Search the web
Welcome, Guest
[Sign Out, My Account]
EDGAR_Online

Quotes & Info
Enter Symbol(s):
e.g. YHOO, ^DJI
Symbol Lookup | Financial Search
CHKR > SEC Filings for CHKR > Form 10-K on 14-Mar-2014All Recent SEC Filings

Show all filings for CHESAPEAKE GRANITE WASH TRUST

Form 10-K for CHESAPEAKE GRANITE WASH TRUST


14-Mar-2014

Annual Report


ITEM 7. 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 audited financial statements and the accompanying notes relating to the Trust and the Underlying Properties included in Part II, Item 8 of this Annual Report and The Underlying Properties and the Royalty Interests and Discussion and Analysis of Results from the Underlying Properties included in Part I, Item 1 of this Annual 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 Part II, Item 8 of this Annual 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 December 31, 2013, Chesapeake had drilled and completed 75 wells within the AMI (approximately 82.4 Development Wells as calculated under the development agreement). As of March 10, 2014, Chesapeake had drilled and completed, or caused to be


drilled and completed, a total of 79 wells within the AMI (approximately 87.9 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 December 31, 2013 and 2012 was a net liability of $8.1 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. During the year ended December 31, 2013, four distributions were paid. See Liquidity and Capital Resources below and Note 7 to the financial statements contained in Part II, Item 8 of this Annual Report for more information regarding the distributions.
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.

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. During the year ended December 31, 2013, the Trust received payments on the Royalty Interests representing royalties attributable to proceeds from sales of oil, NGL and natural gas for September 1, 2012 through August 31, 2013. During the year ended December 31, 2012, the payments received by the Trust represented royalties attributable to proceeds from sales of oil, NGL and natural gas for September 1, 2011 through August 31, 2012. During the six months ended December 31, 2011, the payments received by the Trust represented royalties attributable to proceeds from sales of oil, NGL and natural gas for July 1, 2011 through August 31, 2011.
The Trust's income available for distribution to unitholders in 2013 and 2012 was 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 in 2013, largely because of higher-than-expected pressure depletion within the AMI described below. For the quarterly production periods from July 2011 through February 2012, the Trust paid a common and subordinated unit distribution above the subordination threshold. For the quarterly production periods from March 2012 through May 2013, the Trust paid a common unit distribution at the subordination threshold and a subordinated unit distribution below the subordination threshold. For the quarterly production period from June 2013 through August 2013, the Trust paid a common unit distribution below the subordination threshold and no subordinated unit distribution was paid, and on February 7, 2014, the Trust announced that the quarterly common unit distribution for the production period from September 1, 2013 to November 30, 2013 that was paid on March 3, 2014 was below the subordination threshold and no subordinated unit distribution was paid. See Note 7 to the financial statements contained in Part II, Item 8 of this Annual Report for information regarding prior distributions paid and Note 8 to the financial statements contained in Part II, Item 8 of this Annual Report for information regarding the distribution paid on March 3, 2014 to record unitholders as of February 19, 2014. Low levels of future production will 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 year ended December 31, 2013, the Trust recognized an aggregate of $50.7 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 pressure depletion has resulted in lower initial production rates and lower expected ultimate recovery in some recent Development Wells. See Note 2 to the financial statements contained in Part II, Item 8 of this Annual Report for further discussion of the impairments. In addition, during the year ended December 31, 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 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 of the Royalty Interests. Distributable Income. The Trust's distributable income was $104.9 million for the year ended December 31, 2013. This compares to $116.5 million for the year ended December 31, 2012. The decrease from 2012 to 2013 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 August 31, 2013 ("2013 production period") as compared to the production period from September 1, 2011 to August 31, 2012 ("2012 production period"). These decreases were partially offset by an increase in the price received for natural gas for the 2013 production period compared to the 2012 production period. Distributable income paid to the Trust unitholders during the six months ended December 31, 2011 and attributable to production from July 1, 2011 to August 31, 2011 ("2011 production period") was $27.1 million, which included a $1.3 million reduction for Trust administrative expenses and a cash reserve for the payment of future Trust administrative expenses. The $89.4 million increase in the Trust's distributable income for the 2012 production period as compared to the 2011 production period was a result of a full twelve months of activity in the 2012 production period compared to two months in the 2011 production period. See Royalty Income below for information regarding average prices received and sales volumes.
On a per unit basis, cash distributions during the year ended December 31, 2013 and attributable to the 2013 production period were $2.7171 per common unit and $0.8214 per subordinated unit compared to $2.6265 per common unit and $2.0892 per subordinated unit for the year ended December 31, 2012 and attributable to the 2012 production


period and $0.5800 per common and subordinated unit for the six months ended December 31, 2011 and attributable to the 2011 production period. Distributable income for the production periods described above was calculated as follows:

                                               Year Ended          Year Ended        Six Months Ended
                                            December 31, 2013   December 31, 2012   December 31, 2011
                                                      ($ in thousands, except per unit data)
Revenues:
Royalty income(1)                           $       114,010     $       127,335     $         29,334
Interest income                                           -                   3                    2
Total revenues                                      114,010             127,338               29,336
Expenses:
Production taxes                                      2,216               2,707                  906
Trust administrative expenses(2)                      1,439               1,732                1,315
Cash settlements on derivatives                       5,487               6,389                    -
Total expenses                                        9,142              10,828                2,221
Distributable income available to
unitholders                                 $       104,868     $       116,510     $         27,115

Distributable income per common unit
(35,062,500 units issued and outstanding)   $        2.7171     $        2.6265     $         0.5800
Distributable income per subordinated
unit (11,687,500 units issued and
outstanding)                                $        0.8214     $        2.0892     $         0.5800


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

(2) Includes cash reserves withheld (used).

Royalty Income. Royalty income to the Trust for the year ended December 31, 2013, and attributable to the 2013 production period, totaled $114.0 million based upon sales of production attributable to the Royalty Interests of 544 mbbls of oil, 1,202 mbbls of NGL and 11,495 mmcf of natural gas. Total production attributable to the Royalty Interests for the 2013 production period was 3,661 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 2013 production period were $90.04 per bbl, $31.77 per bbl and $2.34 per mcf, respectively.
Royalty income to the Trust for the year ended December 31, 2012, and attributable to the 2012 production period, totaled $127.3 million based upon sales of production attributable to the Royalty Interests of 673 mbbls of oil, 1,234 mbbls of NGL and 12,179 mmcf of natural gas. Total production attributable to the Royalty Interests for the 2012 production period was 3,937 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 2012 production period were $91.65 per bbl, $35.01 per bbl and $1.84 per mcf, respectively.
Royalty income to the Trust for the six months ended December 31, 2011, and attributable to the 2011 production period, totaled $29.3 million based upon sales of production attributable to the Royalty Interests of 133 mbbls of oil, 225 mbbls of NGL and 2,172 mmcf of natural gas. Total production attributable to the Royalty Interests for the 2011 production period was 720 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 2011 production period were $88.26 per bbl, $46.65 per bbl and $3.26 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 year ended December 31, 2013 totaled $2.2 million, or $0.61 per boe, or approximately 2.0% of royalty income, as compared to production taxes of $2.7 million, or $0.69 per boe, or approximately 2.1% of royalty income for the year ended December 31, 2012 and $0.9 million, or $1.26 per boe, or approximately 3.1% of royalty income for the six months ended December 31, 2011. The decrease in production


taxes per boe from 2012 to 2013 and from 2011 to 2012 was due to an increase in the number of wells taxed at an incentive tax rate due to horizontal well qualification.
Trust Administrative Expenses. Trust administrative expenses, including cash reserves, for the year ended December 31, 2013 totaled $1.4 million as compared to $1.7 million for the year ended December 31, 2012 and $1.3 million for the six months ended December 31, 2011. Trust administrative expenses primarily consist of the administrative fees paid to the Trustees and Chesapeake and costs for accounting and legal services. Administrative expenses for 2011 included an additional $1.0 million to establish an initial cash reserve.
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 2013 production period were settled, during the year ended December 31, 2013, with proceeds from royalty income for the 2013 production period. Total losses during the year ended December 31, 2013 were $5.5 million. Swaps covering the 2012 production period were settled, during the year ended December 31, 2012, with proceeds from royalty income for the 2012 production period. Total losses during the year ended December 31, 2012 were $6.4 million. There were no such cash settlements during the six months ended December 31, 2011.
Impairments of Royalty Interests. During the year ended December 31, 2013, the Trust recognized an aggregate of $50.7 million in impairments of the Royalty Interests. The impairments were the result of downward reserve revisions attributable to 2013 production being below expectations, primarily as a result of higher-than-expected pressure depletion within some 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. There were no such impairments for the year ended December 31, 2012 or the six months ended December 31, 2011.
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. During the year ended December 31, 2013, four distributions were paid. The 2013 fourth quarter distribution of $0.6671 per common unit, consisting of proceeds attributable to production from June 1, 2013 through August 31, 2013, was made on November 29, 2013 to record unitholders as of November 19, 2013. There was no distribution for the subordinated units for the 2013 fourth quarter. The 2013 third quarter distribution of $0.6900 per common unit and $0.1432 per subordinated unit, consisting of proceeds attributable to production from March 1, 2013 to May 31, 2013, was made on August 29, 2013 to record unitholders as of August 19, 2013. The 2013 second quarter distribution of $0.6900 per common unit and $0.3010 per subordinated unit, 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 2013 first quarter 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 following is a summary of distributable income, distributable income per common unit and distributable income per subordinated unit by quarter for the years ended December 31, 2013 and 2012 and the six months ended December 31, 2011 (in thousands except per unit amounts):

             2013                     Q1            Q2            Q3            Q4           Total
Distributable income              $  27,900     $  27,711     $  25,867     $  23,390     $ 104,868
Distributable income per common
unit                              $  0.6700     $  0.6900     $  0.6900     $  0.6671     $  2.7171
Distributable income per
subordinated unit                 $  0.3772     $  0.3010     $  0.1432     $       -     $  0.8214


             2012                     Q1            Q2            Q3            Q4           Total
Distributable income              $  34,019     $  30,801     $  27,020     $  24,670     $ 116,510
Distributable income per common
unit                              $  0.7277     $  0.6588     $  0.6100     $  0.6300     $  2.6265
Distributable income per
subordinated unit                 $  0.7277     $  0.6588     $  0.4819     $  0.2208     $  2.0892


                   2011                               Q3       Q4         Total
Distributable income                                 $ -    $ 27,115    $ 27,115
Distributable income per common unit                 $ -    $ 0.5800    $ 0.5800
Distributable income per subordinated unit           $ -    $ 0.5800    $ 0.5800

On February 7, 2014, the Trust declared a cash distribution of $0.6624 per common unit, which was $0.0276 below the applicable subordination threshold of $0.6900, and no distribution was declared for the subordinated units. The common unit distribution consisted of proceeds attributable to production from September 1, 2013 to November 30, 2013. The distribution was paid on March 3, 2014 to record unitholders as of February 19, 2014. The Trust's quarterly income available for distribution was $0.4968 per unit, which was $0.1932 below the subordination threshold. See Note 8 to the financial statements contained in Part II, Item 8 of this Annual Report for additional information regarding the distribution paid on March 3, 2014 to record unitholders as of February 19, 2014.
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 December 31, 2013 or 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 "Quantitative and Qualitative Disclosures About Market Risk" in Item 7A of this Annual Report. Contractual Obligations
As of December 31, 2013, the Trust had no obligations or commitments to make future contractual payments other than the Trustee administrative fee, administrative services fee, the collateral agent fee and the Delaware Trustee administrative fee payable to the Trustee, Chesapeake and Wells Fargo Bank, N.A., as collateral agent under the derivative contracts and the Delaware Trustee, respectively.

                                                       Less than 1                                    More than 5
                                             Total         Year         1-3 Years       3-5 Years        Years
. . .
  Add CHKR to Portfolio     Set Alert         Email to a Friend  
Get SEC Filings for Another Symbol: Symbol Lookup
Quotes & Info for CHKR - All Recent SEC Filings
Copyright © 2014 Yahoo! Inc. All rights reserved. Privacy Policy - Terms of Service
SEC Filing data and information provided by EDGAR Online, Inc. (1-800-416-6651). All information provided "as is" for informational purposes only, not intended for trading purposes or advice. Neither Yahoo! nor any of independent providers is liable for any informational errors, incompleteness, or delays, or for any actions taken in reliance on information contained herein. By accessing the Yahoo! site, you agree not to redistribute the information found therein.