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SANDRIDGE PERMIAN TRUST - 10-K - Trustee's Discussion and Analysis of Financial Condition and Results of Operations

February 28, 2014

Introduction

The following discussion and analysis is intended to help the reader understand the Trust's business, financial condition, results of operations, liquidity and capital resources. This discussion and analysis should be read in conjunction with other sections of this report, including: "Business" in Item 1, "Selected Financial Data" in Item 6 and "Financial Statements and Supplementary Data" in Item 8. The discussion and analysis relate to the following subjects: Results of Trust Operations Liquidity and Capital Resources Critical Accounting Policies and Estimates Off-Balance Sheet Arrangements



Results of Trust Operations

Results of the Trust for the Years EndedDecember 31, 2013, 2012 and 2011

The primary factors affecting the Trust's revenues and costs are the quantity of oil, NGLs 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 and net derivative settlements are received from the Trust's derivative counterparties. Information regarding the Trust's revenues, expenses, production and pricing for the years ended December 31, 2013, 2012 and 2011, is presented below. Year Ended December 31, 2013(1) 2012(2) 2011(3) Production data Oil (MBbl) 1,306 1,321 408 NGL (MBbls) 136 140 45 Natural gas (MMcf) 387 390 120 Combined equivalent volumes (MBoe) 1,507 1,526



473

Average daily combined equivalent volumes (MBoe/d) 4.1 4.2



3.1

Well data Initial and Trust Development Wells producing - average 896 717 515 Revenues (in thousands) Royalty income $ 122,256$ 126,464$ 40,795 Derivative settlements 8,934 6,840 1,835 Total revenue $ 131,190$ 133,304$ 42,630 Expenses (in thousands) Post-production expenses $ 115$ 117$ 22 Property taxes 2,231 571 225 Production taxes 5,735 6,008 1,959 Franchise taxes 442 155 - Trust administrative expenses 1,433 1,528



666

Cash reserves withheld for current Trust expenses, net of amounts used 564 2,548



1,139

Total expenses $ 10,520$ 10,927 $



4,011

Distributable income available to unitholders $ 120,670$ 122,377$ 38,619 38

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Table of Contents Year Ended December 31, 2013(1) 2012(2) 2011(3) Average prices Oil (per Bbl) $ 89.39$ 90.68$ 93.38 NGL (per Bbl) $ 32.21$ 41.32$ 50.85 Combined oil and NGL (per Bbl) $ 83.99$ 85.94$ 89.13 Natural gas (per Mcf) $ 2.88$ 2.30$ 3.44 Combined equivalent (per Boe) $ 81.14$ 82.87



$ 86.24

Average prices - including impact of derivative settlements and post-production expenses Oil (per Bbl)(4) $ 96.77$ 96.01$ 96.23 NGL (per Bbl) $ 32.21$ 41.32$ 50.85 Combined oil and NGL (per Bbl) $ 90.68$ 90.76$ 91.70 Natural gas (per Mcf) $ 2.58$ 2.00$ 3.25 Combined equivalent (per Boe) $ 87.46$ 87.41$ 88.65 Expenses (per Boe) Post-production $ 0.08$ 0.08$ 0.05 Production taxes $ 3.81$ 3.94$ 4.14

-------------------------------------------------------------------------------- (1) Production volumes and related revenues and expenses for the



year

ended December 31, 2013 (included in SandRidge's 2013 net revenue distributions to the Trust) represent oil and natural gas production from September 1, 2012 to August 31, 2013. (2) Production volumes and related revenues and expenses for the



year

ended December 31, 2012 (included in SandRidge's 2012 net revenue distributions to the Trust) represent oil and natural gas production from September 1, 2011 to August 31, 2012. (3) Production volumes and related revenues and expenses for the



year

ended December 31, 2011 (included in SandRidge's 2011 net revenue distribution to the Trust) represent oil and natural gas production from April 1, 2011 to August 31, 2011. (4) Includes impact of derivative settlements attributable to production from September 1, 2012 to August 31, 2013 for the year ended December 31, 2013, from September 1, 2011 to August 31, 2012 for the year ended December 31, 2012 and from April 1, 2011 to August 31, 2011 for the year ended December 31, 2011.



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

Revenues Royalty Income. Royalty income received during the year ended December 31, 2013 totaled $122.3 million compared to $126.5 million received during the year ended December 31, 2012. The decrease in royalty income was primarily attributable to a decrease in the combined average price received for oil and NGL production, excluding the impact of derivative settlements and post-production expenses, to $83.99 per Bbl during the year ended December 31, 2013 from $85.94 per Bbl during the year ended December 31, 2012. Also contributing to the decrease in royalty income was a decrease in equivalent volumes produced as production from Trust Development Wells completed and brought on production during 2013 was more than offset by natural declines in production from the Initial Wells and older Trust Development Wells. Net revenue distributions received from SandRidge by the Trust during the year ended December 31, 2013 included royalty income attributable to production for the twelve-month period from September 1, 2012 to August 31, 2013 of 1,442 MBbls of oil and NGLs and 387 MMcf of natural gas. The net revenue distributions received from SandRidge by the Trust during the year ended December 31, 2012 included royalty income attributable to production for the twelve-month period from September 1, 2011 to August 31, 2012 of 1,461 MBbls of oil and NGLs and 390 MMcf of natural gas. The decreases in the average prices received for oil and NGL production and total production were slightly offset by an increase in the average price received for natural gas production, excluding the impact of derivative settlements and post-production expenses, to $2.88 per Mcf during the year ended December 31, 2013 from $2.30 per Mcf during the year ended December 31, 2012. Derivative Settlements. The Trust's derivatives contracts are intended to reduce the Trust's exposure to commodity price volatility attributable to a portion of production from the Royalty Interests through March 31, 2015 through the use of oil fixed price swaps. Net cash settlements received related to the Trust's derivative contracts during the year ended December 31, 2013 were approximately $8.9 million, and included (i) approximately $3.8 million received related to the conveyed contracts for production attributable to the Royalty Interests from September 1, 2012 to August 31, 2013, (ii) approximately $5.4 million received from the counterparty to the novated contracts for production attributable to the Royalty Interests from October 1, 2012 to August 31, 2013 and (iii) approximately $0.3 million paid to the counterparty related to the novated contracts for September 2013 production. Total net derivative settlements received by the Trust for production from September 1, 2012 to August 31, 2013 were $9.7 million, including 39

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$0.5 million received in 2012 from the counterparty to the novated contracts, which effectively increased the average price received for oil production for the related period by $7.38 per Bbl to $96.77 per Bbl. The effects of net settlements paid during 2013 related to September 2013 production were included in the Trust's February 2014 distribution. Net cash settlements received related to the Trust's derivative contracts during the year ended December 31, 2012 were approximately $6.8 million, and included (i) approximately $2.2 million received related to the conveyed contracts for production attributable to the Royalty Interests from September 1, 2011 to August 31, 2012, (ii) approximately $4.1 million received from the counterparty to the novated contracts for production attributable to the Royalty Interests from October 1, 2011 to August 31, 2012 and (iii) approximately $0.5 million received from the counterparty to the novated contracts for September 2012 production. Total net derivative settlements received by the Trust for production from September 1, 2011 to August 31, 2012 were $7.0 million, including $0.7 million received in 2011 from the counterparty to the novated contracts, which effectively increased the average price received for oil production for the related period by $5.33 per Bbl to $96.01 per Bbl. Derivative settlements related to September 2012 production were included in the Trust's March 2013 quarterly distribution. Net settlements received during 2013 and 2012 were due to lower commodity prices at the time of settlement compared to the contract price of the Trust's oil fixed price swaps. Expenses Post-Production Expenses. The Trust bears post-production expenses attributable to production from the Royalty Interests. Post-production expenses generally consist of costs incurred to gather, store, compress, transport, process, treat, dehydrate and market the oil and natural gas produced. Post-production expenses for the year ended December 31, 2013 totaled approximately $115,000 compared to approximately $117,000 for the year ended December 31, 2012. Property Taxes. Property taxes paid during the year ended December 31, 2013 totaled approximately $2.2 million compared to approximately $0.6 million for the year ended December 31, 2012. The total payment made related to 2013 property taxes was $0.4 million (paid in October 2013) compared to approximately $2.2 million in payments made related to 2012 property taxes ($0.4 million paid in October 2012 and $1.8 paid in January 2013). The Trust's estimated remaining 2013 property tax liability of approximately $1.9 million will be paid during 2014. The change in total estimated property tax incurred attributable to calendar year 2013 relates to several factors including changes in the producing reserves associated with the Royalty Interests and changes in commodity prices used to value the associated reserves. Production Taxes. Production taxes are calculated as a percentage of oil and natural gas revenues, excluding the effects of derivative settlements and net of any applicable tax credits. Production taxes for the year ended December 31, 2013 totaled $5.7 million, or $3.81 per Boe, and were approximately 4.7% of royalty income. Production taxes for the year ended December 31, 2012 totaled $6.0 million, or $3.94 per Boe, and were approximately 4.8% of royalty income. Texas Franchise Tax. The Trust paid its Texas franchise tax for the year ended December 31, 2012 of approximately $0.4 million, or approximately 0.4% of 2012 royalty income, during the year ended December 31, 2013. The Trust paid its Texas franchise tax for the year ended December 31, 2011 of approximately $0.2 million, or approximately 0.4% of 2011 royalty income, during the year ended December 31, 2012. The Trust's estimated Texas franchise tax for the year ended December 31, 2013 of approximately $0.4 million, or approximately 0.4% of 2013 royalty income, will be paid during the year ending December 31, 2014. Trust Administrative Expenses. Trust administrative expenses for the year ended December 31, 2013 totaled approximately $1.4 million compared to approximately $1.5 million for the year ended December 31, 2012. Distributable Income Distributable income for the year ended December 31, 2013 was $120.7 million, which included a net addition to the cash reserve for the payment of future Trust expenses of approximately $0.6 million (approximately $4.7 million withheld from 2013 cash distributions to unitholders partially offset by approximately $4.1 million used to pay Trust expenses during the period). Distributable income for the year ended December 31, 2012 was $122.4 million, which included a net addition to the cash reserve for payment of future Trust expenses of approximately $2.5 million (approximately $4.8 million withheld from the 2012 cash distributions to unitholders less approximately $2.3 million used to pay Trust expenses during the period). Distributions to Common and Subordinated Units. Holders of Trust common units received greater distributions than holders of Trust subordinated units during the year ended December 31, 2013 as a result of the Trust's subordination provisions. Because income available for distribution on the Trust common units for the May 2013 distribution was below the Subordination Threshold, reduced distributions were paid to the subordinated units for that period. As a result of the subordination provisions, holders of common units received approximately $1.6 million more in distributions for the year ended December 31, 2013 than such holders would have received had the subordination provisions not existed. 40

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

Revenues Royalty Income. Royalty income received during the year ended December 31, 2012 totaled $126.5 million compared to $40.8 million received during the year ended December 31, 2011. The increase in royalty income is primarily attributable to the Trust's receipt during the 2012 period of net revenue for production covering a twelve-month period compared to its receipt during the 2011 period of net revenue for production covering a five-month period. Net revenue distributions received from SandRidge by the Trust during the year ended December 31, 2012 included royalty income attributable to production for the twelve-month period from September 1, 2011 to August 31, 2012 of 1,461 MBbls of oil and NGLs and 390 MMcf of natural gas. The net revenue distribution received from SandRidge by the Trust during the year ended December 31, 2011 included royalty income attributable to production for the five-month period from April 1, 2011 to August 31, 2011 of 453 MBbls of oil and NGLs and 120 MMcf of natural gas. Additionally, production during 2012 increased from 2011 due to production from Trust Development Wells completed during 2012. During 2012, there was an average of 717 Initial and Trust Development Wells producing compared to 515 during 2011. The increase in production was partially offset by a decrease in prices received for oil and natural gas production during the year ended December 31, 2012 compared to 2011. Average combined prices received for oil and NGL production and for natural gas production, excluding the impact of derivative settlements and post-production expenses, during the year ended December 31, 2012 were $85.94 per Bbl and $2.30 per Mcf compared to $89.13 per Bbl and $3.44 per Mcf during the year ended December 31, 2011. Derivative Settlements. Net cash settlements received related to the Trust's derivative contracts during the year ended December 31, 2012 were approximately $6.8 million, and included (i) approximately $2.2 million received related to the conveyed contracts for production attributable to the Royalty Interests from September 1, 2011 to August 31, 2012, (ii) approximately $4.1 million received from the counterparty to the novated contracts for production attributable to the Royalty Interests from October 1, 2011 to August 31, 2012 and (iii) approximately $0.5 million received from the counterparty to the novated contracts for September 2012 production. Total net derivative settlements received by the Trust for production from September 1, 2011 to August 31, 2012 were $7.0 million, including $0.7 million received in 2011 from the counterparty to the novated contracts, which effectively increased the average price received for oil production for the related period by $5.33 per Bbl to $96.01 per Bbl. Net cash settlements received related to the Trust's derivative contracts during the year ended December 31, 2011 were approximately $1.8 million, and included $1.1 million received related to production attributable to the Royalty Interests from April 1, 2011 to August 31, 2011, which effectively increased the average price received for oil production for the related period by $2.85 per Bbl to $96.23 per Bbl. Net settlements received during 2012 and 2011 were due to lower commodity prices at the time of settlement compared to the contract price of the Trust's oil fixed price swaps. Expenses



Post-Production Expenses. Post-production expenses for the year ended December 31, 2012 totaled approximately $117,000 compared to approximately $22,000 for the year ended December 31, 2011. Expense for the year ended December 31, 2012 is attributable to twelve months of production compared to five months of production for the year ended December 31, 2011.

Property Taxes. Property taxes paid during the year ended December 31, 2012 totaled approximately $0.6 million compared to approximately $0.2 million for the year ended December 31, 2011. The total payments made related to 2012 property taxes were $2.2 million ($0.4 million paid in October 2012 and $1.8 paid in January 2013) compared to approximately $0.4 million in payments made related to 2011 property taxes ($0.2 million paid in November 2011 and $0.2 paid in February 2012). The net increase in the estimated property tax incurred attributable to calendar year 2012 relates to several factors including the number of days the Royalty Interests were owned by the Trust during 2012 compared to 2011, changes in the producing reserves associated with the Royalty Interests and changes in commodity prices used to value the associated reserves. Production Taxes. Production taxes for the year ended December 31, 2012 totaled $6.0 million, or $3.94 per Boe, and were approximately 4.8% of royalty income. Production taxes for the year ended December 31, 2011 totaled $2.0 million, or $4.14 per Boe, and were approximately 4.8% of royalty income. Texas Franchise Tax. The Trust paid its Texas franchise tax for the year ended December 31, 2011 of approximately $0.2 million or approximately 0.4% of the 2011 royalty income, during the year ended December 31, 2012. Trust Administrative Expenses. Trust administrative expenses for the year ended December 31, 2012 totaled approximately $1.5 million compared to approximately $0.7 million for the year ended December 31, 2011. Because the Royalty Interests were conveyed to the Trust in August 2011, expense for the year ended December 31, 2011 is attributable to five months of activity compared to twelve months of activity for the year ended December 31, 2012. 41 --------------------------------------------------------------------------------

Table of Contents Distributable Income Distributable income for the year ended December 31, 2012 was $122.4 million, which included a net addition to the cash reserve for payment of future Trust expenses of approximately $2.5 million (approximately $4.8 million withheld from the 2012 cash distributions to unitholders less approximately $2.3 million used to pay Trust expenses during the period). Distributable income for the year ended December 31, 2011 was $38.6 million, which included a net addition to the cash reserve for payment of future Trust expenses of approximately $1.1 million (approximately $1.8 million withheld from the 2012 cash distributions to unitholders less approximately $0.7 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, 2013 or 2012. Under the derivatives agreement, SandRidge pays the Trust amounts it receives from its counterparty and the Trust pays SandRidge any amounts that SandRidge is required to pay such counterparty. Additionally, the Trust receives payment directly from its counterparty to the contracts novated to the Trust by SandRidge and is required to pay any amounts owed under those contracts directly to the counterparty. Significant payments by the Trust to SandRidge or the counterparty to the novated contracts could reduce or eliminate distributions paid to unitholders.



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

42 -------------------------------------------------------------------------------- Table of Contents Covered Production Total Period Date Declared Date Paid Distribution Paid (in millions)

Calendar Quarter 2013 September 1, 2012 - November 30, First Quarter 2012 January 31, 2013 March 1, 2013 $ 31.7 December 1, 2012 - Second Quarter February 28, 2013 April 25, 2013 May 30, 2013 $ 24.8 March 1, 2013 - Third Quarter May 31, 2013 July 25, 2013 August 29, 2013 $ 30.7 June 1, 2013 - Fourth Quarter August 31, 2013 October 24, 2013 November 29, 2013 $ 34.2 Calendar Quarter 2012 September 1, 2011 - November 30, First Quarter 2011 February 2, 2012 February 29, 2012 $ 29.1 December 1, 2011 - Second Quarter February 29, 2012 April 30, 2012 May 30, 2012 $ 30.5 March 1, 2012 - Third Quarter May 31, 2012 July 26, 2012 August 29, 2012 $ 30.1 June 1, 2012 - Fourth Quarter August 31, 2012 November 1, 2012 November 29, 2012 $ 32.8 Calendar Quarter 2011 First Quarter N/A N/A N/A N/A Second Quarter N/A N/A N/A N/A Third Quarter N/A N/A N/A N/A April 1, 2011 - Fourth Quarter August 31, 2011 October 28, 2011 November 30, 2011 $ 37.9 On February 28, 2014, the Trust will pay a cash distribution of $0.641 per unit covering production for the three-month period from September 1, 2013 to November 30, 2013. The distribution totaled $33.7 million and will be made to record unitholders as of February 14, 2014. Contractual Obligations



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

Payments Due by Year 2014 2015 2016 2017 2018 After 2018 Total (in thousands) Administrative services fee $ 300.0$ 300.0$ 300.0$ 300.0$ 300.0$ 3,675.0$ 5,175.0 Trustee Administrative fee 150.0 150.0 150.0 150.0 150.0 1, 837.5 2,587.5 Collateral agency fee 15.0 15.0 - - - - 30.0 Delaware Trustee fee 2.4 2.4 2.4 2.4 2.4 31.2 43.2 Total $ 467.4$ 467.4$ 452.4$ 452.4$ 452.4$ 5,543.7$ 7,835.7 Pursuant to the terms of the administrative services agreement with SandRidge, the Trust is obligated to pay SandRidge an annual administrative services fee of $300,000 for accounting, tax preparation, bookkeeping, informational and hedge management services to be performed by SandRidge on behalf of the Trust throughout the life of the Trust. Pursuant to the trust agreement, the Trust is obligated to pay the Trustee an annual administrative fee of $150,000 until April 1, 2017 after which the fee will be adjusted annually for inflation by no more than plus or minus 3% in any one year through 2030, and the Trust is obligated to pay the Delaware Trustee an annual fee of $2,400, throughout the life of the Trust. Additionally, pursuant to the terms of the collateral agency agreement, the Trust pays an annual fee of $15,000 to the collateral agent through 2015. 43

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Critical Accounting Policies and Estimates

The financial statements of the Trust are significantly affected by its basis of accounting and estimates related to the Royalty Interests and proved reserves, as summarized below. Basis of Accounting. The financial statements of the Trust differ from financial statements prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") as the Trust records revenues when cash is received (rather than when earned) and expenses when paid (rather than when incurred) and may also establish cash reserves for contingencies, which would not be accrued in financial statements prepared in accordance with GAAP. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the SEC as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts. Amortization of investment in royalty interests, calculated on a unit-of-production basis, and any impairment are charged directly to trust corpus. Distributions to unitholders are recorded when declared. Because the Trust's financial statements are prepared on a modified cash basis, most accounting pronouncements are not applicable to the Trust's financial statements. Proved Reserves. The proved oil, NGL and natural gas reserves for the Royalty Interests are estimated by independent petroleum engineers. Estimates of proved reserves are based on the quantities of oil and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions, however, there are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, rates of production and timing of development expenditures, including many factors beyond the Trust's control. Estimating reserves is very complex and relies on assumptions and subjective interpretations of available geologic, geophysical, engineering and production data, and the accuracy of reserve estimates is a function of the quality and quantity of available data, engineering and geological interpretation and judgment. In addition, as a result of volatility of changing market conditions, commodity prices will vary from period to period, causing estimates of proved reserves to vary, as well as causing estimates of future net revenues to vary. Estimates of proved reserves are key components of the Trust's most significant financial estimates as discussed further below. Amortization of Investment in Royalty Interests. Amortization of investment in royalty interests is calculated on a units-of-production basis, whereby the Trust's cost basis is divided by the proved reserves attributable to the Royalty Interests to derive an amortization rate per reserve unit. The rate used to record amortization is dependent upon the estimate of total proved reserves for the Royalty Interests, which incorporates various assumptions and future projections. If the estimates of total proved reserves decline significantly, the rate at which the Trust records amortization would increase, reducing trust corpus. Such a decline in reserves may result from lower commodity prices, which may make it uneconomic for SandRidge to develop or produce the Underlying Properties or from other factors, including changes to estimates for other reasons. Changes in reserve quantity estimates are dependent on future economic and operational conditions and cannot be predicted. Impairment of Investment in Royalty Interests. The investment in royalty interests is assessed to determine whether net capitalized cost is impaired whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Potential impairments of the investment in royalty interests are determined by comparing the net capitalized costs of investment in royalty interests to undiscounted future net revenues attributable to the Trust's interest in the proved oil and natural gas reserves of the Underlying Properties. The Trust provides a write-down to the extent that the net capitalized costs exceed the fair value of the Royalty Interests, which is determined using net discounted future cash flows of the oil, NGL and natural gas reserves attributable to the Royalty Interests. Different pricing assumptions or discount rates could result in a different calculated impairment. Any such write-down would be charged directly to trust corpus and would not reduce distributable income. No impairments were recorded in 2013, 2012 or 2011.



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

Off-balance sheet arrangements

As of December 31, 2013, the Trust had no off-balance sheet arrangements.


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