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CHKR > SEC Filings for CHKR > Form 10-K on 15-Mar-2013All Recent SEC Filings

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

Form 10-K for CHESAPEAKE GRANITE WASH TRUST


15-Mar-2013

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 Discussion and Analysis of Results from the Producing Wells included in Part I, Item 2 of this Annual Report. Capitalized items in this Item 7 have the same meanings ascribed to them in Note 1 to the Trust's financial statements included in Part II, Item 8 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.
During November 2011, the Trust completed an initial public offering of its common units representing beneficial interests in the Trust, the net proceeds of which were remitted to Chesapeake as partial consideration for its conveyance of the Royalty Interests to the Trust.
Concurrent with the initial public offering, Chesapeake conveyed the Royalty Interests to the Trust effective July 1, 2011, which included interests in the Producing Wells and the Development Wells. Chesapeake is obligated to drill and complete, cause to be drilled and completed 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


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production or plug and abandon each Development Well. As of December 31, 2012, Chesapeake had drilled and completed 51 wells within the AMI (approximately 55.1 Development Wells as calculated under the development agreement). As of March 8, 2013, Chesapeake had drilled and completed, or caused to be drilled and completed, a total of 56 wells within the AMI (approximately 61.3 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 oil and NGL 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, 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. The distribution made in the fourth quarter of 2012, consisting of proceeds attributable to production from June 1, 2012 through August 31, 2012, was made on November 29, 2012 to record unitholders as of November 19, 2012.
The amount of Trust revenues and cash distributions to Trust unitholders will fluctuate from quarter to quarter depending on several factors, including:

timing of sales from the Development Wells;

oil, NGL and natural gas prices received;

volumes of oil, NGL and natural gas produced and sold;

amounts received from, or paid under, derivative contracts;

certain post-production expenses and any applicable taxes; and

the Trust's expenses.

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, the cash received by the Trust with respect to the Royalty Interests during the year ended December 31, 2012 substantially represented royalties attributable to proceeds from sales of oil, NGL and natural gas for September 1, 2011 through August 31, 2012. The cash received by the Trust with respect to the Royalty Interests during the six months ended December 31, 2011 substantially represented the royalties attributable to proceeds from sales of oil, NGL and natural gas for July 1, 2011 through August 31, 2011.

Recently, low natural gas prices combined with stronger oil prices have resulted in increased drilling activity in oil- and NGL-rich plays as operators have reduced uneconomic natural gas drilling activities. The resulting increase


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in production volumes of NGL led to a significant decrease in the price of NGL in both absolute terms and on a relative basis compared to oil. The Trust's exposure to low prices for NGL and natural gas production volumes have resulted in per unit income available for distribution below the subordination threshold. Accordingly, on August 30, 2012, the Trust paid a distribution at the subordination threshold of $0.6100 per common unit for the three month production period ended May 31, 2012 and a subordinated unit distribution of $0.4819 per subordinated unit for such period. On November 19, 2012, the Trust paid a common unit distribution at the subordination threshold of $0.6300 per common unit for the three month production period ended August 31, 2012 and a subordinated unit distribution of $0.2208 per subordinated unit for such period. Additionally, on March 1, 2013 the Trust paid a common unit distribution at the subordination threshold of $0.6700 per common unit for the three-month production period ended November 30, 2012, and a subordinated unit distribution of $0.3772 per subordinated unit for such period.

Sustained low commodity prices will reduce the Trust's revenues and distributable income available to unitholders, and may result in future distributions to common unitholders at or below the subordination threshold. Trust Operations for the Year Ended December 31, 2012 as compared to Inception to December 31, 2011.

The Trust's distributable income was $116.5 million for the year ended December 31, 2012 compared to $27.1 million for the period from inception (the effective date of the conveyance of the Royalty Interests to the Trust was July 1, 2011 and the Trust has received the proceeds of production attributable to the Royalty Interests from that date) through December 31, 2011, an increase of $89.4 million. This increase was primarily due to the increase in the net proceeds to the Trust, which was a result of a full twelve months of activity in 2012 compared to two month of activity in 2011 in the year-over-year comparison.

On a per unit basis, cash distributions during the year ended December 31, 2012 were $2.6265 per common unit and $2.0892 per subordinated unit covering production for the period from September 1, 2011 to August 31, 2012 as compared to $0.58 per common and subordinated units for the six months ended December 31, 2011 covering production from July 1, 2011 to August 31, 2011. Distributable income for the year ended December 31, 2012, attributable to production from September 1, 2011 to August 31, 2012, and for the six months ended December 31, 2011, attributable to production from July 1, 2011 to August 31, 2011, was calculated as follows (in thousands except for unit and per unit amounts):

                                                             Year Ended      Six Months Ended
                                                            December 31,       December 31,
                                                                2012               2011
Revenues:
Royalty income(1)                                          $     127,335     $       29,334
Interest income                                                        3                  2
Total Revenues                                             $     127,338     $       29,336
Expenses:
Production taxes                                                   2,707                906
Trust administrative expenses(2)                                   1,732              1,315
Derivative settlement loss                                         6,389                  -
Total Expenses                                                    10,828              2,221
Distributable income available to unitholders              $     116,510     $       27,115

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


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

Royalty Income. Royalty income to the Trust for the year ended December 31, 2012 and attributable to production from September 1, 2011 to August 31, 2012 totaled $127.3 million, representing an increase of $98.0 million over the prior year's royalty income of $29.3 million attributable to production from July 1, 2011 to August 31, 2011. This increase was primarily due to a full twelve months of production paid to unitholders in 2012 compared to two months of production in 2011. This increase was partially offset by price decreases for NGL and natural gas production. The average price


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received for NGL production of $35.01 per boe in 2012 was $11.64 lower than the average price of $46.65 per boe in 2011. In addition, prices received for natural gas production averaged $1.84 per mcf in 2012, $1.42 lower than the average price of $3.26 per mcf in 2011. The average prices received for oil production were $91.65 per barrel and $88.26 per barrel for 2012 and 2011, respectively. Although the average price received for oil production was $3.39 higher in 2012 than in 2011, this price increase was partially offset by payments to the counterparty pursuant to the Trust's oil derivative contracts.

Sales of production attributable to the Royalty Interests for the year ended December 31, 2012 were 673 mbbls of oil, 1,234 mbbls of NGL and 12,179 mmcf of natural gas as compared to production of 133 mbbls of oil, 225 mbbls of NGL and 2,172 mmcf of natural gas attributable to the Royalty Interests for the six months ended December 31, 2011. Total production attributable to the Royalty Interests for the year ended December 31, 2012 was 3,937 mboe as compared to 720 mboe for the six months ended December 31, 2011, an increase of 3,217 mboe. This increase was primarily due to the increase in the net proceeds to the Trust, which was a result of a full twelve months of activity in 2012 compared to two month of activity in 2011 as well as Chesapeake's completion of 43.6 Development Wells (as calculated under the development agreement) during 2012.

Average sales prices are net of certain post-production expenses, including gathering, storage, compression, transportation, processing, treating, dehydrating and non-affiliate marketing expenses and exclude production taxes. 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, 2012 totaled $2.7 million, or $0.69 per boe, or approximately 2.1% of royalty income, as compared to production taxes of $0.9 million, or $1.26 per boe, or approximately 3.1% of royalty income. This decrease in production tax per boe is 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 for the year ended December 31, 2012 totaled $1.7 million as compared to $1.3 million for the six months ended December 31, 2011. The increase was primarily the result of a full year of expenses in 2012 compared to six months in 2011. The increase was partially offset by the $1.0 million initial cash reserve for Trust administrative expenses established in 2011. 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 October 2011 through August 2012 production were settled, during the year ended December 31, 2012, with proceeds from royalty income for the same period. Total losses during the period were $6.4 million, or $0.14 per unit. The Trust had no settlement of swaps during the six months ended December 31, 2011.
Distributable Income. Distributable income paid to the Trust unitholders during the year ended December 31, 2012 and attributable to production from September 1, 2011 to August 31, 2012 was $116.5 million, or $2.6265 per common unit and $2.0892 per subordinated unit, which included a $1.6 million reduction for Trust administrative expenses and a cash reserve for the payment of future Trust administrative expenses. 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 was $27.1 million, or $0.5800 per common unit and subordinated unit, which included a $1.3 million reduction for Trust administrative expenses and a cash reserve for the payment of future Trust administrative expenses. Administrative expenses for a full year 2012 were only $0.3 million higher than the two month period in 2011 primarily due to the $1.0 million initial cash reserve. See Royalty Income above for discussions of price and production changes.
Development Wells. As of December 31, 2012, all of the Producing Wells were producing and approximately 55.1 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 December 31, 2012 was approximately $140.1 million. In addition, 3.0 Development Wells (as calculated under the development agreement) were drilled in the AMI and subsequently completed in January 2013. As of March 8, 2013, Chesapeake had drilled and completed, or caused to be drilled and completed, a total of 56 wells within the AMI (approximately 61.3 Development Wells as calculated under the development agreement) and the amount that could be recovered under the Drilling Support Lien was approximately $126.3 million.


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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 following is a summary of distributable income by quarter for the year ended December 31, 2012 and and six months ended December 31, 2011 (in thousands except per unit amounts):

                   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                    Q1  Q2  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 8, 2013, the Trust declared a cash distribution of $0.6700 per common unit and $0.3772 per subordinated unit, consisting of proceeds attributable to production from September 1, 2012 to November 30, 2012, to record unitholders as of February 19, 2013. The distribution was paid on March 1, 2013. The Trust's quarterly income available for distribution was $0.5968 per unit, which was $0.0732 below the subordination threshold. As a result, the distribution per common unit was equal to the subordination threshold of $0.6700 for the quarter.
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.
The Trust is not responsible for any costs related to the drilling of the Development Wells and Chesapeake granted to the Trust a lien on its interest in the AMI (except the Producing Wells and any other wells that were already producing


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as of July 1, 2011 and are not subject to the Royalty Interests) 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, 2012, 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
Contractual Obligations ($ in thousands):   Total          Year          1-3 Years       3-5 Years        Years

Trustee administrative fee                $  3,238     $       175     $       350     $       350     $    2,363
Chesapeake administrative services fee       3,700             200             400             400          2,700
Wells Fargo collateral agent fee(1)             68              23              45               -              -
Delaware Trustee administrative fee             37               2               4               4             27
Total contractual obligations             $  7,043     $       400     $       799     $       754     $    5,090

(1) Collateral agent fee extends only through September 30, 2015.

The Trust is obligated to make quarterly cash distribution of substantially all of its cash receipts, after deducting the Trust's expenses, approximately 60 days following the completion of each calendar quarter through, and including, the quarter ending June 30, 2031.
Critical Accounting Policies and Estimates

Basis of Accounting. Financial statements of the Trust differ from financial statements prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") as the Trust records revenues when received and expenses when paid and may also establish certain cash reserves for contingencies that would not be accrued in financial statements prepared in accordance with GAAP. This non-GAAP, comprehensive basis of accounting corresponds to the accounting principles permitted for royalty trusts by the Securities and Exchange Commission ("SEC") as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts. The accompanying financial statements as of December 31, 2012 and 2011 have been prepared by the Trust in accordance with the accounting policies noted below.

Investment in Royalty Interests. The conveyance of the Royalty Interests to the Trust is accounted for as a transfer of properties between entities under common control and recorded at the historical cost of Chesapeake ("Investment in Royalty Interests"), which is based on an allocation of the historical net book value of Chesapeake's full cost pool according to the fair value of the Royalty Interests relative to the fair value of Chesapeake's proved reserves. The carrying value of the Trust's Investment in Royalty Interests will not necessarily be indicative of the fair value of such Royalty Interests.

This investment is amortized as a single cost center on a units-of-production basis over total proved reserves. Such amortization does not reduce distributable income, rather it is charged directly to the Trust corpus. Revisions to estimated future units-of-production are treated on a prospective basis beginning on the date significant revisions are known.


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On a quarterly basis, the Trust evaluates the carrying value of the Investment in Royalty Interests under the full cost accounting method prescribed by the SEC. This quarterly review is referred to as a ceiling test. Under the ceiling test, the carrying value of the Investment in Royalty Interests may not exceed an amount equal to the PV-10 for the Trust's proved reserves. Any write-downs resulting from the ceiling test will be non-cash charges to the Trust corpus and will not affect distributable income.

Use of Estimates. The preparation of financial statements requires the Trust to make estimates and assumptions that affect the reported amounts of assets, liabilities and Trust corpus during the reporting period. Significant estimates that impact the Trust's financial statements include estimates of proved oil, NGL and natural gas reserves, which are used to compute the Trust's amortization of Investment in Royalty Interests and, as necessary, to evaluate potential impairment of Investment in Royalty Interests. Actual results could differ from those estimates.

Derivatives. To mitigate a portion of the exposure to adverse market changes of oil and NGL prices, the Trust is party to derivative contracts with its derivative counterparty. See Note 3 to the financial statements contained in Part II, Item 8 of this Annual Report for further discussion of the derivative contracts currently outstanding.

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