NOTES TO FINANCIAL STATEMENTS
(Unaudited)
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1.
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Organization of the Trust
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Chesapeake Granite Wash Trust (the “Trust”) is a statutory trust formed in June 2011 under the Delaware Statutory Trust Act pursuant to an initial trust agreement by and among Chesapeake Energy Corporation ("Chesapeake"), as Trustor, The Bank of New York Mellon Trust Company, N.A., as Trustee (the “Trustee”), and The Corporation Trust Company, as Delaware Trustee (the “Delaware Trustee”).
The Trust was created to own royalty interests (the “Royalty Interests”) for the benefit of Trust unitholders pursuant to a trust agreement dated as of June 29, 2011 and subsequently amended and restated as of November 16, 2011 by and among Chesapeake, Chesapeake Exploration, L.L.C., a wholly owned subsidiary of Chesapeake, the Trustee and the Delaware Trustee (the “Trust Agreement”). The Royalty Interests are derived from Chesapeake’s interests in specified oil and natural gas properties located within an area of mutual interest (the “AMI”) in the Colony Granite Wash play in Washita County in the Anadarko Basin of western Oklahoma (the “Underlying Properties”). Chesapeake conveyed the Royalty Interests to the Trust from (a) Chesapeake’s interests in 69 existing horizontal wells (the “Producing Wells”), and (b) Chesapeake’s interests in 118 horizontal development wells (the “Development Wells”) that have since been, or that are to be, drilled on properties held by Chesapeake within the AMI. Pursuant to a development agreement with the Trust, Chesapeake is obligated to drill, cause to be drilled or participate as a non-operator in the drilling of, the 118 Development Wells by 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. Chesapeake has retained an interest in each of the Producing Wells and Development Wells and currently operates
95%
of the Producing Wells and the completed Development Wells and expects to operate approximately
90%
of the remaining Development Wells.
The business and affairs of the Trust are managed by the Trustee. The Trust Agreement limits the Trust’s business activities generally to owning the Royalty Interests and any activity reasonably related to such ownership, including activities required or permitted by the terms of the conveyances related to the Royalty Interests and derivative contracts between the Trust and its counterparty. The royalty interest in the Producing Wells entitles the Trust to receive 90% of the proceeds (exclusive of any production or development costs but after deducting certain post-production expenses and any applicable taxes) from the sales of oil, natural gas liquids (“NGL”) and natural gas production attributable to Chesapeake’s net revenue interest in the Producing Wells. The royalty interest in the Development Wells entitles the Trust to receive 50% of the proceeds (exclusive of any production or development costs but 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.
Through an initial public offering in November 2011, the Trust sold to the public 23,000,000 of its common units, representing beneficial interests in the Trust, for cash proceeds of approximately $409.7 million, net of offering costs. The Trust delivered the net proceeds of the initial public offering, along with 12,062,500 common units and 11,687,500 subordinated units, to certain wholly owned subsidiaries of Chesapeake in exchange for the conveyance of the Royalty Interests to the Trust. Upon completion of these transactions, there were 46,750,000 Trust units issued and outstanding, consisting of 35,062,500 common units and 11,687,500 subordinated units. The common units and subordinated units have identical rights and privileges, except with respect to their voting rights and rights to receive distributions as described below.
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 provide a cash distribution on the common units that is no less than 80% of the target distribution for the corresponding quarter (the “subordination threshold”). If there is not sufficient cash to fund such a distribution on all of the Trust 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 the common units. 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 “incentive threshold”). The remaining 50% of cash available for distribution in excess of the applicable incentive threshold will be paid to 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
CHESAPEAKE GRANITE WASH TRUST
NOTES TO FINANCIAL STATEMENTS – (Continued)
(Unaudited)
on a one-for-one basis and Chesapeake’s right to receive incentive distributions will terminate. After such time, 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 distributable income covering production from
September 1, 2012
to
November 30, 2012
was below the subordination threshold. As a result, distributions paid in the three months ended
March 31, 2013
were
$0.6700
per common unit and
$0.3772
per subordinated unit. All of the subordinated units are held by Chesapeake. See
Risk and Uncertainties
in Note 2 below.
Neither the Trust nor the Trustee is responsible for, or has any control over, any costs related to the drilling of the Development Wells or any other operating or capital costs of the Underlying Properties. The Trust’s cash receipts with respect to the Royalty Interests in the Underlying Properties are determined after deducting certain post-production expenses and any applicable taxes associated with the Royalty Interests. 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 affiliates of Chesapeake. Cash distributions to unitholders will be increased or decreased by the effect of the Trust’s derivative contracts and reduced by the Trust’s general and administrative expenses. See
Derivative Contracts
in Note 3 below.
The Trust will dissolve and begin to liquidate on June 30, 2031, or earlier upon certain events (the “Termination Date”), and will soon thereafter wind up its affairs and terminate. At the Termination Date, (a) 50% of the total Royalty Interests conveyed by Chesapeake will revert automatically to Chesapeake and (b) 50% of the total Royalty Interests conveyed by Chesapeake (the “Perpetual Royalties”) will be retained by the Trust and thereafter sold. The net proceeds of the sale of the Perpetual Royalties, as well as any remaining Trust cash reserves, will be distributed to the unitholders on a pro rata basis. Chesapeake will have a right of first refusal to purchase the Perpetual Royalties retained by the Trust at the Termination Date.
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2.
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Basis of Presentation and Significant Accounting Policies
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Basis of Accounting
. The accompanying Statement of Assets, Liabilities and Trust Corpus as of
December 31, 2012
, which has been derived from audited financial statements, and the unaudited interim financial statements of the Trust as of, or for the three months ended,
March 31, 2013
and
March 31, 2012
, have been presented in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and include all adjustments which are, in the opinion of the Trustee, necessary for a fair statement of the results for the interim periods presented. The accompanying unaudited interim financial statements should be read in conjunction with the
December 31, 2012
audited financial statements and notes of the Trust included in the Trust’s Annual Report on Form 10-K for the year ended
December 31, 2012
.
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 which 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 SEC as specified by Staff Accounting Bulletin Topic 12:E,
Financial Statements of Royalty Trusts
.
Most accounting pronouncements apply to entities whose financial statements are prepared in accordance with GAAP, directing such entities to accrue or defer revenues and expenses in a period other than when such revenues were received or expenses were paid. Because the Trust’s financial statements are prepared on the modified cash basis as described above, most accounting pronouncements are not applicable to the Trust’s financial statements.
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 and natural gas reserves, which are used to compute the Trust’s amortization of the Investment in Royalty Interests (as defined in
Investment in Royalty Interests
below) and, as necessary, to evaluate potential impairments of Investment in Royalty Interests and of the fair value of derivatives. Actual results could differ from those estimates.
Risk and Uncertainties.
The Trust’s revenue and distributions are substantially dependent upon the prevailing and future prices for oil, NGL and natural gas, each of which depends on numerous factors beyond the Trust’s control such as economic conditions, regulatory developments and competition from other energy sources. Oil, NGL and
CHESAPEAKE GRANITE WASH TRUST
NOTES TO FINANCIAL STATEMENTS – (Continued)
(Unaudited)
natural gas prices historically have been volatile, and may be subject to significant fluctuations in the future. The Trust’s derivative contracts serve to mitigate the effect of this price volatility on a portion of the Trust’s anticipated oil and NGL production through September 30, 2015. See Note 3 for the Trust’s derivative contracts.
Additionally, the Trust’s exposure to low prices for NGL and natural gas production volumes for the production periods from
September 1, 2012
to
November 30, 2012
resulted in per unit income available for distribution below the applicable subordination threshold and, accordingly, the Trust paid 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
to
November 30, 2012
. 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.
Chesapeake’s ability to perform its obligations to the Trust will depend on its future financial condition, economic performance, access to capital, ability to sell assets and ability to comply with the financial covenants contained in its debt instruments, which in turn will depend upon the supply and demand for oil, NGL and natural gas, prevailing economic conditions and financial, business and other factors, many of which are beyond Chesapeake’s control.
If Chesapeake were to default on its obligation to drill the Development Wells, the Trust would be able to foreclose on a drilling support lien (the “Drilling Support Lien”) to the extent of Chesapeake’s remaining interests in the undeveloped portions of the AMI, file a lawsuit to collect money damages from Chesapeake and pursue other available legal remedies against Chesapeake. However, the Trust is not permitted to obtain specific performance from Chesapeake of its drilling obligation and the maximum amount the Trust can recover in a foreclosure or other action was limited to approximately
$119.2
million as of
March 31, 2013
and further reduced to
$116.5
million as of
May 1, 2013
. The maximum amount that may be recovered under the Drilling Support Lien will decrease as the remaining Development Wells are drilled and completed.
Delays and expenses associated with a foreclosure could reduce distributions to the Trust unitholders by reducing the amount of proceeds available for distribution and may result in the loss of acreage due to leasehold expirations. Any amounts actually recovered in a foreclosure action would be applied to completion of Chesapeake’s drilling obligation, would not result in any distribution to the Trust unitholders and may be insufficient to drill the number of wells needed for the Trust to realize the full value of the Royalty Interests in the Development Wells.
In the event of a bankruptcy of Chesapeake or the wholly owned subsidiaries of Chesapeake that conveyed the Royalty Interests to the Trust, the Trust could lose the value of all of the Royalty Interests if a bankruptcy court were to hold that the Royalty Interests constitute an asset of the bankruptcy estate. Chesapeake could also be unable to provide support to the Trust through loans and performance of its management duties.
Cash
. Cash equivalents include all highly liquid instruments with maturities of three months or less at the time of acquisition. The Trustee maintains a minimum cash reserve of $1.0 million and may at the Trustee’s discretion reserve funds for future expected administrative expenses.
Investment in Royalty Interests
. The conveyance of the Royalty Interests to the Trust was 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. The Trust is not burdened by development costs of the Royalty Interests.
The Investment in Royalty Interests 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 Trust corpus. Revisions to estimated future units-of-production are treated on a prospective basis beginning on the date such revisions are known.
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 sum of the present value (using a 10% discount rate) of the estimated future net revenues from proved reserves. During the current quarter's evaluation, the carrying value of the Investment in Royalty Interests exceeded the estimated present
CHESAPEAKE GRANITE WASH TRUST
NOTES TO FINANCIAL STATEMENTS – (Continued)
(Unaudited)
value calculation of future net revenues from proved reserves, resulting in a $32.9 million impairment in the carrying value of the Investment in Royalty Interests.
The impairment was the result of reserve revisions that were due to current results 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 results in a non-cash charge to the Trust corpus and does not affect the Trust's distributable income.
Derivatives.
To mitigate a portion of the exposure to adverse market changes of oil prices and, to the extent oil production falls below the hedged oil volume, NGL prices, the Trust is party to derivative contracts with its hedge counterparty. See Note 3 for discussion of the derivative contracts currently outstanding.
The Trust records gains or losses from the derivative contracts when proceeds are received or payments are made, respectively. Additionally, changes in the fair value of the derivative contracts are accounted for as an adjustment to Trust corpus and the fair value carried on the statement of assets, liabilities and trust corpus.
Loan Commitment
. Pursuant to the Trust Agreement, if at any time the Trust’s cash on hand (including available 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. Such loans will be recorded as a liability on the statement of assets, liabilities and trust corpus until repaid. Loans neither increase or decrease distributions to unitholders, however, 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, 2013 or December 31, 2012.
Revenues and Expenses.
Revenues received by the Trust are net of existing royalties and overriding royalties associated with Chesapeake’s interests and are reduced by certain post-production expenses, production taxes and other allowable expenses, such as the Trust’s administrative expenses, in order to determine distributable income. The Royalty Interests are not burdened by field and lease operating expenses.
The Trust uses derivative instruments to manage its exposure to variability in cash flow from changes in oil prices and, to the extent oil production falls below hedged oil volume, NGL prices. On November 16, 2011, Chesapeake novated the derivative contracts described in the table below to the Trust pursuant to which the Trust became party to derivative contracts covering a portion of its expected production from October 1, 2011 through September 30, 2015. These derivative contracts consist of fixed-price oil swaps, in which the Trust receives a fixed price and pays a floating market price, based on New York Mercantile Exchange (“NYMEX”) settlement prices, to the counterparty for the underlying commodity of the derivative. As a party to these contracts, the Trust receives payments directly from its counterparty or is required to pay any amounts owed directly to the counterparty. All swaps are net settled based on the difference between the fixed-price payment and the floating-price payment. Settlements are due on a quarterly basis, including the first two months of the calendar quarter just ended and the last month of the calendar quarter prior to that one. Any payment due to or from such counterparty will be made by the 40th day following the end of the calendar quarter in which such payments become due.
The Trust’s obligations to the counterparty under the derivative contracts are secured by liens on proved reserves attributable to the Trust’s interest in the Underlying Properties. The counterparty’s obligations under the hedge facility must be secured by cash or short-term U.S. Treasury instruments to the extent that any mark-to-market amounts owed to the Trust exceeds defined thresholds. Mark-to-market amounts did not exceed the defined thresholds as of
March 31, 2013
.
CHESAPEAKE GRANITE WASH TRUST
NOTES TO FINANCIAL STATEMENTS – (Continued)
(Unaudited)
As of
March 31, 2013
, the Trust had the following oil derivative contracts:
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Fixed-Price Oil Swaps
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Production Quarter
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Volume
(mbbl)
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Weighted
Avg. Price
(per bbl)
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Fair Value
($ in thousands)
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Q4 2012
(1)
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62.1
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$87.28
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$
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(341
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)
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Q1 2013
(2)
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182.2
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$87.37
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(987
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)
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Q2 2013
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184.3
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$87.60
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(1,629
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)
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Q3 2013
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187.9
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$87.79
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(1,741
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)
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Q4 2013
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184.2
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$87.99
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(1,437
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)
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Q1 2014
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179.8
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$88.08
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(1,117
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)
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Q2 2014
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180.3
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$88.21
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(873
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)
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Q3 2014
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178.8
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$88.34
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(681
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)
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Q4 2014
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174.3
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$88.45
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(504
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)
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Q1 2015
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171.0
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$88.59
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(317
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)
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Q2 2015
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175.4
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$88.76
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(146
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)
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Q3 2015
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153.6
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$88.90
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(9
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)
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Total
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2,013.9
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$88.14
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$
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(9,782
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)
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_______________________________________________________
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(1)
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Includes December 2012 production that was settled in May 2013.
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(2)
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Includes January and February 2013 production that was settled in May 2013.
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To the extent expected oil production falls below the hedged oil volume, the derivative contracts will also cover expected NGL production. Such estimated production of NGL is hedged with oil contracts using a conversion ratio of one barrel of NGL to 49.2% of a barrel of oil. In 2012 and continuing in early 2013, NGL prices decreased relative to oil prices. To the extent oil and NGL prices are not correlated, the derivative contracts will not effectively mitigate the price risk of the Trust’s NGL production.
Additional Disclosures Regarding Derivative Contracts
In accordance with accounting guidance for derivatives and hedging, and because a legal right of set-off exists, the Trust has netted the value of its derivative contracts with the counterparty in the accompanying statement of assets, liabilities and trust corpus. Short-term derivative liability represents the estimated fair value of derivatives scheduled to settle in cash over the next twelve months based on market prices as of
March 31, 2013
. The Trust does not apply hedge accounting to any of its derivative contracts, and therefore, any changes in the fair value of the derivative contracts prior to settlement will be accounted for as an adjustment to Trust corpus. Results of settled derivative contracts are reflected in distributable income in the period when paid. For the three months ended
March 31, 2013
and March 31, 2012, the Trust settled derivative contracts that resulted in a payment to the counterparty of
$0.6 million
and $0.8 million, respectively.
CHESAPEAKE GRANITE WASH TRUST
NOTES TO FINANCIAL STATEMENTS – (Continued)
(Unaudited)
The following table presents the fair value and location of each classification of derivative contracts disclosed in the statements of assets, liabilities and trust corpus as of March 31, 2013 and December 31, 2012 on a gross basis without regard to same-counterparty netting:
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Fair Value
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Statement of Assets, Liabilities and Trust Corpus Location
|
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March 31,
2013
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December 31, 2012
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($ in thousands)
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Asset Derivatives:
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Not designated as hedging instrument
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Commodity contracts
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Short-term derivative liability
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$
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—
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$
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212
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Commodity contracts
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Long-term derivative liability
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548
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|
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411
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Total
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548
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|
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623
|
|
|
|
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|
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Liability Derivatives:
|
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|
|
|
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Not designated as hedging instrument
|
|
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|
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Commodity contracts
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Short-term derivative liability
|
|
(5,717
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)
|
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(3,488
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)
|
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Commodity contracts
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Long-term derivative liability
|
|
(4,613
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)
|
|
(5,219
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)
|
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Total
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(10,330
|
)
|
|
(8,707
|
)
|
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Total derivatives instruments
|
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$
|
(9,782
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)
|
|
$
|
(8,084
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)
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All of the Trust’s derivative positions are subject to netting arrangements which provide for offsetting of asset and liability positions, as well as related cash collateral if applicable. Such netting arrangements generally do not have restrictions. Under such netting arrangements, the Trust offsets the fair value of derivative instruments with cash collateral received or paid for those contracts executed with the same counterparty, which reduces the Trust’s total assets and Trust corpus. As of March 31, 2013 and December 31, 2012, the Trust did not have any cash collateral balances for these derivatives.
The following tables present the netting offsets of derivative assets and liabilities as of March 31, 2013 and December 31, 2012.
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|
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|
|
March 31, 2013
|
|
|
Derivative Assets
|
|
Derivative Liabilities
|
|
|
Short-term
|
|
Long-Term
|
|
Short-term
|
|
Long-Term
|
|
|
($ in thousands)
|
|
Commodity contracts:
|
|
|
|
|
|
|
|
|
Gross amounts of recognized assets (liabilities)
|
$
|
—
|
|
|
$
|
548
|
|
|
$
|
(5,717
|
)
|
|
$
|
(4,613
|
)
|
|
Gross amounts offset in the statement of assets,
liabilities and trust corpus
|
—
|
|
|
(548
|
)
|
|
—
|
|
|
548
|
|
|
Total derivatives as reported
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(5,717
|
)
|
|
$
|
(4,065
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2012
|
|
|
Derivative Assets
|
|
Derivative Liabilities
|
|
|
Short-term
|
|
Long-Term
|
|
Short-term
|
|
Long-Term
|
|
|
($ in thousands)
|
|
Commodity contracts:
|
|
|
|
|
|
|
|
|
Gross amounts of recognized assets (liabilities)
|
$
|
212
|
|
|
$
|
411
|
|
|
$
|
(3,488
|
)
|
|
$
|
(5,219
|
)
|
|
Gross amounts offset in the statement of assets,
liabilities and trust corpus
|
(212
|
)
|
|
(411
|
)
|
|
212
|
|
|
411
|
|
|
Total derivatives as reported
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(3,276
|
)
|
|
$
|
(4,808
|
)
|
The Trust is a Delaware statutory trust that is treated as a partnership for U.S. federal income tax purposes. The Trust is not required to pay federal or state income taxes. Accordingly, no provision for federal or state income tax has been made.
Trust unitholders are treated as partners of the Trust for U.S. federal income tax purposes. The Trust Agreement contains tax provisions that generally allocate the Trust’s income, deductions and credits among the Trust unitholders in accordance with their percentage interests in the Trust. The Trust Agreement also sets forth the tax accounting principles to be applied by the Trust.
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5.
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Related Party Transactions
|
Trustee Administrative Fee
. Under the terms of the Trust Agreement, the Trust pays an annual administrative fee of $175,000 to the Trustee, paid in equal quarterly installments. The administrative fee may be adjusted for inflation by no more than 3% in any calendar year beginning in 2015.
Agreements with Chesapeake.
In connection with the initial public offering and the conveyance of the Royalty Interests to the Trust, the Trust entered into an administrative service agreement, a development agreement and a registration rights agreement with Chesapeake.
Pursuant to the administrative services agreement, Chesapeake provides the Trust with certain accounting, tax preparation, bookkeeping and information services related to the Royalty Interests and the registration rights agreement. In return for the services provided by Chesapeake under the administrative services agreement, the Trust pays Chesapeake, in equal quarterly installments, an annual fee of $200,000, which will remain fixed for the life of the Trust. Chesapeake is also entitled to receive reimbursement for its actual out-of-pocket fees, costs and expenses incurred in connection with the provision of any of the services under the agreement.
Additionally, the administrative services agreement established Chesapeake as the Trust’s hedge manager, pursuant to which Chesapeake has the authority, on behalf of the Trust, to administer the Trust’s derivative contracts. As hedge manager, Chesapeake also has authority to terminate, restructure or otherwise modify all or any portion of the derivative contracts to the extent that Chesapeake reasonably determines, acting in good faith, that the volumes hedged under such contracts exceed, or are expected to exceed, the combined estimated production attributable to the Royalty Interests over the periods hedged. However, in fulfilling its role as hedge manager, Chesapeake does not act as a fiduciary for the Trust and has no affirmative duty to modify any of the Trust’s derivative contracts, except as required by the derivative contracts and the administrative services agreement. Moreover, the Trust will indemnify Chesapeake for any actions it takes in this regard.
The administrative services agreement will terminate upon the earliest to occur of (a) the date the Trust shall have dissolved and wound up its business and affairs in accordance with the Trust Agreement, (b) the date that all of the Royalty Interests have been terminated or are no longer held by the Trust, (c) with respect to services to be provided with respect to any Underlying Properties being transferred by Chesapeake, the date that either Chesapeake or the Trustee may designate by delivering 90-days prior written notice, provided that Chesapeake’s drilling obligation has been completed and the transferee of such Underlying Properties assumes responsibility to perform the services in place of Chesapeake or (d) a date mutually agreed by Chesapeake and the Trustee.
The development agreement obligates Chesapeake to drill, cause to be drilled or participate as a non-operator in the drilling of the Development Wells 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. Chesapeake has also agreed not to drill and complete, or permit any other person within its control to drill and complete, any well in the AMI other than the Development Wells until Chesapeake has met its obligation to drill the Development Wells.
In drilling the Development Wells, Chesapeake is required to act diligently and as a reasonably prudent oil and gas operator would act under the same or similar circumstances as if it were acting with respect to its own properties, disregarding the existence of the Royalty Interests as burdens affecting such properties (the “Reasonably Prudent Operator Standard”). Where Chesapeake does not operate the Underlying Properties, Chesapeake is required to use commercially reasonable efforts to exercise its contractual rights to cause the operators of such Underlying Properties to adhere to the Reasonably Prudent Operator Standard. Chesapeake expects that the drilling and completion
CHESAPEAKE GRANITE WASH TRUST
NOTES TO FINANCIAL STATEMENTS – (Continued)
(Unaudited)
techniques used for the Development Wells will be generally consistent with those used for the Producing Wells, the existing Development Wells, and other Colony Granite Wash producing wells outside of the AMI.
Under the development agreement, Chesapeake will be credited for drilling one full Development Well if the perforated length of the well is equal to or greater than 3,500 feet and Chesapeake’s net revenue interest in the well is equal to 52.0%. For wells with a perforated length that is less than 3,500 feet, and for wells in which Chesapeake has a net revenue interest greater than or less than 52.0%, Chesapeake receives proportionate credit.
A wholly owned subsidiary of Chesapeake has granted to the Trust the Drilling Support Lien covering Chesapeake’s retained interest in the AMI (except its interest in the Producing Wells, Development Wells and any other wells 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. The maximum amount that may be obtained by the Trust pursuant to the Drilling Support Lien initially could not exceed $262.7 million. As Chesapeake fulfills its drilling obligation over time, the total amount that may be recovered will be proportionately reduced and the completed Development Wells will be released from the lien. If Chesapeake does not fulfill its drilling obligation by June 30, 2016, the Trust may foreclose on any remaining interest in the AMI that is subject to the Drilling Support Lien. Any amounts actually recovered in a foreclosure action would be applied to the completion of Chesapeake’s drilling obligation and would not result in any distribution to the Trust unitholders.
Chesapeake’s drilling activity with respect to the Development Wells is consistent with its intent to meet the drilling obligation contemplated by the development agreement. As of
May 1, 2013
, Chesapeake had drilled and completed, or caused to be drilled or completed, a total of
60
wells in the AMI (approximately
65.7
Development Wells as calculated under the development agreement), reducing the amount that may be recovered under the Drilling Support Lien to approximately
$116.5
million.
The Trust also entered into a registration rights agreement for the benefit of Chesapeake and certain of its affiliates (each, a “holder”). Pursuant to the registration rights agreement, the Trust agreed to register the Trust units held by each such holder for resale under the Securities Act of 1933, as amended. In connection with the preparation and filing of any registration statement, Chesapeake will bear all costs and expenses incidental to any registration statement, excluding certain internal expenses of the Trust, which will be borne by the Trust, and any underwriting discounts and commissions, which will be borne by the seller of the Trust units.
Loan Commitment
. Pursuant to the Trust Agreement, if at any time the Trust’s cash on hand (including available 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, 2013 or December 31, 2012.
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6.
|
Fair Value Measurement
|
Certain financial instruments are reported at fair value on the statement of assets, liabilities and trust corpus. Under fair value measurement accounting guidance, fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants, i.e., an exit price. To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 inputs are inputs other than quoted prices within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the financial asset or liability and have the lowest priority. The Trust uses a market valuation approach based on available inputs and the following methods and assumptions to measure the fair values of its assets and liabilities, which may or may not be observable in the market.
Derivatives.
The fair value of our derivatives is based on third-party pricing models which utilize inputs that are either readily available in the public market, such as oil forward curves and discount rates, or can be corroborated from active markets or broker quotes. These values are then compared to the values given by our counterparty for
CHESAPEAKE GRANITE WASH TRUST
NOTES TO FINANCIAL STATEMENTS – (Continued)
(Unaudited)
reasonableness. Since commodity swaps do not include optionality and therefore have no unobservable inputs, they are classified as Level 2.
The following table provides fair value measurement information for financial assets (liabilities) measured at fair value on a recurring basis as of
March 31, 2013
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quoted
Prices in
Active
Markets
(Level 1)
|
|
Significant
Other
Observable
Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
|
Total
Fair Value
|
|
|
($ in thousands)
|
|
Financial Assets (Liabilities):
|
|
|
|
|
|
|
|
|
Derivative liabilities
|
$
|
—
|
|
|
$
|
(9,782
|
)
|
|
$
|
—
|
|
|
$
|
(9,782
|
)
|
|
Total
|
$
|
—
|
|
|
$
|
(9,782
|
)
|
|
$
|
—
|
|
|
$
|
(9,782
|
)
|
The following table provides fair value measurement information for financial assets (liabilities) measured at fair value on a recurring basis as of
December 31, 2012
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quoted
Prices in
Active
Markets
(Level 1)
|
|
Significant
Other
Observable
Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
|
Total
Fair Value
|
|
|
($ in thousands)
|
|
Financial Assets (Liabilities):
|
|
|
|
|
|
|
|
|
Derivative liabilities
|
$
|
—
|
|
|
$
|
(8,084
|
)
|
|
$
|
—
|
|
|
$
|
(8,084
|
)
|
|
Total
|
$
|
—
|
|
|
$
|
(8,084
|
)
|
|
$
|
—
|
|
|
$
|
(8,084
|
)
|
Fair Value of Other Financial Instruments.
The estimated fair value of financial instruments is made in accordance with accounting guidance for financial instruments. The carrying values of financial instruments comprising cash and cash equivalents approximate fair values due to the short-term maturities of these instruments.
|
|
|
|
7.
|
Distributions to Unitholders
|
The Trust makes quarterly cash distributions of substantially all of its cash receipts, after deducting the Trust’s expenses, approximately 60 days following the completion of each quarter through (and including) the quarter ending June 30, 2031.
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
through
November 30, 2012
, to record unitholders as of
February 19, 2013
. The distribution was paid on
March 1, 2013
.
On
February 8, 2012
, the Trust declared a cash distribution of
$0.7277
per common and subordinated unit, consisting of proceeds attributable to production from
September 1, 2011
through
November 30, 2011
, to record unitholders as of
February 20, 2012
. The distribution was paid on
March 1, 2012
.