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CHKR > SEC Filings for CHKR > Form 10-Q on 7-Nov-2013All Recent SEC Filings

Show all filings for CHESAPEAKE GRANITE WASH TRUST

Form 10-Q for CHESAPEAKE GRANITE WASH TRUST


7-Nov-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 statements contained in Item 1 of Part I 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. Concurrent with the Trust's initial public offering in November 2011, 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 since 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 September 30, 2013, Chesapeake had drilled and completed 73 wells within the AMI (approximately 79.9 Development Wells as calculated under the development agreement). As of November 4, 2013, Chesapeake had drilled and completed, or caused to be drilled and completed, a total of 74 wells within the AMI (approximately 81.0 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 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 September 30, 2013 and December 31, 2012 was a net liability of $11.8 million and $8.1 million, respectively.

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. The distribution made in the second quarter of 2013, consisting of proceeds attributable to production from December 1, 2012 through February 28, 2013, was made on May 31, 2013 to record unitholders as of May 21, 2013. The distribution made in the third quarter of 2013, consisting of proceeds attributable to production from March 1, 2013 through May 31, 2013, was made on August 29, 2013 to record unitholders as of August 19, 2013.
The amount of Trust revenues and cash distributions to Trust unitholders will fluctuate from quarter to quarter depending on several factors, including:

timing and amount of initial production and 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 Development Well drilling obligation, 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.


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(1)        $0.69               $1.04
Second Quarter(2)       $0.69               $1.04
Third Quarter(3)        $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



(1) A distribution of $0.6900 per common unit and $0.3010 per subordinated unit was made on May 31, 2013 to unitholders of record as of May 21, 2013.

(2) A distribution of $0.6900 per common unit and $0.1432 per subordinated unit was made on August 29, 2013 to unitholders of record as of August 19, 2013.

(3) A distribution of $0.6671 per common unit was declared on November 7, 2013 and will be paid on November 29, 2013 to unitholders of record as of November 19, 2013. As the distribution per common unit was below the subordination threshold, no distribution was declared for the subordinated units.

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 August 2013, the Trust received a payment on the Royalty Interests representing royalties attributable to proceeds from sales of oil, NGL and natural gas for March 1, 2013 through May 31, 2013. In May 2013, the Trust received a payment on the Royalty Interests representing royalties attributable to proceeds from sales of oil, NGL and natural gas for December 1, 2012 through February 28, 2013. In March 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.

The Trust's income available for distribution to unitholders has been adversely affected by several factors in 2012 and 2013. Low natural gas prices combined with stronger oil prices have resulted in an industry-wide increase in drilling activity in oil- and NGL-rich plays since 2010. 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. In addition to the Trust's exposure to low prices for natural gas and NGL, the Trust experienced reduced production volumes in prior production periods, largely because of higher than expected pressure depletion within the AMI described below. Accordingly, for the past five quarterly production periods, the Trust paid a common unit distribution at the subordination threshold and a subordinated unit distribution below the subordination threshold, and on November 7, 2013, the Trust announced that the next quarterly common unit distribution to be paid, which relates to the production period from June 1, 2013 to August 31, 2013, will be below the subordination threshold and no subordinated unit distribution will be paid. See Note 7 for information regarding prior distributions paid and Note 8 for information regarding the distribution to be paid November 29, 2013 to record unitholders as of November 19, 2013. Sustained low commodity prices and low levels of future production would continue to reduce the Trust's revenues and distributable income available to unitholders and likely result in continued distributions to common unitholders below the subordination threshold. When a quarterly cash distribution in respect of the common units is lower than the applicable subordination threshold, the common units will not be entitled to receive any additional distributions nor will the units be entitled to arrearages in any future quarter.
During the nine months ended September 30, 2013, the Trust recognized an aggregate of $44.3 million in impairments of the Royalty Interests primarily due to higher than expected pressure depletion within certain areas of the AMI. This pressure depletion has resulted in lower initial production rates and lower expected ultimate recovery in some recent Development Wells. See Note 2 for further discussion of the impairments. During the three months ended September 30, 2013, Chesapeake informed the Trust that it is performing additional testing and scientific analysis of the Colony Granite Wash reservoir in an effort to potentially enhance the value of the remaining Development Wells by optimizing well spacing and interval selections. Chesapeake reduced its operated rig count in the AMI from four rigs to two rigs in mid-August 2013, which allows more time to apply well performance analysis from well to well as Chesapeake's drilling program progresses at a slower pace.

At this time, Chesapeake is unable to predict how long its operated rig count will remain at two rigs or the outcome of its additional testing and analysis, including any potential improvement in Development Well drilling performance or the potential effects on future distributions to common unitholders. The operated rig count reduction will decrease the rate at which royalty income from the remaining Development Wells becomes available to the Trust for distribution to unitholders, and if well performance does not improve, the Trust's revenues and distributable income available to unitholders will be reduced further, contributing to continued distributions to common unitholders below the subordination threshold. Decreased well performance or lower expected ultimate recovery may also lead to further impairments.
Trust Operations for the Three Months Ended September 30, 2013 as compared to September 30, 2012.

Distributable Income. The Trust's distributable income was $25.9 million for the three months ended September 30, 2013 compared to $27.0 million for the three months ended September 30, 2012, a decrease of $1.1 million. This decrease was primarily due to the decrease in the average realized prices received from sales of oil and NGL and lower than expected initial production rates from Development Wells completed in the production period from March 1, 2013 to May 31, 2013 ("current production quarter"). During the current production quarter, the average price received for oil and NGL decreased compared to the production period from March 1, 2012 to May 31, 2012 ("prior production quarter"). These decreases were partially offset by an increase in the price received for natural gas for the current production quarter as compared to the prior production quarter. See Royalty Income below for information regarding the change in average prices received and the change in sales volumes.


On a per unit basis, cash distributions during the three months ended September 30, 2013 and attributable to the current production quarter were $0.6900 per common unit and $0.1432 per subordinated unit as compared to $0.6100 per common and $0.4819 per subordinated unit for the three months ended September 30, 2012 and attributable to the prior production quarter. Distributable income for the three months ended September 30, 2013, and attributable to the current production quarter, and for the three months ended September 30, 2012, and attributable to the prior production quarter, was calculated as follows:

                                                                Three Months Ended
                                                                  September 30,
                                                             2013                    2012
                                                      ($ in thousands, except per unit data)
Revenues:
Royalty income(1)                                  $                27,759     $       30,955
Interest income                                                          -                  1
Total Revenues                                                      27,759             30,956
Expenses:
Production taxes                                                       497                797
Trust administrative expenses(2)                                       342                516
Derivative settlement loss                                           1,053              2,623
Total Expenses                                                       1,892              3,936
Distributable income available to unitholders      $                25,867     $       27,020

Distributable income per common unit (35,062,500
units issued
and outstanding)                                   $                0.6900     $       0.6100
Distributable income per subordinated unit
(11,687,500 units issued
and outstanding)                                   $                0.1432     $       0.4819


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

Royalty Income. Royalty income to the Trust for the three months ended September 30, 2013, and attributable to the current production quarter, totaled $27.8 million based upon sales of production attributable to the Royalty Interests of 132 thousand barrels ("mbbls") of oil, 267 mbbls of NGL and 2,894 million cubic feet ("mmcf") of natural gas. Total production for the current production quarter was 881 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 taxes, during the current production quarter were $88.88 per barrel ("bbl"), $31.42 per bbl and $2.65 per thousand cubic feet ("mcf"), respectively. Royalty income to the Trust for the three months ended September 30, 2012, and attributable to the prior production quarter, totaled $31.0 million based upon sales of production attributable to the Royalty Interests of 168 mbbls of oil, 328 mbbls of NGL and 3,144 mmcf of natural gas. Total production for the prior production quarter was 1,020 mboe. Average prices received for oil, NGL and natural gas production, including the impact of certain post-production expenses and excluding production taxes, during the prior production quarter were $97.96 per bbl, $32.83 per bbl and $1.17 per mcf, respectively. 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 September 30, 2013, and attributable to the current production quarter, totaled $0.5 million, or $0.56 per barrel of oil equivalent ("boe"), as compared to production taxes for the three months ended September 30, 2012, and attributable to the prior production quarter, which totaled $0.8 million, or $0.78 per boe. Production taxes represented approximately 1.8% and 2.6% of royalty income for the three months ended September 30, 2013 and 2012, respectively.


Trust Administrative Expenses. Trust administrative expenses, including additional cash reserves, for the three months ended September 30, 2013 totaled $0.3 million as compared to $0.5 million for the three months ended September 30, 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 the current production quarter were settled, during the three months ended September 30, 2013, with proceeds from royalty income for the current production quarter. Total losses during the three months ended September 30, 2013 were $1.1 million. Swaps covering the prior production quarter were settled, during the three months ended September 30, 2012, with proceeds from royalty income for the prior production quarter. Total losses during the three months ended September 30, 2012 were $2.6 million. Development Wells. As of September 30, 2013, all of the Producing Wells were producing and approximately 79.9 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, 2013 was approximately $84.9 million. In addition, 1.1 Development Wells (as calculated under the development agreement) were drilled in the AMI and subsequently completed in November 2013. As of November 4, 2013, Chesapeake had drilled and completed, or caused to be drilled and completed, a total of 74 wells within the AMI (approximately 81.0 Development Wells as calculated under the development agreement) and the amount that could be recovered under the Drilling Support Lien was approximately $82.4 million.
Trust Operations for the Nine Months Ended September 30, 2013 as compared to September 30, 2012.

Distributable Income. The Trust's distributable income was $81.5 million for the nine months ended September 30, 2013 compared to $91.8 million for the nine months ended September 30, 2012, a decrease of $10.3 million. This decrease was primarily due to the decrease in the average realized prices received from sales of oil and NGL and lower than expected initial production rates from Development Wells completed in the production period from September 1, 2012 to May 31, 2013 ("current production period"). During the current production period, the average price received for oil and NGL decreased compared to the production period from September 1, 2011 to May 31, 2012 ("prior production period"). These decreases were partially offset by an increase in the price received for natural gas for the current production period compared to the prior production period. See Royalty Income below for information regarding the change in average prices received and the change in sales volumes.


On a per unit basis, cash distributions during the nine months ended September 30, 2013 and attributable to the current production period were $2.0500 per common unit and $0.8214 per subordinated unit as compared to $1.9965 per common and $1.8684 per subordinated unit for the nine months ended September 30, 2012 and attributable to the prior production period. Distributable income for the nine months ended September 30, 2013, and attributable to the current production period, and the nine months ended September 30, 2012, and attributable to the prior production period, was calculated as follows:

                                                               Nine Months Ended
                                                                 September 30,
                                                            2013                  2012
                                                    ($ in thousands, except per unit data)
Revenues:
Royalty income(1)                                  $             87,090     $      101,579
Interest income                                                       -                  3
Total Revenues                                                   87,090            101,582
Expenses:
Production taxes                                                  1,662              2,347
Trust administrative expenses(2)                                  1,281              1,381
Derivative settlement loss                                        2,669              6,014
Total Expenses                                                    5,612              9,742
Distributable income available to unitholders      $             81,478     $       91,840

Distributable income per common unit (35,062,500
units issued
and outstanding)                                   $             2.0500     $       1.9965
Distributable income per subordinated unit
(11,687,500 units issued
and outstanding)                                   $             0.8214     $       1.8684


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

Royalty Income. Royalty income to the Trust for the nine months ended September 30, 2013, and attributable to the current production period, totaled $87.1 million based upon sales of production attributable to the Royalty Interests of 432 mbbls of oil, 908 mbbls of NGL and 8,839 mmcf of natural gas. Total production for the current production period was 2,813 mboe. Average prices received for oil, NGL and natural gas production, including the impact of certain post-production expenses and excluding production taxes, during the current production period were $87.60 per bbl, $32.03 per bbl and $2.28 per mcf, respectively. Royalty income to the Trust for the nine months ended September 30, 2012, and attributable to the prior production period, 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 prior production 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 taxes, during the prior production period were $93.69 per bbl, $37.34 per bbl and $1.88 per mcf, respectively. 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 months ended September 30, 2013 and attributable to the current production period totaled $1.7 million, or $0.59 per boe, as compared to production taxes for the nine months ended September 30, 2012 and attributable to the prior production period, which totaled $2.3 million, or $0.79 per boe. Production taxes represented approximately 1.9% and 2.3% of royalty income for the nine months ended September 30, 2013 and 2012, respectively.


Trust Administrative Expenses. Trust administrative expenses, including additional cash reserves, for the nine months ended September 30, 2013 and . . .

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