CHKR 10-Q Quarterly Report June 30, 2018 | Alphaminr
CHESAPEAKE GRANITE WASH TRUST
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CHKR 10-Q Quarter ended June 30, 2018

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Cash Flow
Income Statement
CHESAPEAKE GRANITE WASH TRUST
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10-Q 1 chkr-2018x630x10q.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 June 30, 2018
[ ]    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
601 Travis Street, Floor 16
Houston, Texas
77002
(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 every Interactive Data File required to be submitted 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 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 [ ]
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 accounting 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 August 2, 2018 , 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 JUNE 30, 2018

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. Our forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “seek,” “plan,” “goal,” “assume,” “target,” “should,” “intend,” “ability,” “will,” “would,” “forecast” 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, 2017 (the "2017 Form 10-K") and those set forth from time to time in the Trust’s filings with the United States 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. These factors should not be construed as exhaustive, and there may also be other risks that we are unable to predict at this time. 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 and expressly disclaim any obligation to do so, 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)

June 30, 2018
December 31, 2017
($ in thousands)
ASSETS:
Cash and cash equivalents
$
1,622

$
2,067

Investment in Royalty Interests
487,793

487,793

Less: accumulated amortization and impairment
(463,152
)
(461,488
)
Net Investment in Royalty Interests
24,641

26,305

Total assets
$
26,263

$
28,372

LIABILITIES AND TRUST CORPUS:
Dividend payable to Chesapeake
$
—

$
768

Total liabilities
—

768

Trust Corpus; 46,750,000 common units issued and outstanding at June 30, 2018 and December 31, 2017
26,263

27,604

Total liabilities and Trust corpus
$
26,263

$
28,372












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

1

CHESAPEAKE GRANITE WASH TRUST
STATEMENTS OF DISTRIBUTABLE INCOME
(Unaudited)

Three Months Ended
June 30,
Six Months Ended
June 30,
2018
2017
2018
2017
($ in thousands, except unit and per unit data)
REVENUES:
Royalty income
$
3,362

$
4,533

$
7,287

$
8,306

EXPENSES:
Production taxes
(208
)
(207
)
(451
)
(371
)
Trust administrative expenses
(961
)
(803
)
(963
)
(1,215
)
Total expenses
(1,169
)
(1,010
)
(1,414
)

(1,586
)
Distributable income available to unitholders
$
2,193

$
3,523

$
5,873

$
6,720

Distributable income per common unit (46,750,000 common units at June 30, 2018 and 35,062,500 common units at June 30, 2017)
$
0.0469

$
0.1005

$
0.1256


$
0.1917

Distributable income per subordinated unit (0 subordinated units at June 30, 2018 and 11,687,500 subordinated units at June 30, 2017)
$
—

$
—

$
—

$
—




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

Six Months Ended
June 30,
2018
2017
($ in thousands)
TRUST CORPUS: Beginning of period
$
27,604

$
31,938

Cash reserve deficit
322

186

Amortization of Investment in Royalty Interests
(1,663
)
(2,394
)
Distributable income
5,873

6,720

Distributions paid to unitholders
(5,873
)
(6,720
)
TRUST CORPUS: End of period
$
26,263

$
29,730



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” and, together with the Trustee, the "Trustees").
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 and the Trustees (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 to be paid to 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 under the development agreement, the subordinated units automatically converted into common units on a one-for-one basis. All distributions made on common units after September 30, 2017 no longer have the


3

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

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 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, 2017 and the unaudited interim financial statements of the Trust as of and for the three and six months ended June 30, 2018 and 2017 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, 2017 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, 2017 . 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, there are no derivative contracts, and the Trust does not have the ability to enter into new derivative contracts.


4

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

The Trust's revenues and distributable income available to unitholders have been adversely affected throughout 2017 and to date in 2018 by a decline in production. Due to natural declines, the Trust expects production to decline further and expects distributable income to continue to be adversely affected. On August 3, 2018 , the Trust declared a cash distribution of $0.0626 per common unit (the "August 2018 Distribution"), consisting of proceeds attributable to production from March 1, 2018 to May 31, 2018 . The distribution will be paid on August 30, 2018 to common unitholders of record as of August 20, 2018 . See Note 5 for information regarding prior distributions paid and Note 6 for information on the August 2018 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.
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 six months ended June 30, 2018 and 2017, the Trust recognized no impairments of the Royalty Interests.
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 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, if any) 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 June 30, 2018 or December 31, 2017.
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.


5

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

3.
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.
4.
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. The Trustee's annual administrative fees were adjusted upward by 2.1% for the 2017 calendar year and by 2.5% for the 2018 calendar year.
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.
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 administrative services agreement.
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.
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, if any) 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 June 30, 2018 or December 31, 2017.


6

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

5.
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 six months ended June 30, 2018 and 2017, the Trust declared and paid the following cash distributions:
Production Period
Distribution
Date
Cash Distribution per
Common Unit
Cash Distribution per Subordinated Unit (a)
December 2017 - February 2018
May 31, 2018
$
0.0469

$
—

September 2017 - November 2017
March 2, 2018
$
0.0787

$
—

December 2016 - February 2017
June 1, 2017
$
0.1005

$
—

September 2016 - November 2016
March 2, 2017
$
0.0912

$
—

(a)
For the production periods from September 2016 through November 2016 and December 2016 through February 2017, the distribution per common unit was below the applicable subordination threshold, and no distribution was declared for the subordinated units. On June 30, 2017, the subordinated units automatically converted into common units on a one-for-one basis. As a result, distributions made on common units no longer have the benefit of the subordination threshold, the common units are no longer subject to the incentive threshold, and all Trust unitholders share on a pro rata basis in the Trust's distributions.

6. Subsequent Events
The Trust's quarterly income available for distribution was $0.0626 per common unit for the production period from March 1, 2018 to May 31, 2018 . On August 3, 2018 , the Trust declared the August 2018 Distribution attributable to such production period. The distribution will be paid on August 30, 2018 to common unitholders of record as of August 20, 2018 . All Trust unitholders share on a pro rata basis in the Trust's distributable income.
Distributable income attributable to production from March 1, 2018 to May 31, 2018 was calculated as follows (in thousands, except for unit and per unit amounts):
REVENUES:
Royalty income (a)
$
3,171

EXPENSES:
Production taxes
(212
)
Trust administrative expenses (b)
(34
)
Total expenses
(246
)
Distributable income available to common unitholders
$
2,925

Distributable income per common unit (c)
$
0.0626

___________________________________________________
(a)
Net of certain post-production expenses.
(b)
Includes cash reserves withheld.
(c)
Calculation of distributable income per common unit is based on 46,750,000 common units issued and outstanding as of August 2, 2018.




7

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, 2017 .
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 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. The Trust is treated as a partnership for U.S. 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. 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 produce or plug and abandon each Development Well. 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.

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 six months ended June 30, 2018 , distributions were paid on each of March 2, 2018 and May 31, 2018. See Liquidity and Capital Resources below and Note 5 to the financial statements contained in Item 1 of Part I of this Quarterly Report for more information regarding such distributions.


8

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 production and sales from the Development and Producing 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.
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 after the end of each calendar quarter. During the six months ended June 30, 2018 , the Trust received payments on the Royalty Interests representing royalties attributable to proceeds from sales of oil, natural gas and NGL for September 1, 2017 to February 28, 2018 .
The Trust's revenues and distributable income available to unitholders have been adversely affected throughout 2017 and to date in 2018 by a decline in production. Due to natural declines, the Trust expects production to decline further and expects distributable income to continue to be adversely affected.
Prior to the conversion of the subordinated units, when a quarterly cash 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. As a result, distributions made on common units no longer have the benefit of the subordination threshold, the common units are no longer subject to the incentive threshold, and all Trust unitholders share on a pro rata basis in the Trust's distributions.


9

The Trust's Investment in Royalty Interests are subject to a quarterly full cost ceiling test. In the three and six months ended June 30, 2018 and 2017, the Trust recognized no impairments of the Royalty Interests. 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 impairments.
Trust Operations for the Three Months Ended June 30, 2018 as compared to June 30, 2017 .
Distributable Income. The Trust's distributable income was $2.2 million for the three months ended June 30, 2018 , compared to $3.5 million for the three months ended June 30, 2017 , a decrease of $1.3 million. This decrease was primarily due to a decrease in sales volumes of oil, natural gas and NGL in the production period from December 1, 2017 to February 28, 2018 (current production quarter) as compared to the production period from December 1, 2016 to February 28, 2017 (prior production quarter). See Royalty Income below for information regarding the change in average prices received and the change in sales volumes.
On a per unit basis, the Trust's distributable income for the three months ended June 30, 2018 , and attributable to the current production quarter, was $0.0469 per common unit. Distributable income for the three months ended June 30, 2017 and attributable to the prior production quarter was $0.1005 per common unit, and because such amount was below the subordination threshold, no subordinated distribution was paid. Distributable income for each of the three month periods ended June 30, 2018 and 2017, and their respective production periods described above, was calculated as follows:
Three Months Ended
June 30,
2018
2017
($ in thousands, except per unit data)
REVENUES:
Royalty income (a)
$
3,362

$
4,533

EXPENSES:
Production taxes
(208
)
(207
)
Trust administrative expenses
(961
)
(803
)
Total expenses
(1,169
)
(1,010
)
Distributable income available to unitholders
$
2,193

$
3,523

Distributable income per common unit (b)
$
0.0469

$
0.1005

Distributable income per subordinated unit (c)
$
—

$
—

_____________________________________________________
(a)
Net of certain post-production expenses.
(b)
See Notes 1 and 5 to the financial statements contained in Item 1 of Part I of this Quarterly Report.
(c)
For the three months ended June 30, 2017, the Trust's calculated distributable income was below the applicable subordination threshold. As a result, no distribution was paid for the subordinated units. 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 June 30, 2018 , and attributable to the current production quarter, totaled approximately $3.4 million based upon sales of production attributable to the Royalty Interests of 24 thousand barrels (mbbls) of oil, 608 million cubic feet (mmcf) of natural gas and 63 mbbls of NGL. Total production attributable to the Royalty Interests for the current production quarter was 188 thousand barrels of oil equivalent (mboe). Average prices received for production, including the impact of certain post-production expenses but excluding production taxes, during the current production quarter were $59.96 per barrel (bbl) of oil, $1.08 per thousand cubic feet (mcf) of natural gas and $21.22 per bbl of NGL.
Royalty income to the Trust for the three months ended June 30, 2017 , and attributable to the prior production quarter, totaled approximately $4.5 million based upon sales of production attributable to the Royalty Interests of 36


10

mbbls of oil, 812 mmcf of natural gas and 85 mbbls of NGL. Total production attributable to the Royalty Interests for the prior production quarter was 256 mboe. Average prices received for production, including the impact of certain post-production expenses but excluding production taxes, during the prior production quarter were $47.18 per bbl of oil, $1.09 per mcf of natural gas and $23.10 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 $33,000 increase in royalty income. Such increase was offset by lower sales volumes, which decreased royalty income by $1.2 million, for a total decrease in royalty income of approximately $1.2 million. The 68 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 natural declines in production from the Producing Wells and Development Wells.
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 June 30, 2018 , and attributable to the current production quarter, were $208,000 , or $1.10 per boe, as compared to production taxes for the three months ended June 30, 2017 , and attributable to the prior production quarter, of $207,000 , or $0.81 per boe. Production taxes represented 6.2% and 4.6% of royalty income for the three months ended June 30, 2018 and 2017, respectively.
Trust Administrative Expenses. The Trust recorded expenses of $ 961,000 and $803,000 during the three months ended June 30, 2018 and 2017, respectively, for Trust administrative expenses, including cash reserves. The increase in expenses is primarily due to the the Trust requesting a larger cash advance during the three months ended June 30, 2018 to pay expenses that were delayed during the three months ended March 31, 2018. Trust administrative expenses primarily consist of the administrative fees paid to the Trustees and Chesapeake and costs for accounting and legal services.
Trust Operations for the Six Months Ended June 30, 2018 as compared to June 30, 2017 .
Distributable Income. The Trust's distributable income was $5.9 million for the six months ended June 30, 2018 , compared to $6.7 million for the six months ended June 30, 2017 , a decrease of $0.8 million. This decrease was primarily due to a decrease in sales volumes of oil, natural gas and NGL in the production period from September 1, 2017 to February 28, 2018 (current production period) as compared to the production period from September 1, 2016 to February 28, 2017 (prior production period), partially offset by an increase in prices. See Royalty Income below for information regarding the change in average prices received and the change in sales volumes.


11

On a per unit basis, the Trust's distributable income for the six months ended June 30, 2018 , and attributable to the current production period, was $0.1256 per common unit. Distributable income for the six months ended June 30, 2017 and attributable to the prior production period was $0.1917 per common unit, and because such amount was below the subordination threshold, no subordinated distribution was paid. Distributable income for each of the six month periods ended June 30, 2018 and 2017, and their respective production periods described above, was calculated as follows:
Six Months Ended
June 30,
2018
2017
($ in thousands, except per unit data)
REVENUES:
Royalty income (a)
$
7,287

$
8,306

EXPENSES:
Production taxes
(451
)
(371
)
Trust administrative expenses
(963
)
(1,215
)
Total expenses
(1,414
)
(1,586
)
Distributable income available to unitholders
$
5,873

$
6,720

Distributable income per common unit (b)
$
0.1256

$
0.1917

Distributable income per subordinated unit (c)
$
—

$
—

_____________________________________________________
(a)
Net of certain post-production expenses.
(b)
See Notes 1 and 5 to the financial statements contained in Item 1 of Part I of this Quarterly Report.
(c)
For the six months ended June 30, 2017, the Trust's calculated distributable income was below the applicable subordination threshold. As a result, no distribution was paid for the subordinated units. 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 six months ended June 30, 2018 , and attributable to the current production period, totaled approximately $7.3 million based upon sales of production attributable to the Royalty Interests of 49 mbbls of oil, 1,282 mmcf of natural gas and 148 mbbls of NGL. Total production attributable to the Royalty Interests for the current production period was 411 mboe. Average prices received for production, including the impact of certain post-production expenses but excluding production taxes, during the current production period were $52.02 per bbl of oil, $1.04 per mcf of natural gas and $22.97 per bbl of NGL.
Royalty income to the Trust for the six months ended June 30, 2017 , and attributable to the prior production period, totaled approximately $8.3 million based upon sales of production attributable to the Royalty Interests of 72 mbbls of oil, 1,719 mmcf of natural gas and 169 mbbls of NGL. Total production attributable to the Royalty Interests for the prior production period was 528 mboe. Average prices received for production, including the impact of certain post-production expenses but excluding production taxes, during the prior production period were $44.14 per bbl of oil, $0.91 per mcf of natural gas and $21.12 per bbl of NGL.
The increase in the price received per barrel of oil equivalent (boe) in the current production period compared to the prior production period resulted in a $0.8 million increase in royalty income. Such increase was offset by lower sales volumes, which decreased royalty income by $1.8 million, for a total decrease in royalty income of approximately $1.0 million. The 117 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 natural declines in production from the Producing Wells and Development Wells.
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 six months ended June 30, 2018 , and attributable to the current production period, were $451,000 , or $1.10 per boe, as compared to production taxes for the six months ended June 30,


12

2017 , and attributable to the prior production period, of $371,000 , or $0.70 per boe. The increase in production taxes is primarily due to an increase in oil, natural gas and NGL prices. Production taxes represented 6.2% and 4.5% of royalty income for the six months ended June 30, 2018 and 2017, respectively.
Trust Administrative Expenses. The Trust recorded expenses of $963,000 and $1.2 million during the six months ended June 30, 2018 and 2017, respectively, for Trust administrative expenses, including cash reserves. The decrease in expenses is primarily due to the timing and the dollar amount of cash advance requested from the Trust, which resulted in a delay in the payment of certain expenses of the Trust. Because of the fluctuations in timing of cash advance requests during the six months ended June 30, 2018, the Trust's total cash advance was lower during such period when compared to the six months ended June 30, 2017. Trust administrative expenses primarily consist of the administrative fees paid to the Trustees and Chesapeake and costs for accounting and legal services.


13

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. 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 Trustees, 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. The Trust does not undertake or control any capital projects or capital expenditures. These capital expenditures, if any, are controlled and paid by Chesapeake.
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 2018 second quarter distribution of $0.0469 per common unit, consisting of proceeds attributable to production from December 1, 2017 through February 28, 2018 , was made on May 31, 2018 to record unitholders as of May 21, 2018 .
The Trust's quarterly income available for distribution was $0.0626 per common unit consisting of proceeds attributable to production from March 1, 2018 to May 31, 2018 . On August 3, 2018 , the Trust declared the August 2018 Distribution, attributable to such production period. The distribution will be paid on August 30, 2018 to common unitholders of record as of August 20, 2018 . All Trust unitholders share on a pro rata basis in the Trust's distributable income. Distributable income attributable to production from March 1, 2018 to May 31, 2018 was calculated as follows (in thousands, except for unit and per unit amounts):
REVENUES:
Royalty income (a)
$
3,171

EXPENSES:
Production taxes
(212
)
Trust administrative expenses (b)
(34
)
Total expenses
(246
)
Distributable income available to common unitholders
$
2,925

Distributable income per common unit (c)
$
0.0626

___________________________________________________
(a)
Net of certain post-production expenses.
(b)
Includes cash reserves withheld.
(c)
Calculation of distributable income per common unit is based on 46,750,000 commons units issued and outstanding as of August 2, 2018.
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, if any) 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


14

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 June 30, 2018 or December 31, 2017.
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 contained 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 2017 Form 10-K.
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.


15

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 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. 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 her evaluation, as of June 30, 2018, she has 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 effective.
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.
Changes in Internal Control over Financial Reporting.
There were no changes in the Trust's internal control over financial reporting during the three months ended June 30, 2018, which materially affected, or were reasonably likely to materially affect, the Trust's internal control over financial reporting.



16


PART II. OTHER INFORMATION
ITEM 1. Legal Proceedings
There are no legal proceedings to which the Trust is a named party. However, the Trustee has been advised by Chesapeake that the Trust may from time to time be subject to litigation in the ordinary course of business for certain matters that include the Royalty Interests. While Chesapeake has advised the Trustee that it does not presently believe any pending litigation will have a material adverse effect net to the Trust, in the event such matters are adjudicated or settled in a material amount and charges are made against royalty income, such charges could have a material impact on the Trust's future royalty income.
ITEM 1A. Risk Factors
Information about risk factors relating to the Trust is contained in Item 1A of Part I of the 2017 Form 10-K.


17

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


18

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: August 3, 2018
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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