CHKR 10-Q Quarterly Report Sept. 30, 2017 | Alphaminr
CHESAPEAKE GRANITE WASH TRUST
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CHKR 10-Q Quarter ended Sept. 30, 2017

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CHESAPEAKE GRANITE WASH TRUST
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10-Q 1 chkr-2017x930x10q.htm 10-Q Document





UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X]    Quarterly Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the Quarterly Period Ended September 30, 2017
[ ]    Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from to .

Commission File No. 001-35343
Chesapeake Granite Wash Trust
(Exact name of registrant as specified in its charter)
Delaware
45-6355635
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
The Bank of New York Mellon
Trust Company, N.A., Trustee
Global Corporate Trust
919 Congress Avenue
Austin, Texas
78701
(Address of principal executive offices)
(Zip Code)
(512) 236-6555
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes [X] No [ ]
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes [ ] No [ ]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer," “accelerated filer,” “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer [ ]
Accelerated filer [ ]
Non-accelerated filer [X]
Smaller reporting company [ ]
Emerging growth company [ ]
(Do not check if a smaller
reporting company)
If an emerging growth company indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial account standards provided pursuant to Section 13 (a) of the Exchange Act. [ ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes [ ] No [X]
As of November 6, 2017 , 46,750,000 Common Units representing beneficial interests in Chesapeake Granite Wash Trust were outstanding.


CHESAPEAKE GRANITE WASH TRUST
INDEX TO FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 30, 2017

All references to “we,” “us,” “our,” or the “Trust” refer to Chesapeake Granite Wash Trust. The royalty interests conveyed on November 16, 2011 by Chesapeake from its interests in certain properties in the Colony Granite Wash formation in Oklahoma and held by the Trust are referred to as the “Royalty Interests.” References to “Chesapeake” refer to Chesapeake Energy Corporation and, where the context requires, its subsidiaries.




DISCLOSURES REGARDING FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q (“Quarterly Report”) includes “forward-looking statements” about the Trust and Chesapeake and other matters discussed herein that are subject to risks and uncertainties that are intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995 and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements other than statements of historical fact included in this document, including, without limitation, statements under “Trustee’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 2 of Part I and elsewhere herein regarding the proved oil, natural gas and natural gas liquids ("NGL") reserves associated with the properties underlying the Royalty Interests, the Trust’s or Chesapeake’s future financial position, business strategy, budgets, projected costs and plans and objectives for future operations, information regarding target distributions, statements pertaining to future development activities and costs and information regarding production and reserve growth, are forward-looking statements. Actual outcomes and results may differ materially from those projected. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal,” “assume,” “target,” “should,” “intend” or other words that convey the uncertainty of future events or outcomes. These statements are based on certain assumptions made by the Trust, and by Chesapeake in light of its experience and perception of historical trends, current conditions and expected future developments, as well as other factors we believe are appropriate under the circumstances. However, whether actual results and developments will conform with such expectations and predictions is subject to a number of risks and uncertainties, including the risk factors discussed in Item 1A of Part I of the Trust’s Annual Report on Form 10-K for the year ended December 31, 2016 (the "2016 Form 10-K") and those set forth from time to time in the Trust’s filings with the Securities and Exchange Commission (the "SEC"), which could affect the future results of the energy industry in general, and the Trust and Chesapeake in particular, and could cause those results to differ materially from those expressed in such forward-looking statements. The actual results or developments anticipated may not be realized or, even if substantially realized, they may not have the expected consequences to or effects on Chesapeake’s business and the Trust. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in such forward-looking statements. The Trustee relies on Chesapeake for information regarding the Royalty Interests, the Underlying Properties and Chesapeake itself. The Trust undertakes no obligation to publicly update or revise any forward-looking statements, except as required by applicable law.





PART I. FINANCIAL INFORMATION
ITEM 1.
Financial Statements
CHESAPEAKE GRANITE WASH TRUST
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
(Unaudited)

September 30, 2017
December 31,
2016
($ in thousands)
ASSETS:
Cash and cash equivalents
$
1,358

$
1,215

Investment in royalty interests
487,793

487,793

Less: accumulated amortization and impairment
(460,490
)
(457,070
)
Net investment in royalty interests
27,303

30,723

Total assets
$
28,661

$
31,938

LIABILITIES AND TRUST CORPUS:
Total liabilities
$
—

$
—

Trust Corpus; 46,750,000 common units issued and outstanding at September 30, 2017 and 35,062,500 common units and 11,687,500 subordinated units issued and outstanding December 31, 2016
28,661

31,938

Total liabilities and Trust corpus
$
28,661

$
31,938












The accompanying notes are an integral part of these financial statements.

1

CHESAPEAKE GRANITE WASH TRUST
STATEMENTS OF DISTRIBUTABLE INCOME
(Unaudited)

Three Months Ended
September 30,
Nine Months Ended
September 30,
2017
2016
2017
2016
($ in thousands, except unit and per unit data)
REVENUES:
Royalty income
$
3,939

$
2,608

$
12,245

$
9,041

INCOME (EXPENSES):
Production taxes
(185
)
(79
)
(556
)
(317
)
Trust administrative expenses
(236
)
45

(1,451
)
(1,354
)
Derivative settlement gain
—

—

—

2,109

Total income (expenses)
(421
)
(34
)
(2,007
)

438

Distributable income available to unitholders
$
3,518

$
2,574

$
10,238

$
9,479

Distributable income per common unit (46,750,000 common units at September 30, 2017 and 35,062,500 common units at September 30, 2016) (a)
$
0.1003

$
0.0734

$
0.2920


$
0.2704

Distributable income per subordinated unit (0 subordinated units at September 30, 2017 and 11,687,500 subordinated units at September 30, 2016
$
—

$
—

$
—

$
—


(a) Distributable income per common unit for the three and nine month periods ended September 30, 2017 was based upon 35,062,500 common units and excluded the common units issued on June 30, 2017 upon conversion of the Trust's subordinated units. See Note 6 to the financial statements contained in Item 1 of Part I of this Quarterly Report.


CHESAPEAKE GRANITE WASH TRUST
STATEMENTS OF CHANGES IN TRUST CORPUS
(Unaudited)

Nine Months Ended
September 30,
2017
2016
($ in thousands)
TRUST CORPUS: Beginning of period
$
31,938

$
63,216

Cash reserve surplus
144

229

Amortization of investment in royalty interests
(3,421
)
(5,387
)
Impairment of investment in royalty interests
—

(22,984
)
Change in derivative asset and liability
—

(2,109
)
Distributable income
10,238

9,479

Distributions paid to unitholders
(10,238
)
(9,479
)
TRUST CORPUS: End of period
$
28,661

$
32,965



The accompanying notes are an integral part of these financial statements.

2

CHESAPEAKE GRANITE WASH TRUST
NOTES TO FINANCIAL STATEMENTS
(Unaudited)

1.
Organization of the Trust
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 drilled on properties held by Chesapeake within the AMI. Pursuant to a development agreement with the Trust, Chesapeake was 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 was obligated to either complete and tie into production or plug and abandon each Development Well. Chesapeake retained an interest in each of the Producing Wells and Development Wells and currently operates 96% of the Producing Wells and the completed Development Wells. As of June 30, 2016, Chesapeake had fulfilled its drilling obligation under the development agreement.
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. The royalty interests in the Producing Wells entitle 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 and NGL production attributable to Chesapeake’s net revenue interest in the Producing Wells. The royalty interests in the Development Wells entitle 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, natural gas and NGL 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 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 had identical rights and privileges, except with respect to their voting rights and rights to receive distributions as described below.
Prior to their conversion on June 30, 2017, the subordinated units were entitled to receive pro rata distributions from the Trust each quarter if and to the extent there was sufficient cash to provide a cash distribution on the common units that was no less than 80% of the target distribution set forth in the Trust Agreement for the corresponding quarter (the “subordination threshold”). If there was insufficient cash to fund such a distribution on all of the Trust units, the distribution made with respect to the subordinated units was either 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. Prior to the conversion of the subordinated units on June 30, 2017, Chesapeake was 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 was 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, if any, was paid to Trust unitholders, including Chesapeake, on a pro rata basis.



3

CHESAPEAKE GRANITE WASH TRUST
NOTES TO FINANCIAL STATEMENTS - (Continued)
(Unaudited)

On June 30, 2017, the last day of the fourth full calendar quarter subsequent to Chesapeake's satisfaction of its drilling obligation, the subordinated units automatically converted into common units on a one-for-one basis and Chesapeake's right to receive incentive distributions with respect to quarters after the 2017 second quarter terminated. All distributions made on common units scheduled to be made after September 30, 2017 will no longer have the benefit of the subordination threshold, nor are the common units subject to the incentive threshold, and all Trust unitholders share on a pro rata basis in the Trust's distributions.
The distribution for the quarter ended June 30, 2017 which was paid on August 31, 2017, was still subject to the subordination threshold. As a result, distributable income available to unitholders for the three and nine months ended September 30, 2017 is still subject to the subordination threshold. As such, distributable income per common unit as of September 30, 2017 is based upon the 35,062,500 common units (see Note 6). Beginning with the distribution scheduled for November 30, 2017 the distributable income available to unitholders will be based on the 46,750,000 common units that are currently outstanding (see Note 7).
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.
2.
Basis of Presentation and Significant Accounting Policies
Basis of Accounting .  The accompanying Statement of Assets, Liabilities and Trust Corpus as of December 31, 2016 and the unaudited interim financial statements of the Trust as of and for the three and nine months ended September 30, 2017 and 2016 have been presented in accordance with the rules and regulations of the SEC and include all adjustments which are, in the opinion of the Trustee, necessary to fairly state the Trust's financial position and results of operations for the periods presented. The accompanying unaudited interim financial statements should be read in conjunction with the December 31, 2016 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, 2016 . These financial statements have been prepared in accordance with the SEC instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with accounting principles generally accepted in the United States of America (GAAP).
Financial statements of the Trust differ from financial statements prepared in accordance with 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, natural gas and NGL 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. Actual results could differ from those estimates.
Risks and Uncertainties. The Trust’s revenue and distributions are substantially dependent upon the prevailing and future prices for oil, natural gas and NGL, 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, natural gas and NGL prices historically have been volatile, and may be subject to significant fluctuations in the future. The Trust’s derivative contracts, which were only in effect through September 30, 2015, served to mitigate the effect of this price volatility on a portion of the Trust’s anticipated oil and NGL production. Beginning October 1, 2015, all of the production attributable to the Trust's Royalty Interests is subject to market prices and currently there are no derivative contracts. See Note 3 for a discussion of the Trust’s former derivative contracts.
The Trust’s income available for distribution throughout 2016 and to date in 2017 has been adversely affected by several factors. The Trust's revenues and distributable income available to unitholders have been and will continue to


4

CHESAPEAKE GRANITE WASH TRUST
NOTES TO FINANCIAL STATEMENTS - (Continued)
(Unaudited)

be adversely affected if commodity prices remain at current levels or decline further. For each of the quarterly production periods from September 1, 2016 to November 30, 2016, December 1, 2016 to February 28, 2017 and March 1, 2017 to May 31, 2017, the Trust's calculated distribution per common unit was below the applicable subordination threshold, and no subordinated distribution was paid. On November 7, 2017 , the Trust declared a cash distribution of $0.0657 per common unit (the "November 2017 Distribution"), consisting of proceeds attributable to production from June 1, 2017 to August 31, 2017 . The distribution will be paid on November 30, 2017 to common unitholders of record as of November 20, 2017 . See Note 6 for information regarding prior distributions paid and Note 7 for information on the November 2017 Distribution. On June 30, 2017, the subordinated units automatically converted into common units on a one-for-one basis. Distributions no longer have the benefit of the subordination threshold, nor are the common units subject to the incentive threshold, and all Trust unitholders share on a pro rata basis in the Trust’s distributions.
During the nine months ended September 30, 2017 , none of the distributable income available to common unitholders was attributable to derivative settlement gains or hedging activities. As disclosed in Note 3 below, the derivative contracts were initially novated to the Trust in November 2011 and covered a portion of the production attributable to the Royalty Interests from October 1, 2011 through September 30, 2015 but did not cover any production subsequent to September 30, 2015. Settlement of these derivative contracts was concluded as of February 2016.
Chesapeake's ability to perform its obligations to the Trust depend on its future results of operations, financial condition and liquidity, which in turn depend upon the supply and demand for oil, natural gas and NGL, prevailing economic conditions and financial, business and other factors, many of which are beyond Chesapeake's control.
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 and Cash Equivalents .  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 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. 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.
On a quarterly basis, the Trust evaluates the carrying value of the Investment in Royalty Interests under the full cost accounting rules of 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. In the three and nine months ended September 30, 2017 , the Trust recognized no impairments of the Royalty Interests. In the three and nine months ended September 30, 2016 , the Trust recognized approximately $8.2 million and $23.0 million , respectively, in impairments to the carrying value of the Investment in Royalty Interests, primarily due to a decrease in commodity prices used to calculate the proved reserves attributable to the Trust's interest in the Underlying Properties. The impairments resulted in non-cash charges to Trust corpus and did not affect the Trust's distributable income.
Derivatives. To mitigate a portion of the exposure to adverse market changes of oil prices, the Trust had derivative contracts covering a portion of oil production through September 30, 2015. See Note 3 for discussion of the Trust's former derivative contracts.
The Trust recorded gains or losses from the derivative contracts when proceeds were received or payments were made, respectively. Additionally, changes in the fair value of the derivative contracts were accounted for as an adjustment to Trust corpus and the fair value carried on the Statements of Assets, Liabilities and Trust Corpus. Cash distributions to unitholders were increased or decreased by settlements of the Trust's derivative contracts. All of the Trust's derivative contracts expired on September 30, 2015 and as of February 2016, the Trust had settled all derivative contracts.


5

CHESAPEAKE GRANITE WASH TRUST
NOTES TO FINANCIAL STATEMENTS - (Continued)
(Unaudited)

Fair Value of Other Financial Instruments. The estimated fair value of other 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.
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 Statements of Assets, Liabilities and Trust Corpus until repaid. A loan neither increases nor decreases distributions to unitholders; however, no further distributions will be made to unitholders (except in respect of any previously determined quarterly cash distribution amount and unless Chesapeake otherwise agrees) until the loan is repaid. There were no loans outstanding as of September 30, 2017 or December 31, 2016.
Revenues and Expenses. 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 revenues with respect to the Royalty Interests in the Underlying Properties are net of existing royalties and overriding royalties associated with Chesapeake's interests and 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, natural gas and NGL produced. However, the Trust is not responsible for costs of marketing services provided by affiliates of Chesapeake. Cash distributions to unitholders are reduced by the Trust’s general and administrative expenses.
3.
Derivative Contracts
The Trust's derivative contracts were intended to manage its exposure to adverse changes in oil prices. On November 16, 2011, Chesapeake novated certain derivative contracts 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 consisted of fixed-price oil swaps in which the Trust received a fixed price and paid a floating market price based on New York Mercantile Exchange settlement prices to the counterparty for the underlying commodity of the derivative. As a party to these contracts, the Trust received payments directly from its counterparty or was required to pay any amounts owed directly to the counterparty. All swaps were net settled based on the difference between the fixed-price payment and the floating-price payment. All of the Trust's derivative contracts expired on September 30, 2015 and as of February 2016, the Trust had settled all derivative contracts. For the nine months ended September 30, 2016 , the Trust settled derivative contracts that resulted in receipts from the counterparty of $2.1 million .
4.
Income Taxes
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.
5.
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. A 2.1% adjustment has been made for the 2017 calendar year for inflation.
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 services agreement, a development agreement and a registration rights agreement with Chesapeake.


6

CHESAPEAKE GRANITE WASH TRUST
NOTES TO FINANCIAL STATEMENTS - (Continued)
(Unaudited)

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 had the authority, on behalf of the Trust, to administer the Trust’s derivative contracts. All of the Trust's derivative contracts expired on September 30, 2015.
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 transferred by Chesapeake to a third party, 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 upon by Chesapeake and the Trustee.
Pursuant to the development agreement with the Trust, Chesapeake was obligated to drill, cause to be drilled or participate as a non-operator in the drilling of the 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 was obligated to either complete and tie into production or plug and abandon each Development Well. Chesapeake 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 met its obligation to drill the Development Wells. As of June 30, 2016, Chesapeake had fulfilled its drilling obligation under the development agreement.
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 September 30, 2017 or December 31, 2016.









7

CHESAPEAKE GRANITE WASH TRUST
NOTES TO FINANCIAL STATEMENTS - (Continued)
(Unaudited)

6.
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.
For the nine months ended September 30, 2017 and 2016, the Trust declared and paid the following cash distributions:
Cash Distribution per
Common Unit
Production Period
Distribution
Date
Public Unitholders Other Than Chesapeake
Chesapeake
Cash Distribution per Subordinated Unit
March 2017 - May 2017 (a)
August 31, 2017
$
0.1003

$
0.1003

$
—

December 2016 - February 2017
June 1, 2017
$
0.1005

$
0.1005

$
—

September 2016 - November 2016
March 2, 2017
$
0.0912

$
0.0912

$
—

March 2016 - May 2016
August 29, 2016
$
0.0734

$
0.0734

$
—

December 2015 - February 2016
May 31, 2016
$
0.0403

$
0.0403

$
—

September 2015 - November 2015 (b)
March 1, 2016
$
0.2195

$
0.0369

$
—

___________________________________________________
(a)
Following the Trust's press release dated August 4, 2017, the Trust identified an additional $190,000 to be included in distributable income available to unitholders. The Trust announced a revision to the distribution amount on August 11, 2017. Based upon the revised sales volume and average pricing calculations, the distribution of $0.1003 per common unit, which was calculated on the basis of 35,062,500 common units and excluded the common units issued on June 30, 2017 upon conversion of the Trust's subordinated units, was paid on August 31, 2017.
(b)
In its press release dated February 4, 2016, the Trust incorrectly announced that the distributable income for the quarter ended December 31, 2015 was $0.2195 per common unit. Chesapeake advised the Trust that Chesapeake included an incorrect amount for the derivative settlement gain in the prior calculation of distributable income. Chesapeake elected to waive its right to the higher distribution on common units held by Chesapeake with respect to the 2016 first quarter distribution. As a result, Chesapeake's distribution was reduced by approximately $1.4 million to allow all other common unitholders to receive a distribution of $0.2195 per common unit as previously announced. Chesapeake received a distribution of $0.0369 per common unit.



8

CHESAPEAKE GRANITE WASH TRUST
NOTES TO FINANCIAL STATEMENTS - (Continued)
(Unaudited)

7. Subsequent Events
The Trust's quarterly income available for distribution was $0.0657 per common unit for the production period from June 1, 2017 to August 31, 2017 . On November 7, 2017 , the Trust declared a cash distribution of $0.0657 per common unit (the "November 2017 Distribution"), attributable to such production period. The distribution will be paid on November 30, 2017 to common unitholders of record as of November 20, 2017 . All Trust unitholders share on a pro rata basis in the Trust's distributable income.
Distributable income attributable to production from June 1, 2017 to August 31, 2017 was calculated as follows (in thousands, except for unit and per unit amounts):
REVENUES:
Royalty income (a)
$
3,420

INCOME (EXPENSES):
Production taxes
(113
)
Trust administrative expenses (b)
(234
)
Total expenses
(347
)
Distributable income available to common unitholders
$
3,073

Distributable income per common unit (46,750,000 units) (c)
$
0.0657

___________________________________________________
(a)
Net of certain post-production expenses.
(b)
Includes cash reserves withheld.
(c)
On June 30, 2017, the subordinated units automatically converted into common units on a one-for-one basis and Chesapeake's right to receive incentive distributions with respect to subsequent periods terminated. Distributions made on common units no longer have the benefit of the subordination threshold, nor are the common units subject to the incentive threshold, and all Trust unitholders share on a pro rata basis in the Trust's distribution.




9

ITEM 2.
Trustee's Discussion and Analysis of Financial Condition and Results of Operations
Introduction
The following discussion and analysis is intended to help the reader understand the Trust’s financial condition and results of operations. This discussion and analysis should be read in conjunction with the Trust’s unaudited interim financial statements and the accompanying notes relating to the Trust and the Underlying Properties included in Item 1 of Part I of this Quarterly Report as well as the Trust’s Annual Report on Form 10-K for the year ended December 31, 2016 (the “2016 Form 10-K”).
Overview
The Trust is a statutory trust formed in June 2011 under the Delaware Statutory Trust Act. The business and affairs of the Trust are managed by the Trustee and, as necessary, the Delaware Trustee. The Trust does not conduct any operations or activities other than owning the Royalty Interests and activities related to such ownership. The Trust’s purpose is generally to own the Royalty Interests, to distribute to the Trust unitholders cash that the Trust receives in respect of the Royalty Interests and the derivative contracts (described in Note 3 to the financial statements contained in Item 1 of Part I of this Quarterly Report) and to perform certain administrative functions in respect of the Royalty Interests and the Trust units. The Trust derives all or substantially all of its income and cash flow from the Royalty Interests and, through February 2016, net gains on settlements of 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 drilled in the Colony Granite Wash play on properties within the AMI. Chesapeake was 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. As of June 30, 2016, Chesapeake had fulfilled its drilling obligation under the development agreement.
The Trust was not responsible for any costs related to the drilling of the Development Wells and is not responsible for any other operating or capital costs of the Underlying Properties, and Chesapeake was 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 had 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, natural gas and NGL 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, natural gas and NGL 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, natural gas and NGL 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 included net settlements under these derivative contracts. As of February 2016, the Trust had settled all derivative contracts.

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 nine months ended September 30, 2017 , distributions were paid on March 2, 2017, June 1, 2017 and August 31, 2017. See Liquidity and Capital Resources below and Note 6 to the financial statements contained in Item 1 of Part I of this Quarterly Report for more information regarding the distributions.




10

The amount of Trust revenues and cash distributions to Trust unitholders fluctuates from quarter to quarter depending on several factors, including, but not limited to:
•
timing and amount of initial production and sales from the Development Wells;
•
oil, natural gas and NGL prices received;
•
volumes of oil, natural gas and NGL produced and sold;
•
certain post-production expenses and any applicable taxes; and
•
the Trust’s expenses.
Through the quarter ended March 31, 2016, the Trust revenues and cash distributions to Trust unitholders were also affected by amounts received from, or paid under, derivative contracts.
Subordination Threshold. In order to provide support for cash distributions on the common units, Chesapeake agreed to subordinate 11,687,500 of the Trust units retained following the initial public offering of common units, which constituted 25% of the outstanding Trust units. Prior to their conversion on June 30, 2017, the subordinated units were entitled to receive pro rata distributions from the Trust each quarter if and to the extent there was sufficient cash to pay a cash distribution on the common units that was no less than 80% of the target distribution set forth in the Trust Agreement for the corresponding quarter. If there was insufficient cash to fund such a distribution on all of the common units, the distribution made with respect to the subordinated units was either reduced or eliminated for such quarter in order to make a distribution, to the extent possible, of up to the subordination threshold amount on all the common units, including the common units held by Chesapeake.
Incentive Threshold. Prior to the conversion of the subordinated units on June 30, 2017, 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 was 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 was 20% greater than the target distribution for such quarter. The remaining 50% of cash available for distribution in excess of the applicable incentive threshold, if any, was paid to the Trust unitholders, including Chesapeake, on a pro rata basis.
On June 30, 2017, the last day of the fourth full calendar quarter subsequent to Chesapeake's satisfaction of its drilling obligation, the subordinated units automatically converted into common units on a one-for-one basis. Distributions on common units no longer have the benefit of the subordination threshold, nor are the common units subject to the incentive threshold, and all Trust unitholders share on a pro rata basis in the Trust's distributions.
Results of Trust Operations
The quarterly payments to the Trust with respect to the Royalty Interests are based on the amount of proceeds actually received by Chesapeake during the preceding calendar quarter. Proceeds from production are typically received by Chesapeake one month after production. Due to the timing of the payment of production proceeds, quarterly distributions made by Chesapeake to the Trust generally include royalties attributable to sales of oil, natural gas and NGL 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 nine months ended September 30, 2017 , the Trust received payments on the Royalty Interests representing royalties attributable to proceeds from sales of oil, natural gas and NGL for September 1, 2016 to May 31, 2017 .
The Trust’s income available for distribution throughout 2016 and to date in 2017 has been adversely affected by several factors. The Trust's revenues and distributable income available to unitholders have been and will continue to be adversely affected if commodity prices remain at current levels or decline further. For each quarterly production period from September 1, 2016 to May 31, 2017, the Trust's calculated distribution per common unit was below the applicable subordination threshold, and no subordinated distribution was paid.
Low levels of future production and low commodity prices will continue to reduce the Trust’s revenues and distributable income available to unitholders. Prior to the conversion of the subordinated units, when a quarterly cash


11

distribution per common unit was lower than the applicable subordination threshold, the common units were not entitled to receive any additional distributions, nor were the common units or the subordinated units entitled to arrearages in any future quarter. On June 30, 2017, the last day of the fourth full calendar quarter subsequent to Chesapeake's satisfaction of its drilling obligation, the subordinated units automatically converted into common units on a one-for-one basis. Distributions made on common units no longer have the benefit of the subordination threshold, nor are the common units subject to the incentive threshold, and all Trust unitholders share on a pro rata basis in the Trust's distribution.
As disclosed in Note 3 to the financial statements contained in Item 1 of Part I of this Quarterly Report, the derivative contracts were initially novated to the Trust in November 2011 and covered a portion of the production attributable to the Royalty Interests from October 1, 2011 through September 30, 2015 but did not cover any production subsequent to September 30, 2015. Settlement of these derivative contracts continued through February 2016. As a result of the expiration of these derivative contracts, it is anticipated that Trust revenues and funds available for distribution will continue to remain low as long as low commodity prices continue.
The Trust's Investment in Royalty Interests are subject to a quarterly full cost ceiling test. In the three and nine months ended September 30, 2017, the Trust recognized no impairments of the Royalty Interests. In the three and nine months ended September 30, 2016, the Trust recognized approximately $8.2 million and $ 23.0 million , respectively, in impairments of the Royalty Interests primarily due to a decrease in commodity prices. The impairments resulted in non-cash charges to Trust corpus and did not affect the Trust's distributable income. See Investment in Royalty Interests in Note 2 to the financial statements contained in Item 1 of Part I of this Quarterly Report and Trust Operations below for further discussion of the impairments.
Trust Operations for the Three Months Ended September 30, 2017 as compared to September 30, 2016 .
Distributable Income. The Trust's distributable income was $3.5 million for the three months ended September 30, 2017 , compared to $2.6 million for the three months ended September 30, 2016 , an increase of $0.9 million. This increase was primarily due to an increase in the average realized prices received from sales of oil, natural gas and NGL in the production period from March 1, 2017 to May 31, 2017 (current production quarter) as compared to the production period from March 1, 2016 to May 31, 2016 (prior production quarter). See Royalty Income below for information regarding the change in average prices received and the change in sales volumes.


12

On a per unit basis, the Trust's distributable income for the three months ended September 30, 2017 , and attributable to the current production quarter, was $0.1003 per common unit, excluding the common units issued on June 30, 2017 upon conversion of the Trust's subordinated units. Cash distributions during the three months ended September 30, 2016 and attributable to the prior production quarter were $0.0734 per common unit, and because such amount was below the subordination threshold, no subordinated distribution was paid. Distributable income for each of the three months ended September 30, 2017 and 2016, and their respective production periods described above, was calculated as follows:
Three Months Ended
September 30,
2017
2016
($ in thousands, except per unit data)
REVENUES:
Royalty income (a)
$
3,939

$
2,608

INCOME (EXPENSES):
Production taxes
(185
)
(79
)
Trust administrative expenses
(236
)
45

Total income (expenses)
(421
)
(34
)
Distributable income available to unitholders
$
3,518

$
2,574

Distributable income per common unit (b)
$
0.1003

$
0.0734

Distributable income per subordinated unit (c)
$
—

$
—

_____________________________________________________
(a)
Net of certain post-production expenses.
(b)
See Notes 1 and 6 to the financial statements contained in Item 1 of Part I of this Quarterly Report.
(c)
For the three months ended September 30, 2016 and 2017, the Trust's calculated distributable income was below the applicable subordination threshold. As a result, no distribution was paid for the subordinated units in either quarter. The subordination and incentive thresholds terminated on June 30, 2017 and are no longer applicable for any future distribution.
Royalty Income. Royalty income to the Trust for the three months ended September 30, 2017 , and attributable to the current production quarter, totaled approximately $3.9 million based upon sales of production attributable to the Royalty Interests of 34 thousand barrels (mbbls) of oil, 814 million cubic feet (mmcf) of natural gas and 80 mbbls of NGL. Total production attributable to the Royalty Interests for the current production quarter was 249 thousand barrels of oil equivalent (mboe). Average prices received for production, including the impact of certain post-production expenses and excluding production taxes, during the current production quarter were $44.16 per barrel (bbl) of oil, $1.21 per thousand cubic feet (mcf) of natural gas and $18.45 per bbl of NGL.
Royalty income to the Trust for the three months ended September 30, 2016 , and attributable to the prior production quarter, totaled approximately $2.6 million based upon sales of production attributable to the Royalty Interests of 44 mbbls of oil, 1,012 mmcf of natural gas and 100 mbbls of NGL. Total production attributable to the Royalty Interests for the prior production quarter was 312 mboe. Average prices received for production, including the impact of certain post-production expenses and excluding production taxes, during the prior production quarter were $35.11 per bbl of oil, $(0.40) per mcf of natural gas and $14.80 per bbl of NGL.
The increase in the price received per barrel of oil equivalent (boe) in the current production quarter compared to the prior production quarter resulted in a $1.8 million increase in royalty income. Such increase was offset by lower sales volumes, which decreased royalty income by $0.5 million, for a total increase in royalty income of approximately $1.3 million. The 63 mboe decrease in total production attributable to the Royalty Interests for the current production period compared to the prior production period is primarily due to no additional wells being drilled on the underlying properties once the drilling obligation was met and natural declines in production from the producing wells and development wells.


13

Production Taxes. Production taxes are calculated as a percentage of oil, natural gas and NGL revenues, net of any applicable tax credits. Production taxes for the three months ended September 30, 2017 , and attributable to the current production quarter, were $185,000 , or $0.74 per boe, as compared to production taxes for the three months ended September 30, 2016 , and attributable to the prior production quarter, of $79,000 , or $0.25 per boe. The increase in production taxes is primarily due to the number of wells with expiring tax incentives and no new wells coming online and receiving tax incentives. As incentives on existing wells expire, the wells are taxed at the higher statutory rate, causing the overall effective tax rate to increase. Production taxes represented 4.7% and 3.0% of royalty income for the three months ended September 30, 2017 and 2016, respectively.
Trust Administrative Expenses. The Trust recorded expenses of $ 236,000 and credits of $45,000 during the three months ended September 30, 2017 and September 30, 2016 , respectively, for trust administrative expenses, including cash reserves. The fluctuation in expenses is primarily due to the timing of payments and increased audit fees. Trust administrative expenses primarily consist of the administrative fees paid to the Trustees and Chesapeake and costs for accounting and legal services.
Derivative Settlement Gain. The Trust recorded gains or losses from the derivative contracts when proceeds were received or payments were made, respectively. There was no settlement of derivative contracts for the three months ended September 30, 2017 and 2016, respectively, as the Trust settled all derivative contracts as of February 2016.
Impairments of Investment in Royalty Interests. The Trust's Investment in Royalty Interests are subject to a quarterly full cost ceiling test. For the three months ended September 30, 2017, the Trust recognized no impairments of the Royalty Interests. For the three months ended September 30, 2016, the Trust recognized $8.2 million in impairments of the Royalty Interests. See Investment in Royalty Interests in Note 2 to the financial statements included in Item 1 of Part I of this Quarterly Report for further discussion of the impairments.
Trust Operations for the Nine Months Ended September 30, 2017 as compared to September 30, 2016 .
Distributable Income. The Trust's distributable income was $10.2 million for the nine months ended September 30, 2017 , compared to $9.5 million for the nine months ended September 30, 2016 , an increase of $0.7 million. This increase was primarily due to an increase in the average realized prices received from sales of oil, natural gas and NGL in the production period from September 1, 2016 to May 31, 2017 (current production period) as compared to the production period from September 1, 2015 to May 31, 2016 (prior production period). See Royalty Income below for information regarding the change in average prices received and the change in sales volumes.


14

On a per unit basis, the Trust's distributable income for the nine months ended September 30, 2017 , and attributable to the current production period, was $0.2920 per common unit, and no subordinated distribution was paid. Cash distributions during the nine months ended September 30, 2016 and attributable to the prior production period were $0.2704 per common unit, and because such amount was below the subordination threshold, no subordinated distribution was paid. Distributable income for each of the nine months ended September 30, 2017 and 2016, and their respective production periods described above, was calculated as follows:
Nine Months Ended
September 30,
2017
2016
($ in thousands, except per unit data)
REVENUES:
Royalty income (a)
$
12,245

$
9,041

INCOME (EXPENSES):
Production taxes
(556
)
(317
)
Trust administrative expenses
(1,451
)
(1,354
)
Derivative settlement gain
—

2,109

Total income (expenses)
(2,007
)
438

Distributable income available to unitholders
$
10,238

$
9,479

Distributable income per common unit (b)
$
0.2920

$
0.2704

Distributable income per subordinated unit (c)
$
—

$
—

_____________________________________________________
(a)
Net of certain post-production expenses.
(b)
See Notes 1 and 6 to the financial statements contained in Item 1 of Part I of this Quarterly Report.
(c)
For the nine months ended September 30, 2016, the Trust's calculated distributable income was below the applicable subordination threshold. As a result, no distribution was paid for the subordinated units in either period. The subordination and incentive thresholds terminated on June 30, 2017 and are no longer applicable for any future distribution.
Royalty Income. Royalty income to the Trust for the nine months ended September 30, 2017 , and attributable to the current production quarter, totaled $12.2 million based upon sales of production attributable to the Royalty Interests of 106 mbbls of oil, 2,533 mmcf of natural gas and 249 mbbls of NGL. Total production attributable to the Royalty Interests for the current production period was 777 mboe. Average prices received for production, including the impact of certain post-production expenses and excluding production taxes, during the current production period were $44.00 per bbl of oil, $1.00 per mcf of natural gas and $20.24 per bbl of NGL.
Royalty income to the Trust for the nine months ended September 30, 2016 , and attributable to the prior production period, totaled $9.0 million based upon sales of production attributable to the Royalty Interests of 136 mbbls of oil, 3,325 mmcf of natural gas and 282 mbbls of NGL. Total production attributable to the Royalty Interests for the prior production quarter was 972 mboe. Average prices received for production, including the impact of certain post-production expenses and excluding production taxes, during the prior production period were $32.53 per bbl of oil, $0.15 per mcf of natural gas and $14.57 per bbl of NGL.
The increase in the price received per boe in the current production period compared to the prior production period resulted in a $5.0 million increase in royalty income. Such increase was offset by lower sales volumes, which decreased royalty income by $1.8 million, for a total increase in royalty income of $3.2 million. The 195 mboe decrease in total production attributable to the Royalty Interests for the current production period compared to the prior production period is primarily due to no additional wells being drilled on the underlying properties once Chesapeake satisfied its drilling obligation to the Trust and natural declines in production from the producing wells and development wells.


15

Production Taxes. Production taxes are calculated as a percentage of oil, natural gas and NGL revenues, net of any applicable tax credits. Production taxes for the nine months ended September 30, 2017 , and attributable to the current production period, were $556,000 , or $0.72 per boe, as compared to production taxes for the nine months ended September 30, 2016 , and attributable to the prior production period, of $317,000 , or $0.33 per boe. The increase in production taxes is primarily due to the number of wells with expiring tax incentives and no new wells coming online and receiving tax incentives. As incentives on existing wells expire, the wells are taxed at the higher statutory rate causing the overall effective tax rate to increase. Production taxes represented approximately 4.5% and 3.5% of royalty income for the nine months ended September 30, 2017 and 2016, respectively.
Trust Administrative Expenses. The Trust recorded expenses of $1.5 million and $1.4 million during the nine months ended September 30, 2017 and 2016, respectively, for trust administrative expenses, including cash reserves. Trust administrative expenses primarily consist of the administrative fees paid to the Trustees and Chesapeake and costs for accounting and legal services.
Derivative Settlement Gain. The Trust recorded gains or losses from the derivative contracts when proceeds were received or payments were made, respectively. There was no settlement of derivative contracts for the nine months ended September 30, 2017 , as the Trust settled all derivative contracts as of February 2016. Swaps covering the prior production period were settled during the nine months ended September 30, 2016 , and proceeds received were included in the Trust's distributable income for the prior production period. Total gains during the nine months ended September 30, 2016 were $2.1 million .
Impairments of Investment in Royalty Interests. The Trust's Investment in Royalty Interests are subject to a quarterly full cost ceiling test. For the nine months ended September 30, 2017, the Trust recognized no impairments of the Royalty Interests. For the nine months ended September 30, 2016, the Trust recognized $23.0 million , in impairments of the Royalty Interests. The 2016 impairments were primarily due to a decrease in commodity prices. The 2016 impairments resulted in a non-cash charge to Trust corpus and did not affect the Trust's distributable income. See Investment in Royalty Interests in Note 2 to the financial statements included in Item 1 of Part I of this Quarterly Report for further discussion of the impairments.
Liquidity and Capital Resources
The Trust’s principal sources of liquidity and capital are cash flows generated from the Royalty Interests and the loan commitment as described below and, prior to the expiration of the derivative contracts on September 30, 2015, cash settlements on derivative contracts during periods in which oil prices fell below the fixed price received on derivative contracts. The Trust’s primary uses of cash are distributions to Trust unitholders, payments of production taxes, payments of Trust administrative expenses, including any reserves established by the Trustee for future liabilities and repayment of loans and payments of expense reimbursements to Chesapeake for out-of-pocket expenses incurred 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, natural gas and NGL 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 to the subordination and incentive provisions described previously, as applicable.
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 2017 first quarter distribution of $0.0912 per common unit, consisting of proceeds attributable to production from September 1, 2016 through November 30, 2016 was made on March 2, 2017 to record unitholders as of February 20, 2017. The 2017 second quarter distribution of $0.1005 per common unit, consisting of proceeds attributable to production from December 1, 2016 through February 28, 2017 was made on June 1, 2017 to record unitholders as of May 22, 2017. The 2017 third quarter distribution of $0.1003 per common unit, consisting of proceeds attributable to production from March 1, 2017 through May 31, 2017 , was made on August 31, 2017 to record unitholders as of August 21, 2017 , except with respect to holders of common units issued on June 30, 2017 upon conversion of the Trust's subordinated units. As the distributable income per common unit for the 2017 first and second quarter distributions was below the subordination threshold, no distribution was declared for the subordinated units.


16

The Trust's quarterly income available for distribution was $0.0657 per common unit consisting of proceeds attributable to production from June 1, 2017 to August 31, 2017 . On November 7, 2017 , the Trust declared a cash distribution of $0.0657 per common unit (the "November 2017 Distribution"), attributable to such production period. The distribution will be paid on November 30, 2017 to common unitholders of record as of November 20, 2017 . All Trust unitholders share on a pro rata basis in the Trust's distributable income. Distributable income attributable to production from June 1, 2017 to August 31, 2017 was calculated as follows (in thousands, except for unit and per unit amounts):
REVENUES:
Royalty income (a)
$
3,420

INCOME (EXPENSES):
Production taxes
(113
)
Trust administrative expenses (b)
(234
)
Total expenses
(347
)
Distributable income available to common unitholders
$
3,073

Distributable income per common unit (46,750,000 units) (c)
$
0.0657

___________________________________________________
(a)
Net of certain post-production expenses.
(b)
Includes cash reserves withheld.
(c)
On June 30, 2017, the subordinated units automatically converted into common units on a one-for-one basis and Chesapeake's right to receive incentive distributions with respect to subsequent periods terminated. Distributions made on common units no longer have the benefit of the subordination threshold, nor are the common units subject to the incentive threshold, and all Trust unitholders share on a pro rata basis in the Trust's distribution.
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 may 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 September 30, 2017 or December 31, 2016.
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.
Critical Accounting Policies and Estimates
Refer to Note 2 to the financial statements included in Item 1 of Part I of this Quarterly Report for a discussion of significant accounting policies and estimates that impact the Trust's financial statements. Critical accounting policies and estimates relating to the Trust are contained in Item 7 of Part II of the 2016 Form 10-K.


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ITEM 3.
Quantitative and Qualitative Disclosures about Market Risk
Oil, Natural Gas and NGL Price Risk. The Trust’s primary asset and source of income is the Royalty Interests, which generally entitles the Trust to receive a portion of the net proceeds from the sales of oil, natural gas and NGL from the Underlying Properties. The Trust is significantly exposed to fluctuations in the prices received for oil, natural gas and NGL produced and sold.
Credit Risk Associated With Chesapeake .  Chesapeake’s ability to perform its obligations to the Trust will depend on its future results of operations, financial condition, liquidity 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, natural gas and NGL, prevailing economic conditions and financial, business and other factors, many of which are beyond Chesapeake’s control.
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.
ITEM 4.
Controls and Procedures
Evaluation of Disclosure Controls and Procedures.
The Trust’s disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act, are designed to ensure that the information required to be disclosed by the Trust in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by the Trust is accumulated and communicated by Chesapeake to The Bank of New York Mellon Trust Company, N.A., as the Trustee of the Trust, and its employees who participate in the preparation of the Trust’s periodic reports as appropriate to allow timely decisions regarding required disclosures.
Due to the nature of the Trust as a passive entity and in light of the contractual arrangements pursuant to which the Trust was created, including the provisions of (a) the Trust Agreement, (b) the administrative services agreement, (c) the development agreement and (d) the conveyances granting the Royalty Interests, the Trust’s disclosure controls and procedures necessarily rely on (i) information provided by Chesapeake, including information relating to results of operations, the costs and revenues attributable to the Trust’s interests under the conveyance and other operating and historical data, plans for future operating and capital expenditures, reserve information, information relating to projected production, and other information relating to the status and results of operations of the underlying properties and the Royalty Interests, and (ii) conclusions and reports regarding reserves by the Trust’s independent reserve engineers. Although the Trustee does rely on Chesapeake to perform certain functions and to provide certain information that impact the Trust’s financial statements, the Trustee remains responsible for evaluating, as appropriate, the Trust’s disclosure controls and procedures as well as its internal control over financial reporting.
The Vice President of the Trustee has evaluated the effectiveness of the Trust’s disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(b) as of the end of the period covered by this Quarterly Report. Based on this evaluation, as of September 30, 2017, it was concluded that the Trust’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended) were not effective because of the material weakness in the Trust's internal control over financial reporting described in Item 9A of Part II of the 2016 Form 10-K.
Plan of Remediation for the Material Weakness.
The Trust is actively engaged in remediation efforts to address the material weakness identified in Item 9A of Part II of the 2016 Form 10-K. Specifically, the Trust is in the process of implementing controls related to reviewing the configuration of basis price differential calculations, including a control activity to verify any subsequent changes are appropriately reviewed and that the interface control is designed to validate the data at an appropriately disaggregated level. The Trustee believes that these actions will remediate the material weakness in internal control over financial reporting.



18

Changes in Internal Control over Financial Reporting.
There were no changes in the Trust's internal control over financial reporting during the quarter ended September 30, 2017, which materially affected, or were reasonably likely to materially affect, the Trust's internal control over financial reporting. The Trustee notes for purposes of clarification that it has no authority over, and makes no statement concerning, the internal control over financial reporting of Chesapeake.





19


PART II. OTHER INFORMATION
ITEM 1A. Risk Factors
Additional information about risk factors relating to the Trust are contained in Item 1A of Part I of the 2016 Form 10-K.

ITEM 6. Exhibits
The exhibits listed below in the Index of Exhibits are filed, furnished or incorporated by reference pursuant to the requirements of Item 601 of Regulation S-K.

INDEX OF EXHIBITS
Incorporated by Reference
Exhibit
Number
Exhibit Description
Form
SEC File
Number
Exhibit
Filing Date
Filed
or Furnished Herewith
3.1
Certificate of Trust of Chesapeake Granite Wash Trust.
S-1
333-175395
7/7/2011
3.2
Amended and Restated Trust Agreement, dated as of November 16, 2011, by and among Chesapeake Energy Corporation, Chesapeake Exploration, L.L.C., The Bank of New York Mellon Trust Company, N.A., as Trustee, and The Corporation Trust Company, as Delaware Trustee.
8-K
001-35343
11/21/2011
Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 – Trustee’s Vice President.
X
Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 – Trustee’s Vice President
X





20

SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Date: November 7, 2017
CHESAPEAKE GRANITE WASH TRUST
By:
THE BANK OF NEW YORK MELLON
TRUST COMPANY, N.A, Trustee
By:
/s/ Sarah C. Newell
Sarah C. Newell
Vice President
The registrant, Chesapeake Granite Wash Trust, has no principal executive officer, principal financial officer, board of directors or persons performing similar functions. Accordingly, no additional signatures are available, and none have been provided. In signing the report above, the Trustee does not imply that it has performed any such function or that such function exists pursuant to the terms of the Trust Agreement under which it serves.


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