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CHKR > SEC Filings for CHKR > Form 10-Q on 8-May-2013All Recent SEC Filings

Show all filings for CHESAPEAKE GRANITE WASH TRUST | Request a Trial to NEW EDGAR Online Pro

Form 10-Q for CHESAPEAKE GRANITE WASH TRUST


8-May-2013

Quarterly Report


ITEM 2. 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 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, 2012 (the "2012 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 formed in June 2011 under the Delaware Statutory Trust Act. 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 derivative contracts (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 derivative contracts. 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, cause to be drilled 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 March 31, 2013, Chesapeake had drilled and completed 58 wells within the AMI (approximately 64.5 Development Wells as calculated under the development agreement). As of May 1, 2013, Chesapeake had drilled and completed, or caused to be drilled and completed, a total of 60 wells within the AMI (approximately 65.7 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 is not permitted to 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 or its affiliates. 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 March 31, 2013 was a net liability of $9.8 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 first quarter of 2013, consisting of proceeds attributable to production from September 1, 2012 through November 30, 2012, was made on March 1, 2013 to record unitholders as of February 19, 2013.


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

timing of 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, Chesapeake agreed to subordinate 11,687,500 of the Trust units retained following the initial public offering of common units, which constitute 25% of the outstanding Trust units. 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 pay a cash distribution on the common units that is no less than 80% of the target distribution for the corresponding quarter. If there is not sufficient cash to fund such a distribution on all of the common units, the distribution to be made with respect to the subordinated units will be reduced or eliminated for such quarter in order to make a distribution, to the extent possible, of up to the subordination threshold amount on all the common units, 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 is 20% greater than the target distribution for such quarter. 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. With respect to distributions for quarters following the fourth full quarter after Chesapeake's satisfaction of its drilling obligation with respect to the Development Wells, 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 period during which the subordinated units are outstanding is referred to as the subordination period.


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The following table sets forth the subordination threshold and the incentive threshold for each calendar quarter through the second quarter of 2017, as established in the Trust Agreement:

                 Subordination
Period             Threshold     Incentive Threshold
                              (per unit)
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

Results of Trust Operations
The quarterly payments to the Trust with respect to the Royalty Interests are based on the amount of proceeds actually received by Chesapeake during the preceding calendar quarter. Proceeds from production are typically received by Chesapeake one month after production. Due to the timing of the payment of production proceeds, quarterly distributions made by Chesapeake to the Trust will generally include royalties attributable to sales of oil, NGL and natural gas for three months, comprised of the first two months of the quarter just ended and the last month of the quarter prior to that one. Chesapeake is required to make the Royalty Interest payments to the Trust within 35 days of the end of each calendar quarter. As a result, in February 2013, the Trust received a payment on the Royalty Interests representing royalties attributable to proceeds from sales of oil, NGL and natural gas for September 1, 2012 through November 30, 2012.
Recently, low natural gas prices combined with stronger oil prices have resulted in increased drilling activity in oil- and NGL-rich plays. The resulting increase in production volumes of NGL led to a significant decrease in the price of NGL in both absolute terms and on a relative basis compared to oil. The Trust's exposure to low prices for NGL and natural gas production volumes for the production period from September 1, 2012 to November 30, 2012 resulted in per unit income available for distribution below the subordination threshold. Accordingly, on March 1, 2013, the Trust paid a common unit distribution at the subordination level of $0.6700 per common unit and a subordinated unit distribution of $0.3772 per subordinated unit for the three month production period ended November 30, 2012. Sustained low commodity prices have and will reduce the Trust's revenues and distributable income available to unitholders, and may continue to result in future distributions to common unitholders at or below the subordination threshold.


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Trust Operations for the Three Months Ended March 31, 2013 as compared to March 31, 2012.

Distributable Income. The Trust's distributable income was $27.9 million for the three months ended March 31, 2013 compared to $34.0 million for the three months ended March 31, 2012, a decrease of $6.1 million. This decrease was primarily due to the decrease in the average realized prices received from sales of natural gas and NGL. During the production period from September 1, 2012 to November 30, 2012 ("current production period") the average realized sales price for natural gas was $1.94 per thousand cubic feet ("mcf") compared to $2.66 per mcf for the production period from September 1, 2011 to November 30, 2011 ("prior production period"). The average realized price for the sales of NGL was $31.92 per barrel ("bbl") in the current production period compared to $43.06 per bbl for the prior production period. Oil prices were comparable at $86.26 per bbl for the current production period as compared to $86.27 per bbl for the prior production period, however, oil sales were comparatively lower for the current production period at 151 thousand barrels ("mbbls") as compared to 177 mbbls for the prior production period.

On a per unit basis, cash distributions during the three months ended March 31, 2013 were $0.6700 per common unit and $0.3772 per subordinated unit covering production for the current production period as compared to $0.7277 per common and subordinated units for the prior production period. Distributable income for the three months ended March 31, 2013, attributable to the current production period, and for the three months ended March 31, 2012, attributable to prior production period, was calculated as follows (in thousands except for unit and per unit amounts):

                                                            Three Months Ended
                                                                March 31,
                                                         2013                2012
Revenues:
Royalty income(1)                                  $        29,463     $       36,070
Interest income                                                  -                  1
Total Revenues                                     $        29,463     $       36,071
Expenses:
Production taxes                                   $           588     $          752
Trust administrative expenses(2)                               366                476
Derivative settlement loss                                     609                824
Total Expenses                                               1,563              2,052
Distributable income available to unitholders      $        27,900     $       34,019

Distributable income per common unit (35,062,500
units issued
and outstanding)                                   $        0.6700     $       0.7277
Distributable income per subordinated unit
(11,687,500 units issued
and outstanding)                                   $        0.3772     $       0.7277


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

Royalty Income. Royalty income to the Trust for the three months ended March 31, 2013, and attributable to the current production period, totaled $29.5 million based upon sales of production attributable to the Royalty Interests of 151 mbbls of oil, 329 mbbls of NGL and 3,060 million cubic feet ("mmcf") of natural gas. Total production for the current production period was 990 thousand barrels of oil equivalent ("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 current production period were $86.26 per bbl, $31.92 per bbl and $1.94 per mcf, respectively. Royalty income to the Trust for the three months ended March 31, 2012, and attributable the prior production period, totaled $36.0 million based upon sales of production attributable to the Royalty Interests of 177 mbbls of oil, 303 mbbls of NGL and 2,910 mmcf of natural gas. Total production for the prior production period was 965 mboe. Average prices received for oil, NGL and natural gas production, including the impact of certain post-production expenses and excluding production tax, during prior production period were $86.27 per bbl, $43.06 per bbl and $2.66 per mcf, respectively.


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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 three months ended March 31, 2013 totaled $0.6 million, or $0.59 per barrel of oil equivalent ("boe") as compared to production taxes for the three months ended March 31, 2012 which totaled $0.8 million, or $0.78 per boe. In both periods production taxes were approximately 2% of royalty income. Trust Administrative Expenses. Trust administrative expenses, including additional cash reserves, for the three months ended March 31, 2013 totaled $0.4 million as compared to $0.5 million for the three months ended March 31, 2012. The decrease was primarily the result of higher first-year expenses in 2012. Trust administrative expenses primarily consist of the administrative fees paid to the Trustees and Chesapeake and costs for accounting and legal services. Derivative Settlement Loss. The Trust records gains or losses from the derivative contracts when proceeds are received or payments are made, respectively. Swaps covering September 1, 2012 through November 30, 2012 production were settled, during the three months ended March 31, 2013, with proceeds from royalty income for the same period. Total losses during the period were $0.6 million, or $0.01 per Trust unit. Swaps covering October 1, 2011 through November 30, 2011 production were settled, during the three months ended March 31, 2012, with proceeds from royalty income for the same period. Total losses during the period were $0.8 million, or $0.02 per Trust unit. Development Wells. As of March 31, 2013, all of the Producing Wells were producing and approximately 64.5 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 March 31, 2013 was approximately $119.2 million. In addition, 1.2 Development Wells (as calculated under the development agreement) were drilled in the AMI and subsequently completed in April 2013. As of May 1, 2013, Chesapeake had drilled and completed, or caused to be drilled and completed, a total of 60 wells within the AMI (approximately
65.7 Development Wells as calculated under the development agreement) and the amount that could be recovered under the Drilling Support Lien was approximately $116.5 million. Impairment of Royalty Interest. During the quarter ended March 31, 2013, the Trust recognized a $32.9 million impairment of the Royalty Interest. The impairment was the result of reserve revisions that were due to current results being below expectations, primarily as a result of higher than expected pressure depletion within certain areas of the AMI. This has resulted in lower initial production rates and lower expected ultimate recovery in certain recent development wells. The impairment results in a non-cash charge to the Trust corpus and does not affect the Trust's distributable income. 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 derivative contracts. 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 first calendar quarter 2013 distribution of $0.6700 per common unit and $0.3772 per subordinated unit, consisting of proceeds attributable to production from September 1, 2012 through November 30, 2012, was made on March 1, 2013 to record unitholders as of February 19, 2013.
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


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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 expenses as they become due, Chesapeake will loan funds to the Trust necessary to pay such expenses. Any funds loaned by Chesapeake 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 current liabilities arising in the ordinary course of the Trust's business, and may not be used to satisfy Trust indebtedness for borrowed money of the Trust. If Chesapeake loans funds pursuant to this commitment, unless Chesapeake 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. There were no loans outstanding as of March 31, 2013 or December 31, 2012.
The Trust is not responsible for any costs related to the drilling of the Development Wells and Chesapeake granted to the Trust the Drilling Support Lien in order to secure the estimated amount of the drilling costs for the Trust's interests in the Development Wells. As Chesapeake fulfills its drilling obligation over time, Development Wells that are completed or that are perforated for completion and then plugged and abandoned are released from the Drilling Support Lien and the total dollar amount that may be recovered by the Trust for Chesapeake's failure to fulfill its drilling obligation is proportionately reduced.
Off-Balance Sheet Arrangements
The Trust has no off-balance sheet arrangements. The Trust has not guaranteed the debt of any other party, nor does the Trust have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt, losses or contingent obligations other than the derivative contracts disclosed in the section Derivative Contracts in Note 3 in Part I, Item I of this Quarterly Report.
Critical Accounting Policies and Estimates Refer to Note 2 of Part I, Item 1 for discussion of significant accounting policies and estimates. Critical accounting policies and estimates relating to the Trust are contained in Item 7 of the 2012 Form 10-K. ITEM 3. Quantitative and Qualitative Disclosures about Market Risk

The discussion in this section provides information about derivative contracts between the Trust and the derivative counterparty effective October 1, 2011. The contracts underlying the derivative contracts cover a portion of the expected production attributable to the Royalty Interests from the Producing Wells and the Development Wells through September 30, 2015. The derivative contracts are settled in cash and do not require the actual delivery of oil or NGL at settlement. The contracts are settled based upon NYMEX prices. Under the derivative contracts, the Trust receives payments directly from the counterparty and pays any amounts owed to the counterparty. The Trust does not have the ability to enter into any additional oil, NGL or natural gas derivative contracts, except in limited circumstances involving the restructuring of the existing oil derivatives contracts.


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As of March 31, 2013, the Trust had the following oil derivative contracts:

                               Fixed-Price Oil Swaps
                                 Weighted
                      Volume    Avg. Price       Fair Value
Production Quarter    (mbbl)    (per bbl)     ($ in thousands)
Q4 2012(1)              62.1      $87.28     $          (341 )
Q1 2013(2)             182.2      $87.37                (987 )
Q2 2013                184.3      $87.60              (1,629 )
Q3 2013                187.9      $87.79              (1,741 )
Q4 2013                184.2      $87.99              (1,437 )
Q1 2014                179.8      $88.08              (1,117 )
Q2 2014                180.3      $88.21                (873 )
Q3 2014                178.8      $88.34                (681 )
Q4 2014                174.3      $88.45                (504 )
Q1 2015                171.0      $88.59                (317 )
Q2 2015                175.4      $88.76                (146 )
Q3 2015                153.6      $88.90                  (9 )
Total                2,013.9      $88.14     $        (9,782 )


 _____________________________________________________


(1) Includes December 2012 production that was settled in February 2013.

(2) Includes January 2013 and February 2013 production that was settled in May 2013.

To the extent expected oil production falls below the hedged oil volume, the derivative contracts will also cover expected NGL production. Such estimated production of NGL is hedged with oil contracts using a conversion ratio of one barrel of NGL to 49.2% of a barrel of oil. In 2012 and continuing in 2013, NGL prices have decreased relative to oil prices. To the extent oil and NGL prices are not correlated, the derivative contracts will not effectively mitigate the price risk of the Trust's NGL production.
The Trust's obligations to the counterparty under the derivative contracts are secured by liens on proved reserves attributable to the Trust's interest in the Underlying Properties. The value of the derivative contracts as of March 31, 2013 was a net liability of $9.8 million.
Oil, NGL and Natural Gas Price Risk. The Trust's primary asset and source of income is the Royalty Interests, which generally entitle the Trust to receive a portion of the net proceeds from the sales of oil, NGL and natural gas from the Underlying Properties. The Trust is significantly exposed to fluctuations in the prices received for oil, NGL and natural gas produced and sold. The derivative contracts described above are designed to mitigate a portion of the variability of the prices received for the Trust's share of production. The use of crude oil derivatives to partially mitigate the price risk of NGL production, to the extent oil production falls below the hedged oil volume, is subject to basis risk to the extent oil and NGL prices are not highly correlated. Credit Risk. A portion of the Trust's liquidity is concentrated in the derivative contracts described above. The use of oil derivative contracts exposes the Trust to credit risk from the counterparty, which has an investment grade credit rating. . . .

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