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CHKR > SEC Filings for CHKR > Form 10-Q on 8-May-2014All Recent SEC Filings

Show all filings for CHESAPEAKE GRANITE WASH TRUST

Form 10-Q for CHESAPEAKE GRANITE WASH TRUST


8-May-2014

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, 2013 (the "2013 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 March 31, 2014, Chesapeake had drilled and completed 80 wells within the AMI (approximately 88.9 Development Wells as calculated under the development agreement). As of May 5, 2014, Chesapeake had drilled and completed, or caused to be drilled and completed, a total of 81 wells within the AMI (approximately 89.5 Development Wells as calculated under the development agreement) and had drilled, or caused to be drilled, two additional wells within the AMI that were awaiting completion. 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, 2014 and December 31, 2013 was a net liability of $8.5 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 2014, consisting of proceeds attributable to production from September 1, 2013 through November 30, 2013, was made on March 3, 2014 to record unitholders as of February 19, 2014.
The amount of Trust revenues and cash distributions to Trust unitholders fluctuates 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     Incentive
Period           Threshold(a)    Threshold(a)
                           (per unit)
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



(a) For each quarter, the subordination threshold equals 80% of the target distribution and the incentive threshold equals 120% of the target distribution. The subordination and incentive thresholds terminate after the distribution is made for the fourth full calendar quarter following Chesapeake's completion of its drilling obligation.


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 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. During the three months ended March 31, 2014, 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, 2013 through November 30, 2013.
The Trust's income available for distribution throughout 2013 and continuing into 2014 has been adversely affected by several factors. 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 throughout 2013 and continuing into 2014, largely due to higher-than-expected pressure depletion within the AMI described below. For the quarterly production period from September 1, 2013 to November 31, 2013, the Trust paid a common unit distribution below the subordination threshold and no subordinated distribution was paid. Low levels of future production would continue to reduce the Trust's revenues and distributable income available to unitholders and would 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 are not entitled to receive any additional distributions nor are the common units or the subordinated units entitled to arrearages in any future quarter.
During the three months ended March 31, 2014, the Trust recognized approximately $7.7 million in impairments of the Royalty Interests primarily due to lower proved reserve quantities resulting from higher-than-expected pressure depletion within certain areas of the AMI. This depletion has resulted in lower initial production rates and lower expected ultimate recovery in some recent Development Wells. See Investment in Royalty Interests in Note 2 to the financial statements contained in Item 1 of Part I of this Quarterly Report for further discussion of the impairments.
As previously disclosed, Chesapeake reduced its operated rig count in the AMI from four rigs to two rigs in August 2013 to slow the pace of its drilling program and allow more time to apply well performance analysis from well to well. Chesapeake is incorporating into its current development plan for the AMI the results of additional testing and scientific analysis of the Colony Granite Wash reservoir that it has recently completed. In addition, Chesapeake continues to perform well performance analysis on a well-to-well basis in an effort to potentially enhance the value of the remaining Development Wells by optimizing well spacing and interval selections. However, Chesapeake is unable to predict how long its operated rig count will remain at two rigs or the outcome of the application of its additional testing and analysis, including any potential improvement in Development Well drilling performance or the potential effects on future distributions to Trust common unitholders. 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 of the Royalty Interests.
Trust Operations for the Three Months Ended March 31, 2014 as compared to March 31, 2013.
Distributable Income. The Trust's distributable income was $23.2 million for the three months ended March 31, 2014 compared to $27.9 million for the three months ended March 31, 2013, a decrease of $4.7 million. This decrease was primarily due to lower-than-expected initial production rates from Development Wells completed in the production period from September 1, 2013 to November 30, 2013 ("current production quarter") compared to the production period from September 1, 2012 to November 30, 2012 ("prior production quarter").


On a per unit basis, cash distributions during the three months ended March 31, 2014 and attributable to the current production quarter were $0.6624 per common unit and no subordinated unit distribution was paid as compared to $0.6700 per common unit and $0.3772 per subordinated unit for the three months ended March 31, 2013 and attributable to the prior production quarter. Distributable income for each of the production periods described above was calculated as follows:

                                                                  Three Months Ended
                                                                       March 31,
                                                                  2014             2013
                                                              ($ in thousands, except per
                                                                      unit data)
Revenues:
Royalty income(a)                                           $       26,322     $   29,463
Expenses:
Production taxes                                                       513            588
Trust administrative expenses(b)                                       317            366
Derivative settlement loss                                           2,265            609
Total Expenses                                                       3,095          1,563
Distributable income available to unitholders               $       23,227     $   27,900

Distributable income per common unit (35,062,500 units
issued
and outstanding)                                            $       0.6624     $   0.6700
Distributable income per subordinated unit (11,687,500
units issued
and outstanding)(c)                                         $            -     $   0.3772


 _____________________________________________________
(a) Net of certain post-production expenses.

(b) Includes cash reserves withheld.

(c) For the three months ended March 31, 2014, the distribution per common unit was below the applicable subordination threshold. As a result, no distribution was declared for the subordinated units.

Royalty Income. Royalty income to the Trust for the three months ended March 31, 2014, and attributable to the current production quarter, totaled $26.3 million based upon sales of production attributable to the Royalty Interests of 115 thousand barrels ("mbbls") of oil, 280 mbbls of NGL and 2,488 million cubic feet ("mmcf") of natural gas. Total production attributable to the Royalty Interests for the current production quarter was 809 thousand barrels of oil equivalent ("mboe"). Average prices received for production, including the impact of certain post-production expenses and excluding production taxes, during the current production quarter were $96.39 per barrel ("bbl") of oil, $34.63 per bbl of NGL and $2.24 per thousand cubic feet ("mcf") of natural gas. Royalty income to the Trust for the three months ended March 31, 2013, and attributable to the prior production quarter, 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 mmcf of natural gas. Total production attributable to the Royalty Interests for the prior production quarter was 990 mboe. Average prices received for production, including the impact of certain post-production expenses and excluding production taxes, during the prior production quarter were $86.26 per bbl of oil, $31.92 per bbl of NGL and $1.94 per mcf of natural gas.
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, 2014, and attributable to the current production quarter, totaled $0.5 million, or $0.63 per barrel of oil equivalent ("boe"), as compared to production taxes for the three months ended March 31, 2013, and attributable to the prior production quarter, which totaled $0.6 million, or $0.59 per boe. Production taxes represented approximately 2% of royalty income for each of the three months ended March 31, 2014 and 2013.


Trust Administrative Expenses. Trust administrative expenses, including additional cash reserves, for the three months ended March 31, 2014 totaled $0.3 million as compared to $0.4 million for the three months ended March 31, 2013. Trust administrative expenses primarily consist of the administrative fees paid to the Trustees and Chesapeake and costs for accounting and legal services. Cash Settlements on Derivatives. 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 March 31, 2014, with proceeds from royalty income for the current production quarter. Total losses during the three months ended March 31, 2014 were $2.3 million. Swaps covering the prior production quarter were settled, during the three months ended March 31, 2013, with proceeds from royalty income for the prior production quarter. Total losses during the three months ended March 31, 2013 were $0.6 million.
Impairments of Royalty Interests. During the three months ended March 31, 2014 and 2013, the Trust recognized approximately $7.7 million and $32.9 million in impairments of the Royalty Interests, respectively. The impairments were the result of downward reserve revisions attributable to production being below expectations, primarily as a result of higher-than-expected pressure depletion within some areas of the AMI. The impairments resulted in a non-cash charge to the Trust corpus and did 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 current quarter distribution of $0.6624 per common unit, consisting of proceeds attributable to production from September 1, 2013 through November 30, 2013, was made on March 3, 2014 to record unitholders as of February 19, 2014.


On May 8, 2014, the Trust declared a cash distribution of $0.6454 per common unit, consisting of proceeds attributable to production from December 1, 2013 to February 28, 2014. The distribution will be paid on May 30, 2014 to record unitholders as of May 20, 2014. The Trust's quarterly income available for distribution was $0.4840 per unit, which was $0.2060 below the applicable subordination threshold of $0.6900. All of the quarterly income available for distribution will be used to make the common unit distribution, which is $0.0446 below the applicable subordination threshold, and no subordinated unit distribution will be paid. Distributable income attributable to production from December 1, 2013 to February 28, 2014 was calculated as follows (in thousands except for unit and per unit amounts):

REVENUES:
Royalty income(a)                               $ 25,334
EXPENSES:
Production taxes                                     486
Trust administrative expenses(b)                     468
Derivative settlement loss                         1,752
Total Expenses                                     2,706
Distributable income available to unitholders   $ 22,628

Distributable income per common unit
(35,062,500 units)                              $ 0.6454
Distributable income per subordinated unit
(11,687,500 units)                              $      -


___________________________________________________
(a) Net of certain post-production expenses.

(b) Includes cash reserves withheld.

(c) As the distribution per common unit was below the applicable subordination threshold, no distribution was declared for the subordinated units.

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 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, 2014 or December 31, 2013.
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 Item 1 of

Part I of this Quarterly Report.
Critical Accounting Policies and Estimates Refer to Note 2 in Item 1 of Part I for a discussion of significant accounting policies and estimates that impact the Trust's financial statements. Critical accounting policies and estimates relating to the Trust are contained in Item 7 of the 2013 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.
As of March 31, 2014, the Trust had the following crude oil derivative contracts:

                               Fixed-Price Oil Swaps
                                 Weighted        Fair Value
. . .
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