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

Show all filings for CHESAPEAKE GRANITE WASH TRUST

Form 10-Q for CHESAPEAKE GRANITE WASH TRUST


8-Aug-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 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 June 30, 2013, Chesapeake had drilled and completed 65 wells within the AMI (approximately 72.1 Development Wells as calculated under the development agreement). As of August 2, 2013, Chesapeake had drilled and completed, or caused to be drilled and completed, a total of 68 wells within the AMI (approximately 74.6 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 June 30, 2013 was a net liability of $4.1 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. 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 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            $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 declared on August 8, 2013 and will be paid on or about August 29, 2013 to unitholders of record as of August 19, 2013.

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 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.


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. 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 reduced production volumes for the production periods from September 1, 2012 to May 31, 2013, in addition to higher than expected pressure depletion within the AMI described below, resulted in per unit income available for distribution below the applicable subordination threshold. Accordingly, the Trust paid a common unit distribution at the subordination threshold of $0.6900 and a subordinated unit distribution of $0.3010 on May 31, 2013, covering production from December 1, 2012 through February 28, 2013, and a common unit distribution at the subordination threshold of $0.6700 and a subordinated unit distribution of $0.3772 on March 1, 2013, covering production from September 1, 2012 through November 30, 2012 and, on August 8, 2013, the Trust announced that, on or about August 29, 2013, it will pay a common unit distribution at the subordination threshold of $0.6900 and a subordinated unit distribution of $0.1432, covering production from March 1, 2013 to May 31, 2013, to record unitholders as of August 19, 2013. Sustained low commodity prices and higher than expected pressure depletion have reduced and may continue to reduce the Trust's revenues and distributable income available to unitholders, which may contribute to future distributions to common unitholders below the subordination threshold, and could lead to future impairments.
For the three months ended June 30, 2013 and March 31, 2013, the Trust recognized an $11.4 million and a $32.9 million impairment of the Royalty Interests, for each period, primarily due to higher than expected pressure depletion within certain areas of the AMI which has resulted in lower initial production rates and lower expected ultimate recovery in certain recent Development Wells. See Risks and Uncertainties in Note 2 for further discussion. Chesapeake has informed the Trust that it is currently 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 Colony Granite Wash interval selections. Chesapeake has also advised that it believes it is prudent to reduce its operated rig count in the AMI from four rigs to two rigs beginning in mid-August 2013, which will allow 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. If well performance does not improve, the Trust's revenues and distributable income available to unitholders will be reduced, which may contribute to future distributions to common unitholders below the subordination threshold, and decreased well performance or lower expected ultimate recovery may also lead to further impairments. In addition, the operated rig count reduction from four rigs to two rigs will decrease the rate at which royalty income from the remaining Development Wells becomes available to the Trust for distribution to unitholders, which, if combined with continued low NGL and natural gas prices and reduced well performance, will likely result in future distributions to common unitholders below the subordination threshold beginning in 2014. If 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.
Trust Operations for the Three Months Ended June 30, 2013 as compared to June 30, 2012.

Distributable Income. The Trust's distributable income was $27.7 million for the three months ended June 30, 2013 compared to $30.8 million for the three months ended June 30, 2012, a decrease of $3.1 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 December 1, 2012 to February 28, 2013 ("current production quarter"). During the current production quarter, the average price received for oil was $88.08 per barrel ("bbl") compared to $97.03 per bbl for the production period from December 1, 2011 to February 29, 2012 ("prior production quarter"). NGL prices received were $32.67 per bbl for the current production quarter compared to $36.56 per bbl for the prior production quarter. Current production quarter oil sales volumes also decreased from the prior production quarter to 149 thousand barrels ("mbbls") from 182 mbbls due to higher than expected pressure depletion within certain areas of the AMI. These decreases were offset by an increase in the price received for natural gas to $2.28 per thousand cubic feet ("mcf") for the current production quarter from $1.90 per mcf for the prior production quarter.


On a per unit basis, cash distributions during the three months ended June 30, 2013 and attributable to the current production quarter were $0.6900 per common unit and $0.3010 per subordinated unit as compared to $0.6588 per common and subordinated unit for the three months ended June 30, 2012 and attributable to the prior production quarter. Distributable income for the three months ended June 30, 2013, and attributable to the current production quarter, and the three months ended June 30, 2012, and attributable to the prior production quarter, was calculated as follows:

                                                                Three Months Ended
                                                                     June 30,
                                                             2013                    2012
                                                      ($ in thousands, except per unit data)
Revenues:
Royalty income(1)                                  $                29,868     $       34,554
Interest income                                                          -                  1
Total Revenues                                     $                29,868     $       34,555
Expenses:
Production taxes                                   $                   577     $          798
Trust administrative expenses(2)                                       573                389
Derivative settlement loss                                           1,007              2,567
Total Expenses                                                       2,157              3,754
Distributable income available to unitholders      $                27,711     $       30,801

Distributable income per common unit (35,062,500
units issued
and outstanding)                                   $                0.6900     $       0.6588
Distributable income per subordinated unit
(11,687,500 units issued
and outstanding)                                   $                0.3010     $       0.6588


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

Royalty Income. Royalty income to the Trust for the three months ended June 30, 2013, and attributable to the current production quarter, totaled $29.9 million based upon sales of production attributable to the Royalty Interests of 149 mbbls of oil, 312 mbbls of NGL and 2,886 million cubic feet ("mmcf") of natural gas. Total production for the current production quarter was 942 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 $88.08 per bbl, $32.67 per bbl and $2.28 per mcf, respectively. Royalty income to the Trust for the three months ended June 30, 2012, and attributable to the prior production quarter, totaled $34.5 million based upon sales of production attributable to the Royalty Interests of 182 mbbls of oil, 315 mbbls of NGL and 2,921 mmcf of natural gas. Total production for the prior production quarter was 984 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 $97.03 per bbl, $36.56 per bbl and $1.90 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 June 30, 2013, and attributable to the current production quarter, totaled $0.6 million, or $0.61 per barrel of oil equivalent ("boe") as compared to production taxes for the three months ended June 30, 2012 and attributable to the prior production quarter, which totaled $0.8 million, or $0.81 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 June 30, 2013 totaled $0.6 million as compared to $0.4 million for the three months ended June 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 June 30, 2013, with proceeds from royalty income for the current production quarter. Total losses during the three months ended June 30, 2013 were $1.0 million. Swaps covering the prior production quarter were settled, during the three months ended June 30, 2012, with proceeds from royalty income for the prior production quarter. Total losses during the three months ended June 30, 2012 were $2.6 million.
Development Wells. As of June 30, 2013, all of the Producing Wells were producing and approximately 72.1 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 June 30, 2013 was approximately $102.2 million. In addition, 2.5 Development Wells (as calculated under the development agreement) were drilled in the AMI and subsequently completed in July 2013. As of August 2, 2013, Chesapeake had drilled and completed, or caused to be drilled and completed, a total of 68 wells within the AMI (approximately
74.6 Development Wells as calculated under the development agreement) and the amount that could be recovered under the Drilling Support Lien was approximately $96.6 million. Impairment of Royalty Interests. During the quarter ended June 30, 2013, the Trust recognized an $11.4 million impairment of the Royalty Interests. The impairment was the result of reserve revisions attributable to current production 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 resulted in a non-cash charge to the Trust corpus and did not affect the Trust's distributable income. See Risks and Uncertainties in Note 2 in Item I of Part I. Trust Operations for the Six Months Ended June 30, 2013 as compared to June 30, 2012.

Distributable Income. The Trust's distributable income was $55.6 million for the six months ended June 30, 2013 compared to $64.8 million for the six months ended June 30, 2012, a decrease of $9.2 million. This decrease was primarily due to the decrease in the average realized prices received from sales of oil, NGL and natural gas and lower than expected initial production rates from Development Wells completed in the production period from September 1, 2012 to February 28, 2013 ("current production period"). During the current production period, the average price received for oil was $87.16 per bbl compared to $91.68 per bbl for the production period from September 1, 2011 to February 29, 2012 ("prior production period"). NGL prices received were $32.29 per bbl for the current production period compared to $39.72 per bbl for the prior production period. Natural gas prices were $2.10 per mcf for the current production period compared to $2.26 per mcf for the prior production period.


On a per unit basis, cash distributions during the six months ended June 30, 2013 and attributable to the current production period were $1.3600 per common unit and $0.6782 per subordinated unit as compared to $1.3865 per common and subordinated unit for the six months ended June 30, 2012 and attributable to the prior production period. Distributable income for the six months ended June 30, 2013, and attributable to the current production period, and the six months ended June 30, 2012, and attributable to prior production period, was calculated as follows:

                                                                Six Months Ended
                                                                    June 30,
                                                            2013                   2012
                                                     ($ in thousands, except per unit data)
Revenues:
Royalty income(1)                                  $              59,331     $       70,624
Interest income                                                        -                  2
Total Revenues                                     $              59,331     $       70,626
Expenses:
Production taxes                                   $               1,165     $        1,550
Trust administrative expenses(2)                                     939                865
Derivative settlement loss                                         1,616              3,391
Total Expenses                                                     3,720              5,806
Distributable income available to unitholders      $              55,611     $       64,820

Distributable income per common unit (35,062,500
units issued
and outstanding)                                   $              1.3600     $       1.3865
Distributable income per subordinated unit
(11,687,500 units issued
and outstanding)                                   $              0.6782     $       1.3865


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

Royalty Income. Royalty income to the Trust for the six months ended June 30, 2013, and attributable to the current production period, totaled $59.3 million based upon sales of production attributable to the Royalty Interests of 300 mbbls of oil, 641 mbbls of NGL and 5,946 mmcf of natural gas. Total production for the current production period was 1,932 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 $87.16 per bbl, $32.29 per bbl and $2.10 per mcf, respectively. Royalty income to the Trust for the six months ended June 30, 2012, and attributable the prior production period, totaled $70.6 million based upon sales of production attributable to the Royalty Interests of 359 mbbls of oil, 618 mbbls of NGL and 5,831 mmcf of natural gas. Total production for the prior production period was 1,949 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 $91.68 per bbl, $39.72 per bbl and $2.26 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 six months ended June 30, 2013 and attributable to the current production period totaled $1.2 million, or $0.60 per boe as compared to production taxes for the six months ended June 30, 2012 and attributable to the prior production period, which totaled $1.6 million, or $0.80 per boe. In both periods, production taxes were approximately 2% of royalty income. Trust Administrative Expenses. Trust administrative expenses, including . . .
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