Introduction
The following discussion and analysis is intended to help the reader understand the Trust's financial condition and results of operations. This discussion and analysis should be read in conjunction with the Trust's unaudited interim financial statements and the accompanying notes relating to the Trust and the Underlying Properties included in Item 1 of Part I of this Quarterly Report as well as the Trust's Annual Report on Form 10-K for the year ended December 31, 2011 (the "2011 Form 10-K"). Capitalized items in this Item 2 have the same meanings ascribed to them in Note 1 to the Trust's financial statements included in Item 1 of Part I of this Quarterly Report. Overview
The Trust is a statutory trust created under the Delaware Statutory Trust Act in June 2011. The business and affairs of the Trust are managed by the Trustee and, as necessary, the Delaware Trustee. The Trust does not conduct any operations or activities other than owning the Royalty Interests and activities related to such ownership. The Trust's purpose is generally to own the Royalty Interests, to distribute to the Trust unitholders cash that the Trust receives in respect of the Royalty Interests and the hedging arrangements (described in Note 3 to the financial statement contained in Part I, Item 1 of this Quarterly Report) and to perform certain administrative functions in respect of the Royalty Interests and the Trust units. The Trust derives all or substantially all of its income and cash flow from the Royalty Interests and the hedging arrangements. The Trust is treated as a partnership for federal income tax purposes. During November 2011, the Trust completed an initial public offering of its common units representing beneficial interests in the Trust, the net proceeds of which were remitted to Chesapeake as partial consideration for its conveyance of the Royalty Interests to the Trust.
Concurrent with the initial public offering, Chesapeake conveyed the Royalty Interests to the Trust effective July 1, 2011, which included interests in
(a) 69 Producing Wells in the Colony Granite Wash play and (b) 118 Development Wells that have been or that are to be drilled in the Colony Granite Wash play on properties within the AMI. Chesapeake is obligated to drill, or participate as a non operator in the drilling of, the Development Wells from drill sites in the AMI on or prior to June 30, 2016. Additionally, based on Chesapeake's assessment of the ability of a Development Well to produce in paying quantities, Chesapeake is obligated to either complete and tie into production or plug and abandon each Development Well. As of September 30, 2012, Chesapeake had drilled and completed 44 wells within the AMI (approximately 47.8 Development Wells as calculated under the development agreement). As of November 9, 2012, Chesapeake had drilled and completed, or caused to be drilled and completed, a total of 47 wells within the AMI (approximately 52.0 Development Wells as calculated under the development agreement). The Trust is not responsible for any costs related to the drilling of the Development Wells or any other operating or capital costs of the Underlying Properties, and Chesapeake may not drill and complete any well in the Colony Granite Wash formation on acreage included within the AMI for its own account until it has satisfied its drilling obligation to the Trust. The Royalty Interests entitle the Trust to receive 90% of the proceeds (after deducting certain post-production expenses and any applicable taxes) from the sales of production of oil, NGL and natural gas attributable to Chesapeake's net revenue interest in the Producing Wells and 50% of the proceeds (after deducting certain post-production expenses and any applicable taxes) from the sales of oil, NGL and natural gas production attributable to Chesapeake's net revenue interest in the Development Wells. Post-production expenses generally consist of costs incurred to gather, store, compress, transport, process, treat, dehydrate and market the oil, NGL and natural gas produced. However, the Trust is not responsible for costs of marketing services provided by Chesapeake. On November 16, 2011, Chesapeake novated to the Trust, and the Trust became party to, derivative contracts covering a portion of the production attributable to the Royalty Interests from October 1, 2011 through September 30, 2015. The Trust's distributable income will include net settlements under these derivative contracts. The value of the derivative contracts as of September 30, 2012 was a net liability of $9.0 million.

The Trust is required to make quarterly cash distributions of substantially all of its cash receipts, after deducting the Trust's administrative expenses, on or about 60 days following the completion of each calendar quarter through (and including) the quarter ending June 30, 2031. The distribution made in the third quarter of 2012, consisting of proceeds attributable to production from March 1, 2012 through May 31, 2012, was made on August 30, 2012 to record unitholders as of August 20, 2012.

The amount of Trust revenues and cash distributions to Trust unitholders will fluctuate from quarter to quarter depending on several factors, including:

• timing of initial sales from the Development Wells;

• oil, NGL and natural gas prices received;

• volumes of oil, NGL and natural gas produced and sold;

• amounts received from, or paid under, derivative contracts;

• certain post-production expenses and any applicable taxes; and

• the Trust's expenses.

Subordination Threshold. In order to provide support for cash distributions on the common units, 11,687,500 units (25% of the outstanding Trust units) are subordinated units. The subordinated units, which are owned by Chesapeake, 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 not less than the applicable subordination threshold for the corresponding quarter as set forth in the Trust Agreement and as shown in the table below. If there is not sufficient cash to fund such a distribution on all of the common units (including the common units held by Chesapeake), the distribution to be made with respect to the subordinated units will be reduced or eliminated for such quarter in order to make a distribution, to the extent possible, up to the subordination threshold amount on all the common units (including the common units held by Chesapeake).
Incentive Threshold. In exchange for agreeing to subordinate a portion of its Trust units, and in order to provide additional financial incentive to Chesapeake to satisfy its drilling obligation and perform operations on the Underlying Properties in an efficient and cost-effective manner, Chesapeake 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 the incentive threshold for the corresponding quarter as set forth in the Trust Agreement and as shown in the table below. The remaining 50% of cash available for distribution in excess of the applicable incentive threshold will be paid to the Trust unitholders, including Chesapeake, on a pro rata basis. At the end of the fourth full calendar quarter following Chesapeake's satisfaction of its drilling obligation with respect to the Development Wells, the subordinated units will automatically convert into common units on a one-for-one basis and Chesapeake'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. There is no assurance of any minimum distribution at any time.

The following table sets forth the subordination threshold and the incentive threshold for each calendar quarter through the second quarter of 2017:

Period              Threshold     Incentive Threshold
                              ($ per unit)
2012:
Third Quarter (1)     0.63                0.94
Fourth Quarter        0.67                1.01
2013:
First Quarter         0.69                1.04
Second Quarter        0.69                1.04
Third Quarter         0.71                1.07
Fourth Quarter        0.69                1.04
2014:
First Quarter         0.69                1.04
Second Quarter        0.68                1.02
Third Quarter         0.69                1.03
Fourth Quarter        0.66                0.99
2015:
First Quarter         0.66                0.99
Second Quarter        0.68                1.02
Third Quarter         0.64                0.96
Fourth Quarter        0.56                0.84
2016:
First Quarter         0.51                0.76
Second Quarter        0.47                0.70
Third Quarter         0.44                0.66
Fourth Quarter        0.41                0.62
2017:
First Quarter         0.39                0.59
Second Quarter        0.37                0.56


 ____________________________________________________

Sustained low commodity prices will reduce the Trust's revenues and distributable income available to unitholders, and may result in future distributions to common unitholders at or below the subordination threshold. Trust Operations for the Three Months Ended September 30, 2012 On August 10, 2012, the Trust declared a cash distribution of $0.6100 per common unit and $0.4819 per subordinated unit covering production for the period from March 1, 2012 through May 31, 2012 to record unitholders as of August 20, 2012. The distribution was paid on August 30, 2012 and is reported as distributable income for the quarter ended September 30, 2012 due to the modified cash accounting method adopted by the Trust. Distributable income attributable to production from March 1, 2012 through May 31, 2012 was calculated as follows (in thousands except for unit and per unit amounts):

Revenues:
Royalty income(1)                                                    $     30,955
Interest income                                                                 1
Total Revenues                                                       $     30,956
Expenses:
Production taxes                                                              797
Trust administrative expenses(2)                                              516
Derivative settlement loss                                                  2,623
Total Expenses                                                              3,936
Distributable income available to unitholders                        $     27,020

Distributable income per common unit (35,062,500 units issued and
outstanding)                                                         $     0.6100
Distributable income per subordinated unit (11,687,500 units issued
and outstanding)                                                     $     0.4819


 _____________________________________________________
(1) Net of certain post-production expenses.
(2) Includes cash reserves withheld.

Distributable Income. Distributable income paid to the Trust unitholders during the three-month period ended September 30, 2012 and attributable to production from March 1, 2012 through May 31, 2012 was $27.0 million, or $0.6100 per common unit and $0.4819 per subordinated unit, which included a $0.5 million reduction for Trust administrative expenses and a cash reserve for the payment of future Trust administrative expenses. Distributable income was lower than the target distribution of $0.76 per unit stated in the prospectus dated November 10, 2011 relating to the initial public offering of the Trust's units (the "Prospectus") primarily as a result of lower than assumed prices for natural gas and NGL that were partially offset by higher than assumed prices for oil, including the impact of

certain post-production expenses. The average price received for oil sales of $97.96 per bbl for March 1, 2012 through May 31, 2012 production exceeded the price of $89.41 per bbl assumed in preparing the target distribution level for the same period. The average price received for NGL sales of $32.83 per bbl was lower than the price of $43.23 per bbl assumed in preparing the target distribution level for the same period. The average price received for natural gas sales of $1.17 per mcf for March 1, 2012 through May 31, 2012 production was lower than the price of $2.93 per mcf assumed in preparing the target distribution level for the same period.
The distribution paid during the three months ended September 30, 2012 was a subordinated distribution. The calculated distribution was below the subordination threshold resulting in a distribution to common unitholders at the subordination threshold and a lower distribution to the subordinated unitholders. All of the subordinated units are held by Chesapeake. Development Wells. As of September 30, 2012, all of the Producing Wells were producing and approximately 47.8 Development Wells (as calculated under the development agreement) were completed and producing. The amount that could be recovered under the Drilling Support Lien as of September 30, 2012 was approximately $156.3 million. In addition, 4.2 Development Wells (as calculated under the development agreement) were drilled in the AMI and subsequently completed in October 2012. As of November 9, 2012, Chesapeake had drilled and completed, or caused to be drilled and completed, a total of 47 wells within the AMI (approximately 52.0 Development Wells as calculated under the development agreement) and the amount that could be recovered under the Drilling Support Lien was approximately $146.9 million.
Trust Operations for the Nine Months Ended September 30, 2012 Cash distributions for the nine-month period ended September 30, 2012 were $1.9965 per common unit and $1.8684 per subordinated unit covering production for the period from September 1, 2011 to May 31, 2012. Distributable income attributable to production from September 1, 2011 to May 31, 2012 was calculated as follows (in thousands except for unit and per unit amounts):

Revenues:
Royalty income(1)                                                    $    101,579
Interest income                                                                 3
Total Revenues                                                       $    101,582
Expenses:
Production taxes                                                            2,347
Trust administrative expenses(2)                                            1,381
Derivative settlement loss                                                  6,014
Total Expenses                                                              9,742
Distributable income available to unitholders                        $     91,840

Distributable income per common unit (35,062,500 units issued and
outstanding)                                                         $     1.9965
Distributable income per subordinated unit (11,687,500 units issued
and outstanding)                                                     $     1.8684


 _____________________________________________________
(1) Net of certain post-production expenses.
(2) Includes cash reserves withheld.

Royalty Income. Royalty income to the Trust for the nine-month period ended September 30, 2012 and attributable to production from September 1, 2011 to May 31, 2012 totaled $101.6 million based upon sales of production attributable to the Royalty Interests of 527 mbbls of oil, 946 mbbls of NGL and 8,975 mmcf of natural gas. Total production for the nine-month period was 2,969 mboe. Average prices received for oil, NGL and natural gas production, including the impact of certain post-production expenses and excluding production tax, during the nine-month period ended September 30, 2012 were $93.69 per bbl, $37.34 per bbl and $1.88 per mcf, respectively. Average sales prices are net of certain post-production expenses, including gathering, storage, compression, transportation, processing, treating, dehydrating and non-affiliate marketing expenses.
Production Taxes. Production taxes are calculated as a percentage of oil, NGL and natural gas revenues, net of any applicable tax credits. Production taxes for the nine-month period ended September 30, 2012 totaled $2.3 million, or $0.79 per boe, and were approximately 2.3% of royalty income.

Derivative Settlement Loss. The Trust will record gains or losses from the derivative contracts conveyed under the hedging arrangements when proceeds are received or payments are made, respectively. Swaps covering October 2011 through May 2012 production were settled, during the nine-month period ended September 30, 2012, with proceeds from royalty income for the same period. Total losses during the period were $6.0 million, or $0.13 per unit.
Distributable Income. Distributable income paid to the Trust unitholders during the nine-month period ended September 30, 2012 and attributable to production from September 1, 2011 to May 31, 2012 was $91.8 million, or $1.9965 per common unit and $1.8684 per subordinated unit, which included a $1.4 million reduction for Trust administrative expenses and a cash reserve for the payment of future Trust administrative expenses. Distributable income was lower than the aggregate target distributions of $2.1800 per unit for the nine months ended September 30, 2012 as stated in the Prospectus primarily as a result of lower than assumed prices for natural gas and NGL that were partially offset by higher than assumed prices for oil, including the impact of certain post-production expenses. The average price received for oil sales of $93.69 per bbl for September 1, 2011 to May 31, 2012 production exceeded the price of $86.96 per bbl assumed in preparing the target distribution level for the same period. The average price received for NGL sales of $37.34 per bbl was lower than the price of $42.14 per bbl assumed in preparing the target distribution level for the same period. The average price received for natural gas sales of $1.88 per mcf for September 1, 2011 to May 31, 2012 production was lower than the price of $2.70 per mcf assumed in preparing the target distribution level for the same period. Development Wells. As of September 30, 2012, all of the Producing Wells were producing and approximately 47.8 Development Wells (as calculated under the development agreement) were completed and producing. The amount that could be recovered under the Drilling Support Lien as of September 30, 2012 was approximately $156.3 million. In addition, 4.2 Development Wells (as calculated under the development agreement) were drilled in the AMI and subsequently completed in October 2012. As of November 9, 2012, Chesapeake had drilled and completed, or caused to be drilled and completed, a total of 47 wells within the AMI (approximately 52.0 Development Wells as calculated under the development agreement) and the amount that could be recovered under the Drilling Support Lien was approximately $146.9 million.
Liquidity and Capital Resources
The Trust's principal sources of liquidity and capital are cash flows generated from the Royalty Interests, the loan commitment as described below and, during periods in which oil prices fall below the fixed price received on derivative contracts, the hedging arrangements. The Trust's primary uses of cash are distributions to Trust unitholders, including, if applicable, incentive distributions to Chesapeake, payments of production taxes, payments of Trust administrative expenses, including any reserves established by the Trustee for future liabilities and repayment of loans, payments for derivative contract settlements and payments of expense reimbursements to Chesapeake for out-of-pocket expenses it incurs on behalf of the Trust. Administrative expenses include payments to the Trustee and the Delaware Trustee as well as a quarterly fee of $50,000 to Chesapeake 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 sales of oil, NGL and natural gas production attributable to the Royalty Interests during the quarter, over the Trust's expenses for the quarter and any cash reserve for the payment of liabilities of the Trust, subject in all cases to the subordination and incentive provisions described previously. The Trust is required to make quarterly cash distributions of substantially all of its cash receipts, after deducting the Trust's administrative expenses, on or about 60 days following the completion of each calendar quarter through (and including) the quarter ending June 30, 2031. The third calendar quarter 2012 distribution of $0.6100 per common unit and $0.4819 per subordinated unit, consisting of proceeds attributable to production from March 1, 2012 through May 31, 2012, was made on August 30, 2012 to record unitholders as of August 20, 2012.
On November 7, 2012, the Trust declared a cash distribution of $0.6300 per common unit and $0.2208 per subordinated unit, consisting of proceeds attributable to production from June 1, 2012 to August 31, 2012, to record unitholders as of November 19, 2012. The distribution will be paid on November 29, 2012. The Trust's quarterly income available for distribution was $0.5277 per unit, which was $0.1023 below the subordination threshold. As a result, the distribution per common unit will be the subordination threshold of $0.6300 for the quarter. Distributable income attributable to production from June 1, 2012 to August 31, 2012 was calculated as follows (in thousands except for unit and per unit amounts):

Revenues:
Royalty income(1)                                                    $     25,756
Total Revenues                                                       $     25,756
Expenses:
Production taxes                                                              361
Trust administrative expenses(2)                                              350
Derivative settlement loss                                                    375
Total Expenses                                                              1,086
Distributable income available to unitholders                        $     24,670

Distributable income per common unit (35,062,500 units issued and
outstanding)                                                         $     0.6300
Distributable income per subordinated unit (11,687,500 units issued
and outstanding)                                                     $     0.2208


 ______________________________________________________
(1) Net of certain post-production expenses.

(2) Includes cash reserves withheld.

The Trustee can authorize the Trust to borrow money to pay Trust expenses that exceed cash held by the Trust. The Trustee may authorize the Trust to borrow from the Trustee as a lender provided the terms of the loan are fair to the Trust unitholders. The Trustee may also deposit funds awaiting distribution in an account with itself, if the interest paid to the Trust at least equals amounts paid by the Trustee on similar deposits, and make other short-term investments with the funds distributed to the Trust. The Trustee may also hold funds awaiting distribution in a non-interest bearing account. Pursuant to the Trust Agreement, if at any time the Trust's cash on hand (including cash reserves) is not sufficient to pay the Trust's ordinary course . . .