.S. federal income tax purposes, then its cash available for distribution to unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in the Trust units depends largely on the Trust being treated as a partnership for U.S. federal income tax purposes. The Trust has not requested, and does not plan to request, a ruling from the IRS, on this or any other tax matter affecting it.
It is possible in certain circumstances for a publicly traded trust otherwise treated as a partnership, such as the Trust, to be treated as a corporation for U.S. federal income tax purposes. In addition, a change in current law could cause the Trust to be treated as a corporation for U.S. federal income tax purposes or otherwise subject it to federal taxation as an entity.
If the Trust were treated as a corporation for U.S. federal income tax purposes, it would pay federal income tax on its taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely be required to also pay state income tax on its taxable income at the corporate tax rate of such state. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to unitholders without first being subjected to taxation at the entity level. Because
additional tax would be imposed upon the Trust as a corporation, its cash available for distribution to unitholders would be substantially reduced. Therefore, treatment of the Trust as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the Trust unitholders, likely causing a substantial reduction in the value of the Trust units.
The trust agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects the Trust to additional amounts of entity-level taxation for state or local income tax purposes, the Subordination Threshold amounts, Incentive Threshold amounts and target distribution amounts may be adjusted to reflect the impact of that law on the Trust.
If the Trust were subjected to a material amount of additional entity-level taxation by individual states, it would reduce the Trust’s cash available for distribution to unitholders.
Changes in current state law may subject the Trust to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation.
Additional imposition of such taxes may substantially reduce the cash available for distribution to unitholders and, therefore, negatively impact the value of an investment in Trust units. The trust agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects the Trust to additional amounts of entity-level taxation for state or local income tax purposes, the Subordination Threshold amounts, Incentive Threshold amounts and target distribution amounts may be adjusted to reflect the impact of that law on the Trust.
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. Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income and long-term capital gains of individuals is 39.6% and 20%, respectively. Moreover, these rates are subject to change by new legislation at any time.
Current law may change so as to cause the Trust to be treated as a corporation for U.S. federal income tax purposes or otherwise subject the Trust to entity-level taxation. Specifically, the present U.S. federal income tax treatment of publicly traded partnerships, including the Trust, or an investment in the Trust units may be modified by administrative, legislative or judicial interpretation at any time. For example, at the federal level, legislation has been proposed in the past that would have eliminated partnership tax treatment for certain publicly traded partnerships. Although such legislation would not have applied to the Trust as it was proposed, it could be reintroduced in a manner that does apply to the Trust.
The trust agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects the Trust to taxation as a corporation or otherwise subjects it to entity-level taxation for U.S. federal income tax purposes, Subordination Threshold amounts, the Incentive Threshold amounts and the target distribution amounts may be adjusted to reflect the impact of that law on the Trust.
The Trust has adopted and may continue to adopt positions that may not conform to all aspects of existing Treasury Regulations. If the IRS contests the tax positions the Trust takes, the value of the Trust units may be adversely affected, the cost of any IRS contest will reduce the Trust’s cash available for distribution and income, gains, losses and deductions may be reallocated among Trust unitholders.
If the IRS contests any of the U.S. federal income tax positions the Trust takes or has taken, the value of the Trust units may be adversely affected because the cost of any IRS contest will reduce the Trust’s cash available for distribution and income, gain, loss and deduction may be reallocated among Trust unitholders. For example, the Trust generally prorates its items of income, gain, loss and deduction between transferors and transferees of the Trust units each quarter based upon the record ownership of the Trust units on the quarterly record date in such quarter, instead of on the basis of the date a particular Trust unit is transferred. Although simplifying conventions are contemplated by the Internal Revenue Code, and most publicly traded partnerships use similar simplifying conventions, the use of these methods may not be permitted under existing Treasury Regulations.
The Trust has not requested a ruling from the IRS with respect to its treatment as a partnership for U.S. federal income tax purposes or any other matter affecting the Trust. The IRS may adopt positions that differ from the conclusions of SandRidge’s counsel or from the positions the Trust takes. It may be necessary to resort to administrative or court proceedings to attempt to sustain some or all of the conclusions of SandRidge’s counsel or the positions the Trust takes. A court may not agree with some or all of the conclusions of SandRidge’s counsel or positions the Trust takes. Any contest with the IRS may materially and adversely impact the market for the Trust units and the price at which they trade. In addition, the Trust’s costs of any contest with the IRS will be borne indirectly by the Trust unitholders because the costs will reduce the Trust’s cash available for distribution.
Each unitholder is required to pay taxes on the unitholder’s share of the Trust’s income even if a unitholder does not receive cash distributions from the Trust equal to the unitholder’s share of the Trust’s taxable income.
Because the Trust unitholders are treated as partners to whom the Trust allocates taxable income that could be different in amount than the cash the Trust distributes, each unitholder may be required to pay any federal income taxes and, in some cases, state and local income taxes on the unitholder’s share of the Trust’s taxable income even if a unitholder may not receive cash distributions from the Trust equal to the unitholder’s share of the Trust’s taxable income or even equal to the actual tax liability that results from that income.
Tax gain or loss on the disposition of the Trust units could be more or less than expected.
If a unitholder sells its Trust units, the unitholder will recognize a gain or loss equal to the difference between the amount realized and the unitholder’s tax basis in those Trust units. Because distributions in excess of a unitholder’s allocable share of the Trust’s net taxable income decrease the unitholder’s tax basis in its Trust units, the amount, if any, of such prior excess distributions with respect to the Trust units unitholders sell will, in effect, become taxable income to unitholders if unitholders sell such Trust units at a price greater than the unitholder’s tax basis in those Trust units, even if the price the unitholder receives is less than the unitholder’s original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depletion recapture.
The ownership and disposition of Trust units by non-U.S. persons may result in adverse tax consequences to them.
Investment in Trust units by non-U.S. persons raises issues unique to them. For example, distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons may be required to file U.S. federal income tax returns and pay tax on their share of the Trust’s taxable income or proceeds from the sale of trust units. If a unitholder is a non-U.S. person, the unitholder should consult a tax advisor before investing in the Trust units.
The Trust treats each purchaser of Trust units as having the same economic attributes without regard to the actual Trust units purchased. The IRS may challenge this treatment, which could adversely affect the value of the Trust units.
Due to a number of factors, including the Trust’s inability to match transferors and transferees of Trust units, the Trust may adopt positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely alter the tax effects of an investment in Trust units. It also could affect the timing of tax benefits or the amount of gain from a unitholder’s sale of Trust units and could have a negative impact on the value of the Trust units or result in audit adjustments to a unitholder’s tax returns.
The Trust prorates its items of income, gain, loss and deduction between transferors and transferees of the Trust units each quarter based upon the record ownership of the Trust units on the quarterly record date, in such quarter, instead of on the basis of the date a particular Trust unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among the Trust unitholders.
The Trust generally prorates its items of income, gain, loss and deduction between transferors and transferees of the Trust units based upon the record ownership of the Trust units on the quarterly record date in such quarter instead of on the basis of the date a particular Trust unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations, and, accordingly, SandRidge’s counsel is unable to opine as to the validity of this method. If the IRS were to challenge the Trust’s proration method, the Trust may be required to change its allocation of items of income, gain, loss and deduction among the Trust unitholders and the costs to the Trust of implementing and reporting under any such changed method may be significant.
A Trust unitholder whose Trust units are loaned to a “short seller” to cover a short sale of Trust units may be considered as having disposed of those Trust units. If so, he would no longer be treated for tax purposes as a partner with respect to those Trust units during the period of the loan and may recognize gain or loss from the disposition.
Because a Trust unitholder whose Trust units are loaned to a “short seller” to cover a short sale of Trust units may be considered as having disposed of the loaned Trust units, he may no longer be treated for tax purposes as a partner with respect to those Trust units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of the Trust’s income, gains, losses or deductions with respect to those Trust units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those Trust units could be fully taxable as ordinary income. Trust unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from loaning their Trust units.
The Trust may adopt certain valuation methodologies that may affect the income, gain, loss and deduction allocable to the Trust unitholders. The IRS may challenge this treatment, which could adversely affect the value of the Trust units.
The U.S. federal income tax consequences of the ownership and disposition of Trust units will depend in part on the Trust’s estimates of the relative fair market values, and the initial tax bases of the Trust’s assets. Although the Trust may from time to time consult with professional appraisers regarding valuation matters, the Trust will make many of the relative fair market value estimates itself. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by Trust unitholders might change, and Trust unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.
The sale or exchange of 50% or more of the Trust’s capital and profits interests during any 12-month period will result in the termination of the Trust’s partnership status for U.S. federal income tax purposes.
The Trust will be considered to have technically terminated for U.S. federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in its capital and profits within a 12-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same Trust unit within any 12-month period will be counted only once. The Trust’s termination would, among other things, result in the closing of its taxable year for all Trust unitholders, which would result in the Trust filing two tax returns (and the Trust unitholders would receive two Schedules K-1) for one calendar year. However, the IRS announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership will be required to provide only a single Schedule K-1 to unitholders for the short taxable years that result from the technical termination. In the case of a unitholder reporting on a taxable year other than a calendar year ending December 31, the closing of the Trust’s taxable year as a result of any technical termination may also result in more than twelve months of the Trust’s taxable income being includable in his or her taxable income for the year of termination. A technical termination would not affect the Trust’s classification as a partnership for U.S. federal income tax purposes, but instead, the Trust would be treated as a new partnership for tax purposes. If treated as a new partnership, the Trust must make new tax elections and could be subject to penalties if the Trust is unable to determine that a technical termination occurred.
Certain U.S. federal income tax preferences currently available with respect to oil and natural gas production may be eliminated as a result of future legislation.
The Obama administration’s budget proposals in recent years, including the budget proposal for fiscal year 2013, have included provisions eliminating certain key U.S. federal income tax incentives currently available to oil and gas exploration and production activities. If enacted into law, these provisions would eliminate certain tax preferences applicable to taxpayers engaged in the exploration and production of natural resources. These provisions include, but are not limited to (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for U.S. production activities and (iv) the increase in the amortization period from two years to seven years for geophysical costs paid or incurred in connection with the exploration for or development of, oil and gas within the United States. It is unclear whether any similar provisions will be included in future budget proposals, whether such provisions will actually be enacted or how soon any such provisions would become effective if enacted. The repeal of the percentage depletion allowance for oil and gas properties, including the Royalty Interests that are perpetual, could negatively impact the value of the Trust units as only cost depletion would be available.
Item 1B.
Item 1B. Unresolved Staff Comments
None.
Item 2.
Item 2. Properties
Information regarding the Trust’s properties is included in Item 1 of this report. Also, refer to Note 9 to the financial statements included in Item 8 of this report.
Item 3.
Item 3. Legal Proceedings
None.
Item 4.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
Item 5.
Item 5. Market for Common Units of the Trust, Related Unitholder Matters and Issuer Purchases of Common Units.
The Trust units commenced trading on the New York Stock Exchange (“NYSE”) on April 18, 2012, under the symbol “SDR.” Prior to April 18, 2012, there was no established public trading market for the Trust units. The range of high and low sales prices for the Trust’s common units for the periods indicated, as reported by the NYSE, and distributions per unit made by the Trust during the corresponding periods are as follows:
On March 8, 2013, there were four record unitholders of the Trust’s common units.
Distributions
The Trust makes quarterly cash distributions of substantially all of its cash receipts, after deducting amounts for the Trust’s administrative expenses and cash reserves withheld by the Trustee, on or about 60 days following the completion of each quarter.
Equity Compensation Plans
The Trust does not have any employees and, therefore, does not maintain any equity compensation plans.
Recent Sales of Unregistered Securities
None.
Purchases of Securities
There were no purchases of Trust units by the Trust or any affiliated purchaser during the fourth quarter of 2012.
Item 6.
Item 6. Selected Financial Data
Although the Trust was formed on December 13, 2011, the conveyance of the Royalty Interests did not occur until April 23, 2012, with an effective date of January 1, 2012, and no proceeds were received from SandRidge until May 2012. As a result, the Trust did not recognize any income or make any distributions during 2011 or the first calendar quarter of 2012. The information presented below should be read in conjunction with “Trustee’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7
Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations
Introduction
The following discussion and analysis is intended to help the reader understand the Trust’s business, financial condition, results of operations, liquidity and capital resources. This discussion and analysis should be read in conjunction with other sections of this report, including: “Business” in Item 1, “Selected Financial Data” in Item 6 and “Financial Statements and Supplementary Data” in Item 8. The discussion and analysis relate to the following subjects:
•
Results of Trust Operations
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Liquidity and Capital Resources
•
Critical Accounting Policies and Estimates
•
Off-Balance Sheet Arrangements
Results of Trust Operations
Results of the Trust for the Year Ended December 31, 2012
The primary factors affecting the Trust’s revenues and costs are the quantity of oil and natural gas production attributable to the Royalty Interests, the prices received for such production and amounts paid or received as net settlements under the derivatives agreement. Royalty income, post-production expenses, certain taxes and derivative settlements are recorded on a cash basis when net revenue distributions are received by the Trust from SandRidge. Although the Trust was formed on December 13, 2011, the conveyance of the Royalty Interests did not occur until April 23, 2012, with an effective date of January 1, 2012, and no proceeds were received from SandRidge until May 2012. As a result, the Trust did not recognize any income or make any distributions during 2011 or during the first calendar quarter of 2012. Information regarding the Trust’s revenues, expenses, production and pricing for the year ended December 31, 2012 is presented below.
(1) Oil and natural gas volumes and related revenues and expenses for the year ended December 31, 2012 (included in SandRidge’s 2012 net revenue distributions to the Trust) represent oil and natural gas production from January 1, 2012 to August 31, 2012.
(2) Includes natural gas liquids.
(3) Includes impact of derivative settlements attributable to production from April 1, 2012 to August 31, 2012.
Revenues
Royalty Income. Royalty income received during the year ended December 31, 2012 totaled $68.3 million based upon production attributable to the Royalty Interests of 636 MBbls of oil and 4,177 MMcf of natural gas for the period from January 1, 2012 to August 31, 2012. Average prices received for oil and natural gas production, excluding the impact of derivative settlements and post-production expenses, during the year ended December 31, 2012 were $89.35 per Bbl of oil and $2.75 per Mcf of natural gas.
Derivative Settlements. The Trust’s derivatives agreement with SandRidge reduces the Trust’s exposure to commodity price volatility attributable to a portion of production from the Royalty Interests through December 31, 2014 through the use of oil fixed price swaps. Net cash settlements received related to the Trust’s derivative contracts during the year ended December 31, 2012 were approximately $6.2 million, and included $5.6 million related to production attributable to the Royalty Interests from April 1, 2012 to August 31, 2012, which effectively increased the average price received for oil production for the related period by $8.79 per Bbl to $98.14 per Bbl. Additionally, during November 2012, the Trust received $0.6 million related to September 2012 production from the counterparty to the novated contracts. Derivative settlements related to September 2012 production were included in the Trust’s March 2013 quarterly distribution.
Expenses
Post-Production Expenses. The Trust bears post-production expenses attributable to production from the Royalty Interests. Post-production expenses generally consist of costs incurred to gather, store, compress, transport, process, treat, dehydrate and market the oil and natural gas produced. Post-production expenses for the year ended December 31, 2012 totaled approximately $2.4 million.
Property Taxes. Property taxes paid during the year ended December 31, 2012 totaled approximately $0.3 million.
Production Taxes. Production taxes are calculated as a percentage of oil and natural gas revenues, excluding the effects of derivative settlements and net of any applicable tax credits. Production taxes for the year ended December 31, 2012 totaled $1.0 million, or $0.73 per Boe, and were approximately 1.4% of royalty income.
Trust Administrative Expenses. Trust administrative expenses for the year ended December 31, 2012 totaled approximately $0.9 million.
Distributable Income
Distributable income for the year ended December 31, 2012 was $68.4 million, which included a net increase to the cash reserve for payment of future Trust expenses of approximately $1.5 million (approximately $2.7 million withheld from the 2012 cash distributions to unitholders less approximately $1.2 million used to pay Trust expenses during the period).
Liquidity and Capital Resources
The Trust’s principal sources of liquidity and capital are cash flow generated from the Royalty Interests and the Trust’s derivative contracts, and borrowings to fund administrative expenses, including any amounts borrowed under SandRidge’s loan commitment described in Note 5 to the financial statements contained in Part II,
Item 8 of this report. The Trust’s primary uses of cash are distributions to Trust unitholders, including, if applicable, incentive distributions to SandRidge, payment of amounts owed under the Trust’s derivative contracts, payment of Trust administrative expenses, including any reserves established by the Trustee for future liabilities, payment of applicable taxes and payment of expense reimbursements to SandRidge for out-of-pocket expenses incurred on behalf of the Trust. Under the conveyances granting the Royalty Interests, the Trust does not have any capital requirements related to drilling wells or any other operating and capital costs related to the wells.
Administrative expenses include payments to the Trustee and the Delaware Trustee as well as a quarterly fee of $75,000 to SandRidge pursuant to an administrative services agreement. Each quarter, the Trustee determines the amount of funds available for distribution. Available funds are the excess cash, if any, received by the Trust from the sale of oil and natural gas production attributable to the Royalty Interests that quarter, over the Trust’s expenses for the quarter, subject in all cases to the subordination and incentive provisions. If at any time the Trust’s cash on hand (including available cash reserves) is not sufficient to pay the Trust’s ordinary course administrative expenses as they become due, the Trust may borrow funds from the Trustee or other lenders, including SandRidge, to pay such expenses. The Trustee does not intend to lend funds to the Trust. If such funds are borrowed, no further distributions will be made to unitholders (except in respect of any previously determined quarterly distribution amount) until the borrowed funds have been repaid, except that if SandRidge loans such funds, SandRidge may permit the Trust to make distributions prior to SandRidge being repaid. There was no such loan outstanding at December 31, 2012 or December 31, 2011.
Under the derivatives agreement, SandRidge pays the Trust amounts it receives from its counterparties and the Trust pays SandRidge any amounts that SandRidge is required to pay such counterparties. Additionally, the Trust receives payment directly from its counterparties to the contracts novated to the Trust by SandRidge and is required to pay any amounts owed under those contracts directly to the counterparties. Significant payments by the Trust to SandRidge or to the counterparties for the novated contracts could reduce or eliminate distributions paid to unitholders.
Trust Distributions to Unitholders. During the year ended December 31, 2012, the Trust’s distributions to unitholders were as follows:
On March 1, 2013, the Trust paid a cash distribution of $0.532557 per unit covering production for the three-month period from September 1, 2012 to November 30, 2012. The distribution totaled $26.5 million and was made to record unitholders as of February 14, 2013.
Contractual Obligations
A summary of the Trust’s contractual obligations as of December 31, 2012 is provided in the following table:
Pursuant to the terms of the administrative services agreement with SandRidge, the Trust is obligated to pay SandRidge an annual administrative services fee of $300,000 for accounting, tax preparation, bookkeeping and informational services to be performed by SandRidge on behalf of the Trust throughout the life of the Trust. Pursuant to the trust agreement, the Trust is obligated to pay the Trustee an annual administrative fee of $150,000 until January 1, 2018 after which the fee will be adjusted annually for inflation by no more than plus or minus 3% in any one year through 2031 and the Trust is obligated to pay the Delaware Trustee an annual fee of $2,400, throughout the life of the Trust. Additionally, pursuant to the terms of the collateral agency agreement, the Trust pays an annual fee of $15,000 to the collateral agent through 2014.
Critical Accounting Policies and Estimates
The financial statements of the Trust are significantly affected by its basis of accounting and estimates related to the Royalty Interests and proved reserves, as summarized below.
Basis of Accounting. The financial statements of the Trust differ from financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) as the Trust records revenues when cash is received (rather than when earned) and expenses when paid (rather than when incurred) and may also establish certain cash reserves for contingencies, which would not be accrued in financial statements prepared in accordance with GAAP. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the SEC as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts. Amortization of investment in royalty interests, calculated on a unit-of-production basis, and any impairment are charged directly to trust corpus. Distributions to unitholders are recorded when declared. Because the Trust’s financial statements are prepared on a modified cash basis, most accounting pronouncements are not applicable to the Trust’s financial statements.
Oil and Natural Gas Reserves. The proved oil and natural gas reserves for the Royalty Interests are estimated by independent petroleum engineers. Estimates of proved reserves are based on the quantities of oil and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions, however, there are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, rates of production and timing of development expenditures, including many factors beyond the Trust’s control. Estimating reserves is very complex and relies on assumptions and subjective interpretations of available geologic, geophysical, engineering and production data, and the accuracy of reserve estimates is a function of the quality and quantity of available data, engineering and geological interpretation and judgment. In addition, as a result of volatility of changing market conditions, commodity prices will vary from period to period, causing estimates of proved reserves to vary, as well as causing estimates of future net revenues to vary. Estimates of proved reserves are key components of the Trust’s most significant financial estimates as discussed further below.
Amortization of Investment in Royalty Interests. Amortization of investment in royalty interests is calculated on a units-of-production basis, whereby the Trust’s cost basis is divided by the proved reserves attributable to the Royalty Interests to derive an amortization rate per reserve unit. The rate of recording amortization is dependent upon the estimate of total proved reserves for the Royalty Interests, which incorporates various assumptions and future projections. If the estimates of total proved reserves decline significantly, the rate at which the Trust records amortization would increase, reducing trust corpus. Such a decline in reserves may result from lower commodity prices, which may make it uneconomic for SandRidge to develop or produce the Underlying Properties. Changes in reserve quantity estimates are dependent on future economic and operational conditions and cannot be predicted.
Impairment of Investment in Royalty Interests. The investment in royalty interests is assessed to determine whether net capitalized cost is impaired whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Potential impairments of the investment in royalty interests are determined by comparing the net capitalized costs of investment in royalty interests to undiscounted future net revenues attributable to the Trust’s interest in the proved oil and natural gas reserves of the Underlying Properties. The Trust provides a write-down to the extent that the net capitalized costs exceed the fair value of the Royalty Interests, which is determined using net discounted future cash flows of the oil and natural gas reserves attributable to the Royalty Interests. Different pricing assumptions or discount rates could result in a different calculated impairment. Any such write-down would be charged directly to trust corpus and would not reduce distributable income. No impairments have been recorded as of December 31, 2012.
Refer to Note 1 to the financial statements included in Item 8 of this report for the Trust’s significant accounting policies.
Off-balance sheet arrangements
As of December 31, 2012, the Trust had no off-balance sheet arrangements.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
The discussion in this section provides information about commodity derivative contracts, certain benefits and obligations of which SandRidge has passed to the Trust pursuant to a derivatives agreement effective April 1, 2012. Under the derivatives agreement, SandRidge pays the Trust amounts it receives from counterparties under certain of its derivative contracts with third parties, and the Trust pays SandRidge any amounts that SandRidge is required to pay the counterparties under such derivative contracts. Concurrent with the execution of the derivatives agreement, SandRidge novated certain of the derivative contracts underlying the derivatives agreement to the Trust. As a party to these contracts, the Trust receives payment directly from the counterparties, and is required to pay any amounts owed directly to the counterparties. To secure its obligations under these novated contracts, the Trust entered into a collateral agency agreement and granted the counterparties a lien on the Royalty Interests. Under the collateral agency agreement, the Trust pays a $15,000 annual fee to the collateral agent. Under the derivatives agreement, as Trust Development Wells are drilled, SandRidge has the right, under certain circumstances, to assign or novate to the Trust additional derivative contracts. The commodity derivative contracts underlying the derivatives agreement are settled in cash and do not require the actual delivery of a commodity at settlement. Fixed price swap contracts are settled based upon “NYMEX” prices. The contracts underlying the derivatives agreement cover a portion of the anticipated future sales volumes of oil production from the Initial Wells as well as a portion of the anticipated future production from the Trust Development Wells through December 31, 2014. The Trust does not have the ability to enter into its own derivative contracts. See Note 6 to the financial statements contained in Item 8
Item 8. Financial Statements and Supplementary Data
The Trust’s financial statements required by this item are included in this report beginning on page.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A. Controls and Procedures
This annual report on Form 10-K does not include a report of the Trustee’s assessment regarding internal control over financial reporting or an attestation report of the Trust’s registered public accounting firm due to a transition period established by the rules of the SEC for newly public companies.
Evaluation of Disclosure Controls and Procedures. The Trustee conducted an evaluation of the Trust’s disclosure controls and procedures as defined in Rules 13a-15 and 15d-15 under the Securities Act designed to ensure that information required to be disclosed by the Trust in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Based on this evaluation, the Trustee has concluded that the disclosure controls and procedures of the Trust are effective as of the end of the period covered by this report. In its evaluation of disclosure controls and procedures, the Trustee has relied, to the extent considered reasonable, on information provided by SandRidge.
Due to the nature of the Trust as a passive entity and in light of the contractual arrangements pursuant to which the Trust was created, including the provisions of (i) the trust agreement, (ii) the administrative services agreement, (iii) the development agreement and (iv) the conveyances granting the Royalty Interests, the Trustee’s disclosure controls and procedures related to the Trust necessarily rely on (A) information provided by SandRidge, including information relating to results of operations, the status of drilling of the Trust Development Wells, the costs and revenues attributable to the Trust’s interests under the conveyance and other operating and historical data, plans for future operating and capital expenditures, reserve information, information relating to projected production, and other information relating to the status and results of operations of the Underlying Properties and the Royalty Interests, and (B) conclusions and reports regarding reserves by the Trust’s independent reserve engineers.
Changes in Internal Control over Financial Reporting. There were no changes in the Trust’s internal control over financial reporting during the quarter ended December 31, 2012 that have materially affected, or are reasonably likely to materially affect, the Trust’s internal control over financial reporting. The Trustee notes for purposes of clarification that it has no authority over, has not evaluated and makes no statement concerning, the internal control over financial reporting of SandRidge.
Item 9B.
Item 9B. Other Information
None.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
The Trust has no directors or executive officers. The Trustee is a corporate trustee that may be removed by the affirmative vote of the holders of not less than a majority of the outstanding Trust units, excluding Trust units held by SandRidge, at a special meeting of the Trust unitholders at which a quorum is present.
Section 16(a) Beneficial Ownership Reporting Compliance
The Trust has no directors or officers. Accordingly, only holders of more than 10% of the Trust’s units are required to file with the SEC initial reports of ownership of units and reports of changes in such ownership pursuant to Section 16 under the Securities Exchange Act of 1934. Based solely on a review of these reports, the Trustee is not aware of any person having failed to file on a timely basis the reports required by section 16(a) of the Exchange Act during the most recent fiscal year or prior fiscal years. In making this statement, the Trustee has relied upon examination of the copies of Forms 3, 4 and 5, to the extent there were any, provided to the Trust.
Audit Committee and Nominating Committee
Because the Trust does not have a board of directors, it does not have an audit committee, an audit committee financial expert or a nominating committee.
Code of Ethics
The Trust does not have a principal executive officer, principal financial officer, principal accounting officer or controller and, therefore, has not adopted a code of ethics applicable to such persons.
Item 11.
Item 11. Executive Compensation
During the year ended December 31, 2012, the Trustee and the Delaware Trustee received administrative fees from the Trust pursuant to the trust agreement. The Trust does not have any executive officers, directors or employees. Because the Trust does not have a board of directors, it does not have a compensation committee.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
(a) Security Ownership of Certain Beneficial Owners.
The following table sets forth certain information regarding the beneficial ownership of the Trust units as of March 8, 2013 by each person who, to the Trustee’s knowledge, beneficially owns more than 5% of the outstanding Trust units.
(1) All 7,393,750 common units and 12,431,250 subordinated units beneficially owned by SandRidge are held of record by its wholly owned subsidiary, SandRidge Exploration and Production, LLC.
At the end of the fourth full calendar quarter following SandRidge’s satisfaction of its drilling obligation to the Trust, the subordinated units will automatically convert into common units on a one-for-one basis. The subordinated units constitute 25% of the total number of units outstanding. As of March 8, 2013, SandRidge owned 39.9% of the total Trust units outstanding.
(b) Security Ownership of Management.
Not applicable.
(c) Changes in Control.
The registrant knows of no arrangement, including any pledge by any person of securities of the registrant or any of its parents, the operation of which may at a subsequent date result in a change of control of the registrant.
Item 13.
Item 13. Certain Relationships and Related Transactions and Director Independence
In conjunction with the conveyance of the Royalty Interests to the Trust, the Trust entered into the development agreement and the administrative services agreement with SandRidge and/or one of its wholly owned subsidiaries on April 23, 2012, effective January 1, 2012. Additionally, the Trust entered into the derivatives agreement with SandRidge on April 23, 2012, which was effective April 1, 2012, and the registration rights agreement with SandRidge. The Trust makes certain payments to SandRidge, the Trustee and the Delaware Trustee pursuant to the trust agreement, the administrative services agreement and the derivatives agreement. Descriptions of these agreements are included in the “-Business” section of Part 1, Item 1; in the “Trustee’s Discussion and Analysis of Financial Condition and Results of Operations” section of Part II, Item 7; and in Note 6 to the financial statements included in Item 8 of this report. In addition, the description of the initial public offering included in Part 1, Item 1 “- Business” of this report is hereby incorporated by reference.
Director Independence
The Trust does not have a board of directors. Further, the Trust relies on an exemption from the director independence requirements of the New York Stock Exchange set forth in Rule 10A-3(c)(7) under the Securities Exchange Act of 1934, applicable to listed issuers organized as trusts that do not have a board of directors.
Item 14.
Item 14. Principal Accounting Fees and Services
The Trust does not have an audit committee. Any pre-approval and approval of all services performed by the principal auditor or any other professional service firms and related fees are granted by the Trustee.
The following table presents fees for professional audit services rendered by PricewaterhouseCoopers LLP for the audit of the Trust’s financial statements for 2012 and fees billed for other services rendered by PricewaterhouseCoopers LLP. Because the Trust was formed on December 13, 2011, and the conveyance of the Royalty Interests did not occur until April 2012, there were no fees billed in 2011.
(1) Fees for audit services in 2012 consisted of the audit of the Trust’s annual financial statements and reviews of the Trust’s quarterly financial statements.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
The following documents are filed as a part of this report:
(1) Financial Statements
Reference is made to the Index to Financial Statements appearing on page.
(2) Financial Statement Schedules
All financial statement schedules have been omitted because they are not applicable or the required information is presented in the financial statements or notes thereto.
(3) Exhibits
Reference is made to the Exhibit Index.
INDEX TO FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm
To the Unitholders of SandRidge Mississippian Trust II and The Bank of New York Mellon Trust Company, N.A., Trustee:
We have audited the accompanying statement of assets and trust corpus of SandRidge Mississippian Trust II (the “Trust”) as of December 31, 2012, and the related statements of distributable income and of changes in trust corpus for the year then ended. These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
As described in Note 2, these financial statements were prepared on the modified cash basis of accounting, which is a comprehensive basis of accounting other than generally accepted accounting principles.
In our opinion, the financial statements referred to above present fairly, in all material respects, the assets and trust corpus of the Trust at December 31, 2012, and the distributable income and changes in trust corpus for the year then ended, on the basis of accounting described in Note 2.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Tulsa, Oklahoma
March 15, 2013
SANDRIDGE MISSISSIPIAN TRUST II
STATEMENTS OF ASSETS AND TRUST CORPUS
(In thousands, except unit data)
The accompanying notes are an integral part of these financial statements.
SANDRIDGE MISSISSIPIAN TRUST II
STATEMENT OF DISTRIBUTABLE INCOME
FOR THE YEAR ENDED DECEMBER 31, 2012
(In thousands, except unit and per unit data)
The accompanying notes are an integral part of these financial statements.
SANDRIDGE MISSISSIPIAN TRUST II
STATEMENT OF CHANGES IN TRUST CORPUS
FOR THE YEAR ENDED DECEMBER 31, 2012
(In thousands)
The accompanying notes are an integral part of these financial statements.
SANDRIDGE MISSISSIPIAN TRUST II
NOTES TO FINANCIAL STATEMENTS
1. Organization of the Trust
Nature of Business. SandRidge Mississippian Trust II (the “Trust”) is a statutory trust formed on December 13, 2011 under the Delaware Statutory Trust Act pursuant to a trust agreement by and among SandRidge Energy, Inc. (“SandRidge”), as Trustor, The Bank of New York Mellon Trust Company, N.A., as Trustee (the “Trustee”), and The Corporation Trust Company, as Delaware Trustee (the “Delaware Trustee”). The trust agreement was amended and restated by SandRidge, the Trustee and the Delaware Trustee on April 23, 2012. References in this report to the “trust agreement” are to the amended and restated trust agreement.
The Trust was created to acquire and hold Royalty Interests in specified oil and natural gas properties located in the Mississippian formation in Alfalfa, Grant, Kay, Noble and Woods counties in northern Oklahoma and Barber, Comanche, Harper and Sumner counties in southern Kansas (the “Underlying Properties”). The Royalty Interests were conveyed to the Trust by SandRidge in exchange for Trust common and subordinated units and the proceeds of the Trust’s initial public offering, described further below.
The Royalty Interests entitle the Trust to receive 80% of the proceeds (after deducting post-production costs and any applicable taxes) from the sale of oil, including natural gas liquids, and natural gas production attributable to SandRidge’s net revenue interest in 54 wells producing at December 31, 2011, and 13 additional wells awaiting completion at that time (together, the “Initial Wells”), and 70% of the proceeds (after deducting post-production costs and any applicable taxes) from the sale of oil, including natural gas liquids, and natural gas production attributable to SandRidge’s net revenue interest in 206 horizontal oil and natural gas development wells to be drilled (the “Trust Development Wells”) within an area of mutual interest (“AMI”) beginning on January 1, 2012, the effective date of the conveyance. Although the Trust was formed on December 13, 2011 the conveyance of the Royalty Interests did not occur until April 2012 and no proceeds from the sale of oil and natural gas production were received by the Trust until May 2012.
As specified in the development agreement executed by the Trust with SandRidge (see Note 6), SandRidge is credited for having drilled one full Trust Development Well if the well is drilled and perforated for completion with a perforated length between 3,500 feet and 4,500 feet within the Mississippian formation and SandRidge’s net revenue interest in the well is equal to 47.4%. SandRidge receives proportional credit for Trust Development Wells if the perforated length is less than 3,500 feet or greater than 4,500 feet, or if SandRidge’s net revenue interest is less than or greater than 47.4%. Accordingly, the actual number of wells required to be drilled may increase or decrease in proportion to SandRidge’s net revenue interest and the perforated length of each well. At December 31, 2012, these properties consisted of Royalty Interests in (a) the Initial Wells, (b) 89 additional wells (equivalent to approximately 107 Trust Development Wells under the development agreement as described in Note 6) that were drilled and perforated for completion between December 31, 2011 and December 31, 2012, and (c) the equivalent of approximately 99 Trust Development Wells to be drilled within the AMI.
The Trust is passive in nature and neither the Trust nor the Trustee has any control over, or responsibility for, costs relating to the operation of the Underlying Properties. The business and affairs of the Trust are administered by the Trustee. The trust agreement generally limits the Trust’s business activities to owning the Royalty Interests and entering into derivative contracts on a limited basis and activities reasonably related thereto, including activities required or permitted by the terms of the conveyances related to the Royalty Interests. The Trust is not responsible for any costs related to the drilling of the Trust Development Wells or any other operating or capital costs related to the Underlying Properties.
Initial Public Offering. Through an initial public offering in April 2012, the Trust sold 29,900,000 of its common units to the public for net proceeds, after payment of offering expenses, of approximately $590.2 million. The Trust delivered the net proceeds of the offering, which were further reduced by $3.1 million for a structuring fee paid to certain of the underwriters, along with 7,393,750 common units and 12,431,250
SANDRIDGE MISSISSIPIAN TRUST II
NOTES TO FINANCIAL STATEMENTS
subordinated units, to certain wholly owned subsidiaries of SandRidge, in exchange for the conveyance of the Royalty Interests to the Trust. Upon completion of these transactions and as of December 31, 2012, there were 49,725,000 Trust units, consisting of 37,293,750 common and 12,431,250 subordinated units, issued and outstanding. At December 31, 2012, SandRidge owned 7,393,750 Trust common units and 12,431,250 Trust subordinated units. The common and subordinated units have identical rights and privileges, except with respect to their rights to receive distributions as described below.
Distributions. The Trust makes quarterly cash distributions of substantially all of its cash receipts, after deducting amounts for the Trust’s administrative expenses, property taxes and cash reserves withheld by the Trustee, on or about 60 days following the completion of each quarter. Due to the timing of the payment of production proceeds to the Trust, each distribution covers production from a three-month period consisting of the first two months of the most recently ended quarter and the final month of the quarter preceding it. However, the Trust’s first distribution in May 2012 covered production for the two-month period from January 1, 2012 to February 29, 2012. Subsequent distributions cover a three-month period.
The Trust’s cash receipts with respect to the Royalty Interests in the Underlying Properties are determined after deducting post-production costs and any applicable taxes associated with the Royalty Interests. Post-production costs generally consist of costs incurred to gather, store, compress, transport, process, treat, dehydrate and market the oil and natural gas produced. The Trust’s distributable income is adjusted for amounts received and paid under the Trust’s derivative contracts, as discussed further in Note 6, and is reduced by the Trust’s cash reserves withheld by the Trustee and general and administrative expenses when paid.
The subordinated units, all of which are held by SandRidge, constitute 25% of the Trust units issued and outstanding. The subordinated units are entitled to receive pro rata distributions from the Trust each quarter if and to the extent there is sufficient cash to provide a cash distribution on the common units that is no less than 80% of the target distribution for the corresponding quarter (“Subordination Threshold”). If there is not sufficient cash to fund such a distribution on all of the common units, the distribution to be made with respect to the subordinated units is reduced or eliminated for such quarter in order to make a distribution, to the extent possible, of up to the Subordination Threshold amount on all of the common units. In exchange for agreeing to subordinate a portion of its Trust units, and in order to provide additional financial incentive to SandRidge to satisfy its drilling obligation, SandRidge is entitled to receive incentive distributions equal to 50% of the amount by which the cash available for distribution on all of the Trust units in any quarter exceeds 120% of the target distribution for such quarter (“Incentive Threshold”). At the end of the fourth full calendar quarter following SandRidge’s satisfaction of its drilling obligation with respect to the Trust Development Wells, the subordinated units will automatically convert into common units on a one-for-one basis and SandRidge’s right to receive incentive distributions will terminate. After such time, the common units will no longer have the protection of the Subordination Threshold, and all Trust unitholders will share on a pro rata basis in the Trust’s distributions.
Dissolution. The Trust will dissolve and begin to liquidate on December 31, 2031 (the “Termination Date”) and will soon thereafter wind up its affairs and terminate. At the Termination Date, 50% of the Royalty Interests will revert automatically to SandRidge. The remaining 50% of the Royalty Interests will be retained by the Trust at the Termination Date and thereafter sold, with the net proceeds of the sale, as well as any remaining Trust cash reserves, distributed to the unitholders on a pro rata basis. SandRidge has a right of first refusal to purchase the Royalty Interests retained by the Trust at the Termination Date.
2. Significant Accounting Policies
Basis of Accounting. The financial statements of the Trust differ from financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) as the Trust records revenues when cash is received (rather than when earned) and expenses when paid (rather than when
SANDRIDGE MISSISSIPIAN TRUST II
NOTES TO FINANCIAL STATEMENTS
incurred) and may also establish certain cash reserves for contingencies, which would not be accrued in financial statements prepared in accordance with GAAP. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the Securities and Exchange Commission (“SEC”) as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts. Amortization of investment in royalty interests, calculated on a unit-of-production basis, and any impairments are charged directly to trust corpus. Distributions to unitholders are recorded when declared.
Significant Accounting Policies. Most accounting pronouncements apply to entities whose financial statements are prepared in accordance with GAAP, directing such entities to accrue or defer revenues and expenses in a period other than when such revenues are received or expenses are paid. Because the Trust’s financial statements are prepared on the modified cash basis as described above, most accounting pronouncements are not applicable to the Trust’s financial statements.
Use of Estimates. The preparation of financial statements requires the Trust to make estimates and assumptions that affect the reported amounts of assets and trust corpus and the reported amounts of revenues and expenses during the reporting period. Significant estimates that impact the Trust’s financial statements include estimates of proved oil and natural gas reserves, which are used to compute the Trust’s amortization of investment in royalty interests and, as necessary, to evaluate potential impairment of its investment in royalty interests. Actual results could differ from those estimates.
Risks and Uncertainties. The Trust’s revenue and distributions are substantially dependent upon the prevailing and future prices for oil and natural gas, each of which depends on numerous factors beyond the Trust’s control such as overall oil and natural gas production and inventories in relevant markets, economic conditions, the global political environment, regulatory developments and competition from other energy sources. Oil and natural gas prices historically have been volatile, and may be subject to significant fluctuations in the future. The Trust’s derivative arrangements serve to mitigate a portion of the effect of this price volatility. See Note 6 for a discussion of the Trust’s open oil commodity derivative contracts.
Cash and Cash Equivalents. Cash and cash equivalents consist of all highly-liquid instruments with original maturities of three months or less.
Investment in Royalty Interests. The conveyance of the Royalty Interests to the Trust in April 2012 was accounted for as a transfer of properties between entities under common control and recorded at SandRidge’s historical cost, or $467.1 million, which was determined by allocating the historical net book value of SandRidge’s full cost pool based on the fair value of the Royalty Interests relative to the fair value of SandRidge’s full cost pool. The carrying value of the Trust’s investment in royalty interests is not necessarily indicative of the fair value of such Royalty Interests.
Significant dispositions or abandonments of the Underlying Properties are charged to investment in royalty interests and the trust corpus. Amortization of investment in royalty interests is calculated on a units-of-production basis, whereby the Trust’s cost basis is divided by the proved reserves attributable to the Royalty Interests to derive an amortization rate per reserve unit. Amortization is recorded when units are produced. Such amortization does not reduce distributable income, rather it is charged directly to trust corpus. Revisions to estimated future units-of-production are treated on a prospective basis beginning on the date significant revisions are known.
The investment in royalty interests is assessed to determine whether net capitalized cost is impaired whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If an assessment is necessary, an impairment would be indicated when the net capitalized costs of investment in
SANDRIDGE MISSISSIPIAN TRUST II
NOTES TO FINANCIAL STATEMENTS
royalty interests exceeds undiscounted future net revenues attributable to the Trust’s interest in the proved oil and natural gas reserves of the Underlying Properties. The Trust will provide a write-down to the extent that the net capitalized costs exceed the fair value of the proved oil and natural gas reserves attributable to the Royalty Interests. Any such write-down would be charged directly to trust corpus and would not reduce distributable income. No impairments have been recorded as of December 31, 2012.
Derivative Financial Instruments. The Trust entered into a derivatives agreement with SandRidge to manage risks related to oil and natural gas price volatility. See Note 6. The Trust uses the cash method to account for derivative instruments, under which it records benefits or obligations from derivative contracts when such benefits are received or obligations are paid. The fair market values and changes in the fair market value of the derivative contracts are not included in the accompanying financial statements as the statements are presented on a modified cash basis. Net cash settlements received related to the Trust’s derivative contracts during the year ended December 31, 2012 were approximately $6.2 million, and included $5.6 million related to production attributable to the Royalty Interests from April 1, 2012 to August 31, 2012. Additionally, during November 2012, the Trust received $0.6 million related to September 2012 production from the counterparty to the novated contracts. Net settlements received during 2012 related to September 2012 production were included in the Trust’s March 2013 distribution. See Note 8 for further discussion of the March 2013 distribution.
Revenue and Expenses. Revenues received by the Trust are net of gathering and post-production expenses and production taxes in order to determine distributable income. The Trust’s distributable income is adjusted for amounts received or paid under the derivatives agreement and is reduced by cash reserves withheld by the Trustee and other allowable costs such as general and administrative expenses, when paid. The Royalty Interests are not burdened by field and lease operating expenses.
Concentration of Risk. The Trust maintains cash balances at one financial institution. Accounts at each institution are insured by the Federal Deposit Insurance Corporation up to $250,000. From time to time, the Trust may have balances in these accounts that exceed the federally insured limit. The Trust does not anticipate any loss associated with balances exceeding the federally insured limit.
The use of hedging transactions involves the risk that the counterparties may be unable to meet the financial terms of the transactions. The counterparties to the contracts novated to the Trust by SandRidge have an “investment grade” credit rating. SandRidge, on behalf of the Trust, monitors on an ongoing basis the credit rating of the hedging counterparties. The Trust has a master netting agreement with its derivative contract counterparties, which allows the Trust to net amounts due from and owed to the same counterparty. As a result of the netting provision, the Trust’s maximum amount of loss under the hedging transaction due to credit risk is limited to the net amount due from the counterparties under the derivatives. As of December 31, 2012, the counterparties to the contracts novated to the Trust by SandRidge consisted of two financial institutions. The Trust is not required to post additional collateral under the derivative contract.
3. Income Taxes
The Trust is treated for federal and applicable state income tax purposes as a partnership. For U.S. federal income tax purposes, a partnership is not a taxable entity and incurs no U.S. federal income tax liability. With respect to state taxation, a partnership is typically treated in the same manner as it is for U.S. federal income tax purposes.
SANDRIDGE MISSISSIPIAN TRUST II
NOTES TO FINANCIAL STATEMENTS
4. Distributions to Unitholders
The Trust makes quarterly cash distributions of substantially all of its cash receipts, after deducting amounts for the Trust’s administrative expenses, property taxes and cash reserves withheld by the Trustee, on or about 60 days following the completion of each quarter. Other than the first distribution, which covered production for the two-month period from January 1, 2012 to February 29, 2012, distributions cover a three-month period. A summary of the Trust’s distributions to unitholders is as follows:
On March 1, 2013, the Trust paid a cash distribution covering production for the period from September 1, 2012 to November 30, 2012. See Note 8 for further discussion.
5. Loan Commitment
Pursuant to the trust agreement, if at any time the Trust’s cash on hand (including available cash reserves) is not sufficient to pay the Trust’s ordinary course administrative expenses as they become due, SandRidge will loan funds to the Trust necessary to pay such expenses. Any funds loaned by SandRidge pursuant to this commitment will be limited to the payment of current accounts payable or other obligations to trade creditors in connection with obtaining goods or services or the payment of other accrued current liabilities arising in the ordinary course of the Trust’s business, and may not be used to satisfy Trust indebtedness, or to make distributions. If SandRidge loans funds pursuant to this commitment, unless SandRidge agrees otherwise, no further distributions will be made to unitholders (except in respect of any previously determined quarterly cash distribution amount) until such loan is repaid. Any such loan will be on an unsecured basis, and the terms of such loan will be substantially the same as those which would be obtained in an arm’s length transaction between SandRidge and an unaffiliated third party. There was no such loan outstanding with SandRidge at December 31, 2012 or 2011.
6. Related Party Transactions
Trustee Administrative Fee. Under the terms of the trust agreement, the Trust pays an annual administrative fee of $150,000 to the Trustee, which will be adjusted for inflation by no more than 3% in any year, beginning in 2018. The Trustee waived its administrative fee for the first quarter of 2012. During 2012, the Trust paid the Trustee’s and the Delaware Trustee’s legal expenses incurred in forming the Trust of approximately $100,000, as well as the Trustee’s acceptance fee in the amount of $10,000. The Trustee’s administrative fees paid, including the acceptance fee, during the year ended December 31, 2012 were approximately $123,000.
Registration Rights Agreement. On April 23, 2012, the Trust entered into a registration rights agreement pursuant to which the Trust has agreed to register the offering of the Trust units held by SandRidge and certain of its affiliates and permitted transferees upon request by SandRidge.
SANDRIDGE MISSISSIPIAN TRUST II
NOTES TO FINANCIAL STATEMENTS
Development Agreement. On April 23, 2012, the Trust entered into a development agreement with SandRidge, effective January 1, 2012, that obligates SandRidge to drill, or cause to be drilled, the Trust Development Wells by December 31, 2016. Additionally, SandRidge agreed not to drill and complete, or allow another person within its control to drill and complete, any other well in the AMI other than the Trust Development Wells until SandRidge has fulfilled its drilling obligation.
A wholly owned subsidiary of SandRidge granted to the Trust a lien (“Drilling Support Lien”) covering its interest in the AMI (except its interest in the Initial Wells) in order to secure the estimated amount of the drilling costs for the Trust’s interests in the undeveloped Underlying Properties. The initial amount recoverable by the Trust pursuant to the Drilling Support Lien could not exceed approximately $269.1 million, subject to adjustment as described below. As SandRidge fulfills its drilling obligation over time, the total amount that may be recovered will be reduced proportionately, once SandRidge has completed 103 Trust Development Wells, as each of the remaining Trust Development Wells is drilled. If SandRidge does not fulfill its drilling obligation by December 31, 2016, the Trust may foreclose on any remaining interest in the AMI that is subject to the Drilling Support Lien. Any amounts actually recovered in a foreclosure action would be applied to the completion of SandRidge’s drilling obligation and would not result in a distribution to the Trust’s unitholders. As of December 31, 2012, SandRidge had drilled and perforated for completion approximately 107 equivalent Trust Development Wells and the maximum amount potentially recoverable under the Drilling Support Lien had been reduced to approximately $258.2 million.
Administrative Services Agreement. On April 23, 2012, the Trust entered into an administrative services agreement with SandRidge, effective January 1, 2012, that obligates the Trust to pay SandRidge an annual administrative services fee for accounting, tax preparation, bookkeeping and informational services to be performed by SandRidge on behalf of the Trust. Additionally, the administrative services agreement designates SandRidge as the Trust’s hedge manager, pursuant to which SandRidge has authority to administer the derivatives contracts underlying the derivatives agreement (described below), and, on behalf of the Trust, to administer the Trust’s derivative contracts with unaffiliated third parties. For its services under the administrative services agreement, SandRidge receives an annual fee of $300,000, which is payable in equal quarterly installments and will remain fixed for the life of the Trust. SandRidge is also entitled to receive reimbursement for its out-of-pocket fees, costs and expenses incurred in connection with the provision of any of the services under this agreement. The administrative services agreement will terminate on the earliest to occur of: (i) the date the Trust shall have dissolved and commenced winding up in accordance with the trust agreement, (ii) the date that all of the Royalty Interests have been terminated or are no longer held by the Trust, (iii) pertaining to services to be provided with respect to any Underlying Properties transferred by SandRidge, the date that either SandRidge or the Trustee may designate by delivering 90-days’ prior written notice, provided that SandRidge’s drilling obligation has been completed and the transferee of such Underlying Properties assumes responsibility to perform the services in place of SandRidge and (iv) a date mutually agreed to by SandRidge and the Trustee. SandRidge agreed to waive its administrative services fee for the first quarter of 2012. During the year ended December 31, 2012, the Trust paid $150,000 to SandRidge for administrative service fees.
Derivatives Agreement. On April 23, 2012, the Trust entered into a derivatives agreement with SandRidge, effective April 1, 2012, that provides the Trust with the economic effect of certain derivative contracts previously entered into by SandRidge with third parties. Under the derivatives agreement, SandRidge pays the Trust amounts it receives from its counterparties and the Trust pays SandRidge any amounts that SandRidge is required to pay such counterparties. Substantially concurrent with the execution of the derivatives agreement, SandRidge novated certain of the derivative contracts underlying the derivatives agreement to the Trust. As a party to these contracts, the Trust receives payment directly from the counterparties, and is required to pay any amounts owed directly to the counterparties. To secure its obligations under these novated contracts, the Trust entered into a collateral agency agreement and granted the counterparties a lien on the Royalty Interests. Under the collateral
SANDRIDGE MISSISSIPIAN TRUST II
NOTES TO FINANCIAL STATEMENTS
agency agreement, the Trust pays a $15,000 annual fee to the collateral agent. Under the derivatives agreement, as Trust Development Wells are drilled, SandRidge has the right, under certain circumstances, to assign or novate to the Trust additional derivative contracts. The Trust’s derivative contracts consist of fixed price swaps.
The following tables present, as of December 31, 2012, the notional amount and weighted average fixed price of the open contracts underlying the derivatives agreement and the contracts that have been novated to the Trust. The combined volume in the tables below reflects the total volume of oil derivative contracts for the Trust.
Oil Contracts Underlying the Derivatives Agreement
Oil Contracts Underlying the Derivatives Agreement and Novated to the Trust
7. Major Customers
For the year ended December 31, 2012, sales of production attributable to the Royalty Interests exceeding 10% of the Trust’s total revenues were made to the following oil or natural gas purchasers:
SANDRIDGE MISSISSIPIAN TRUST II
NOTES TO FINANCIAL STATEMENTS
8. Subsequent Events
On January 31, 2013, the Trust declared a cash distribution of $0.532557 per unit covering production for the three-month period from September 1, 2012 to November 30, 2012 for record unitholders as of February 14, 2013. The distribution was paid on March 1, 2013. Distributable income for September 1, 2012 to November 30, 2012 was calculated as follows (in thousands, except for unit and per unit amounts):
(1) Includes amounts withheld for payment of future Trust administrative expenses.
During March 2013, SandRidge novated certain additional portions of the derivative contracts underlying the derivatives agreement to the Trust.
9. Supplemental Information on Oil and Natural Gas Producing Activities
The following supplemental information includes capitalized costs related to oil and natural gas producing activities; costs incurred in oil and natural gas property acquisition, exploration and development; and the results of operations for oil and natural gas producing activities. Supplemental information is also provided for oil and natural gas production and average sales prices; the estimated quantities of proved oil and natural gas reserves; the standardized measure of discounted future net cash flows associated with proved oil and natural gas reserves; and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved oil and natural gas reserves. This supplemental information was prepared on an accrual basis, which is the basis upon which SandRidge and the Underlying Properties maintain their records and is different from the modified cash basis on which the Trust financial statements are prepared. A reconciliation of information presented on the modified cash basis to the accrual basis for the year ended December 31, 2012 is as follows:
SANDRIDGE MISSISSIPIAN TRUST II
NOTES TO FINANCIAL STATEMENTS
(1) Oil and natural gas volumes attributable to the Royalty Interests and related revenues and expenses included in SandRidge’s 2012 net revenue distributions to the Trust. Represents oil and natural gas production from January 1, 2012 to August 31, 2012.
(2) Oil and natural gas volumes attributable to the Royalty Interests and related revenues and expenses, presented on an accrual basis, from the date of conveyance, April 23, 2012, through December 31, 2012.
(3) Includes natural gas liquids.
Capitalized Costs Related to Oil and Natural Gas Producing Activities
The Trust’s capitalized costs consisted of the following at December 31, 2012 (in thousands):
(1) The Trust was formed in 2011; however, the Royalty Interests were not conveyed to the Trust by SandRidge until 2012. As such, there were no capitalized costs related to oil and natural gas producing activities at December 31, 2011.
(2) Royalty Interests conveyed to the Trust by SandRidge in April 2012 were in both proved and unproved locations; however, by December 31, 2012, all Trust Royalty Interests had associated proved reserves.
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development
The conveyance of the Royalty Interests was accounted for as a transfer of properties between entities under common control and recorded by the Trust at SandRidge’s historical cost, which was $467.1 million. The Trust delivered the net proceeds of its initial public offering, or $590.2 million, along with 7,393,750 common units and 12,431,250 subordinated units, to certain wholly owned subsidiaries of SandRidge in exchange for the conveyance of the Royalty Interests to the Trust in April 2012. The Trust is not responsible for any costs incurred to drill the Trust Development Wells. As such, the Trust did not incur any costs in the exploration or development of oil and natural gas properties during the year ended December 31, 2012.
Results of Operations for Oil and Natural Gas Producing Activities (Unaudited)
The Trust’s results of operations from oil and natural gas producing activities for the year ended December 31, 2012 are shown in the following table (in thousands):
SANDRIDGE MISSISSIPIAN TRUST II
NOTES TO FINANCIAL STATEMENTS
(1) Oil and natural gas revenues and post-production costs attributable to volumes produced from April 23, 2012, the date of conveyance, to December 31, 2012, regardless of whether proceeds from the sale of production have been remitted to the Trust by SandRidge.
(2) The Trust does not bear any well operating costs and is not subject to federal or state income taxes.
(3) Amortization is recorded by the Trust as volumes are produced and does not reduce distributable income, but rather, is recorded directly to trust corpus
Oil and Natural Gas Reserve Quantities (Unaudited)
Proved oil and natural gas reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, based on prices used to estimate reserves, from a given date forward from known reservoirs, and under existing economic conditions, operating methods, and government regulation before the time of which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Proved developed reserves are proved reserves expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively large major expenditure is required for recompletion.
Netherland Sewell, independent oil and natural gas consultants, prepared the estimates of proved reserves of oil and natural gas attributable to the Royalty Interests as of December 31, 2012. Netherland Sewell are independent petroleum engineers, geologists, geophysicists and petrophysicists and do not own an interest in the Trust or its properties and are not employed on a contingent basis.
The Trustee believes the geoscience and engineering data examined provides reasonable assurance that the proved reserves are economically producible in future years from known reservoirs, and under existing economic conditions, operating methods and governmental regulations. Estimates of proved reserves are subject to change, either positively or negatively, as additional information is available and contractual and economic conditions change.
The table below represents the estimate of proved oil and natural gas reserves attributable to the Trust’s net interest in oil and natural gas properties, all of which are located in the continental United States, based upon the evaluation by the Trustee and its independent petroleum engineers of pertinent geoscience and engineering data in accordance with the SEC’s regulations. Estimates of the Trust’s proved reserves have been prepared by independent reservoir engineers and geoscience professionals and are reviewed by members of the SandRidge’s senior management with professional training in petroleum engineering to ensure that rigorous professional standards and the reserve definitions prescribed by the SEC are consistently applied.
SANDRIDGE MISSISSIPIAN TRUST II
NOTES TO FINANCIAL STATEMENTS
The summary below presents changes in the Trust’s estimated reserves during the year ended December 31, 2012.
(1) Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.
(2) Volumes produced from April 23, 2012, the date of Royalty Interest conveyance, to December 31, 2012, regardless of whether proceeds from the sale of such production have been remitted to the Trust by SandRidge.
(3) Estimated proved reserves were determined using a 12-month average price for oil and natural gas.
During the period from April 23, 2012, the date of the Royalty Interests conveyance, to December 31, 2012, the Trust recognized net reductions to reserves associated with proved properties in the AMI of approximately 5,618.5 MBoe as a result of negative revisions due to pricing and well performance as additional information was obtained through the continued horizontal development of and production from the Mississippian formation during the period. Additionally, approximately 6,484.0 MBoe were converted from probable reserves to proved reserves (approximately 2,851.4 MBoe of proved developed and 3,632.6 MBoe of proved undeveloped) during the same period through the drilling by SandRidge of 45 Trust Development Wells. Of the remaining Trust Development Wells drilled during 2012, 37 converted proved undeveloped reserves to proved developed reserves and one converted proved developed non-producing reserves to proved developed producing reserves.
Standardized Measure of Discounted Future Net Cash Flows (Unaudited)
The assumptions underlying the computation of the standardized measure of discounted cash flows are summarized as follows:
•
the standardized measure includes estimates of proved oil and natural gas reserves and projected future production volumes based upon economic conditions;
•
pricing is applied based upon 12-month average market prices at December 31, 2012. The calculated weighted average per unit prices for the Trust’s proved reserves and future net revenues were $90.57 per barrel of oil and $2.24 per Mcf of natural gas; and
•
a discount factor of 10% per year is applied annually to the future net cash flows.
SANDRIDGE MISSISSIPIAN TRUST II
NOTES TO FINANCIAL STATEMENTS
The summary below presents the Trust’s future net cash flows relating to proved oil and natural gas reserves at December 31, 2012 based on the standardized measure in ASC Topic 932 (in thousands).
(1) Includes the Trust’s proportionate share of production taxes and post-production costs. The Trust does not bear any development or operational costs related to wells.
(2) The Trust is not subject to federal or state income taxes.
The following table represents the Trust’s estimate of changes in the standardized measure of discounted future net cash flows from proved reserves during the year ended December 31, 2012 (in thousands):
Changes in the Standardized Measure of Discounted Future Net Cash Flows
Associated with Proved Oil and Natural Gas Reserves
(1) Changes in timing differences and other are related to revisions in the estimated timing of production and development.
10. Quarterly Financial Results (Unaudited)
The Trust’s operating results for each calendar quarter of 2012 is summarized below (in thousands, except per unit data).
(1) Includes proceeds attributable to production from the Royalty Interests from January 1, 2012 to February 29, 2012.
(2) Includes proceeds attributable to production from the Royalty Interests from March 1, 2012 to May 31, 2012.
(3) Includes proceeds attributable to production from the Royalty Interests from June 1, 2012 to August 31, 2012.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
SANDRIDGE MISSISSIPPIAN TRUST II
By
The Bank of New York Mellon
Trust Company, N.A., Trustee
By
/s/ Michael J. Ulrich
Michael J. Ulrich
Vice President
March 15, 2013
The Registrant, SandRidge Mississippian Trust II, has no principal executive officer, principal financial officer, board of directors or persons performing similar functions. Accordingly, no additional signatures are available, and none have been provided. In signing the report above, the Trustee does not imply that it has performed any such function or that any such function exists pursuant to the terms of the trust agreement under which it serves.
EXHIBIT INDEX