What changed in this filing

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Item 1. Business

2020-03-19 compared with 2019-03-22 · 52 added, 77 removed, 450 unchanged (22% of the section changed)

15 unchanged sentences

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, and Chesapeake's right to receive incentive distributions with respect to quarters after the 2017 second quarter terminated.

All distributions made on common units after September 30, 2017 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 was still subject to the subordination threshold.

As such, distributable income per common unit as of September 30, 2017 was based upon 35,062,500 common units.

Beginning with the November 30, 2017 distribution, the distributable income available to unitholders is based on the 46,750,000 common units that are currently outstanding.

The subordinated units were converted into common units on a one-for-one basis as of June 30, 2017.

Neither the Trust nor the Trustee is responsible for , or has any control over , any operating or capital costs of the Underlying Properties.

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Chesapeake will have a right of first refusal to purchase the Perpetual Royalties retained by the Trust at the Termination Date.

Target Distributions and Subordination and Incentive Thresholds

The Trust is required to make quarterly cash distributions of substantially all of its quarterly cash receipts, after deducting the Trust's administrative expenses and any cash reserves, on or about 60 days following the completion of each quarter through (and including) the quarter ending June 30, 2031.

1 unchanged sentence

The first quarterly distribution was made on December 28, 2011 to record unitholders as of December 15, 2011.

In connection with the initial public offering of the Trust, Chesapeake established quarterly target levels of cash distributions to unitholders for the life of the Trust.

These target distributions were used to calculate the subordination and incentive thresholds described in more detail below and do not represent estimates of the actual distributions that may be received by Trust unitholders.

Actual cash distributions to the Trust unitholders will fluctuate quarterly based on the quantity of oil, natural gas, and NGL sold from the Underlying Properties, the prices received for such sales, the timing of Chesapeake's receipt of payment for such sales, the Trust's expenses and other factors.

Target distributions will decline over time as a result of the depletion of the reserves in the Underlying Properties.

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.

For the year ended December 31, 2019 , the Trust declared and paid the following cash distributions:

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Taking into account the receipt and disbursement of all such amounts, the Trustee determines for such calendar quarter the amount of funds available for distribution to the Trust unitholders.

Available funds are the excess cash, if any, received by the Trust over the Trust's expenses for that quarter.

Available funds are the excess cash, if any, received by the Trust over

the Trust's expenses for that quarter.

Available funds are reduced by any cash the Trustee decides to hold as a reserve against future liabilities.

117 unchanged sentences

If Chesapeake lends 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.

Any such loan will be on an unsecured basis, and the terms of such loan will be substantially the same as those which would be obtained in an arms' length transaction between Chesapeake and an unaffiliated third party.

Any such loan will be on an unsecured basis.

There were no loans outstanding as of December 31, 2019 or December 31, 2018.

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the Trust sells all of the Royalty Interests;

cash available for distribution is less than $1.0 million for any four consecutive quarters;

the aggregate quarterly cash distribution amounts for any four consecutive quarters is less than $1.0 million;

the holders of a majority of the Trust units and a majority of the common units (excluding common units owned by Chesapeake and its affiliates) in each case voting in person or by proxy at a meeting of such holders at which a quorum is present vote in favor of dissolution;

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All of Chesapeake's operations are conducted onshore in the United States.

oil and natural gas industry is regulated at the federal, state and local levels, and some of the laws and regulations that govern its operations carry substantial administrative, civil and criminal penalties for non-compliance.

Although Chesapeake has advised the Trustee that Chesapeake believes it is in material compliance with all applicable laws and regulations, and that the cost of compliance with existing requirements will not have a material adverse effect on its financial position, cash flows or results of operations, such laws and regulations could be, and frequently are, amended or reinterpreted.

oil and natural gas industry is subject to a wide range of regulations, laws, rules, taxes, fees and other policy implementation actions that have been pervasive and are under constant review for amendment or expansion.

Numerous government agencies have issued extensive regulations that are binding on our industry, some of which carry substantial penalties for failure to comply.

These laws and regulations increase the cost of doing business and consequently affect profitability.

Additionally, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered.

Therefore, Chesapeake is unable to predict the future costs or impact of compliance or non-compliance.

Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, local governments, the courts and federal agencies, such as the U.S.

Environmental Protection Agency (EPA), the Federal Energy Regulatory Commission (FERC), the Department of Transportation (DOT), the Department of Interior (DOI) and the U.S.

Army Corps of Engineers (USACE).

Chesapeake has advised the Trustee that Chesapeake actively monitors regulatory developments applicable to the industry in order to anticipate, design and implement required compliance activities and systems.

Regulation – Environment, Health and Safety

Chesapeake has advised the Trustee that Chesapeake actively monitors regulatory developments applicable to our industry in order to anticipate, design and implement required compliance activities and systems.

The following are significant areas of government control and regulation affecting our operations.

Exploration and Production, Environmental, Health and Safety, and Occupational Laws and Regulations

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seismic operations and data;

hydraulic fracturing

location, drilling, cementing and casing of wells;

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construction and operations activities in sensitive areas, such as wetlands, coastal regions or areas that contain endangered or threatened species, their habitats, or sites of cultural significance;

method of completing wells;

hydraulic fracturing;

method of completing wells and hydraulic fracturing;

water withdrawal;

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emergency response, contingency plans and spill prevention plans;

air emissions and fluid discharges;

emissions and discharges permitting;

climate change;

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transportation of production.

Failure to comply with these laws and regulations can lead to the imposition of remedial liabilities, fines, or criminal penalties or to injunctions limiting Chesapeake's operations in affected areas.

Moreover, multiple environmental laws

provide for citizen suits that allow environmental organizations to act in the place of the government and sue operators for alleged violations of environmental law.

Chesapeake considers the costs of environmental protection and of safety and health compliance to be necessary, manageable parts of its business.

Chesapeake has been able to plan for and comply with environmental, safety and health laws and regulations without materially altering its operating strategy or incurring significant unreimbursed expenditures.

However, based on regulatory trends and increasingly stringent laws, Chesapeake's capital expenditures and operating expenses related to compliance with the protection of the environment, safety and health have increased over the years and may continue to increase.

Failure to comply with these laws and regulations can lead to the imposition of remedial liabilities, fines or penalties or injunctions limiting Chesapeake's operations in affected areas.

Moreover, multiple environmental laws provide for citizen suits that allow environmental organizations to act in the place of the government and sue operators for alleged

violations of environmental law.

Chesapeake considers the costs of environmental protection and of safety and health compliance necessary, manageable parts of its business.

Chesapeake has been able to plan for and comply with environmental, safety and health initiatives without materially altering its operating strategy or incurring significant unreimbursed expenditures.

However, based on regulatory trends and increasingly stringent laws, Chesapeake's capital expenditures and operating expenses related to the protection of the environment and safety and health compliance have increased over the years and may continue to increase.

Chesapeake cannot predict with any reasonable degree of certainty its future exposure concerning such matters.

See the Risk Factors described in Item 1A of this report for further discussion of governmental regulation and ongoing regulatory changes, including with respect to environmental matters,

Chesapeake's operations are also subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in a unit, the rate of production allowable from oil and gas wells, and the unitization or pooling of oil and gas properties.

In the United States, some states allow the forced pooling or integration of tracts to facilitate exploration.

Other states rely on voluntary pooling of lands and leases which may make it more difficult to develop oil and gas properties.

Chesapeake's operations also are subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in a unit, the rate of production allowable from oil and gas wells, and the unitization or pooling of oil and gas properties.

In the United States, some states allow the forced pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases, which may make it more difficult to develop oil and gas properties.

In addition, federal and state conservation laws generally limit the venting or flaring of natural gas, and state conservation laws impose certain requirements regarding the ratable purchase of production.

These regulations limit the amounts of oil and gas Chesapeake can produce from its wells and the number of wells or the locations at which it can drill.

For further discussion, see Item 1A.

Risk Factors - Chesapeake is subject to extensive governmental regulation, which can change and could adversely impact Chesapeake's business.

Regulatory proposals in some states and local communities have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations.

Federal and state agencies have continued to assess the potential impacts of hydraulic fracturing, which could spur further action toward federal, state and/or local legislation and regulation.

Further restrictions of hydraulic fracturing could reduce the amount of oil, natural gas and NGL that Chesapeake is ultimately able to produce in commercial quantities from its properties.

Further restrictions of hydraulic fracturing could make it prohibitive to conduct operations, and also reduce the amount of oil, natural gas and NGL that Chesapeake is ultimately able to produce in commercial quantities from its properties.

Certain of Chesapeake's U.S.

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Failure to comply with applicable regulations or permit requirements could result in revocation of Chesapeake's permits, inability to obtain new permits and the imposition of fines and penalties.

For further discussion, see Item 1A.

Risk Factors - Oil and natural gas drilling and producing operations can be hazardous and may expose Chesapeake to liabilities.

Operating Hazards and Insurance

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Chesapeake provides workers' compensation insurance coverage to employees in all states in which it operates.

While Chesapeake has informed us that it believes these policies are customary in the industry, they do not provide complete coverage against all operating risks and policy limits scale to Chesapeake's working interest

percentage in certain situations.

While Chesapeake has informed us that it believes these policies are customary in the industry, they do

not provide complete coverage against all operating risks and policy limits scale to Chesapeake's working interest percentage in certain situations.

In addition, Chesapeake's insurance does not cover penalties or fines that may be assessed by a governmental authority.

6 unchanged sentences

These amounts include 4,175 mboe of proved developed reserves and no proved undeveloped reserves as of December 31, 2019 and 5,075 mboe of proved developed reserves and no proved undeveloped reserves as of December 31, 2018 .

The decrease in estimated total reserves attributable to the Trust of 893 mboe is primarily attributable to 2018 production, partially offset by higher oil and gas prices.

See Risk Factors – Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the Trust and the valu e of the Trust units in Item 1A and Risks and Uncertainties in Note 2 to the financial statements contained in Part II, Item 8 of this Annual Report for further discussion of the decrease in reserves.

The decrease in estimated total reserves attributable to the Trust of 900 mboe is primarily attributable to 2019 production and lower oil and natural gas prices.

Risk Factors – Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the Trust and the valu e of the Trust units and Risks and Uncertainties in Note 2 to the financial statements contained in Part II, Item 8 of this Annual Report for further discussion of the decrease in reserves.

The Colony Granite Wash is a subset of the greater granite wash plays of the Anadarko Basin.

5 unchanged sentences

However, in the Colony Granite Wash, oil and NGL production currently generate more revenue than natural gas production due to higher relative prices for oil and NGL than for natural gas.

No development costs were incurred in the year ended December 31, 2018 and 2017 due to no new wells being drilled by Chesapeake in the Colony Granite Wash after Chesapeake's fulfillment of its drilling obligation to the Trust.

No development costs were incurred in the years ended December 31, 2019 and 2018 due to no new wells being drilled by Chesapeake in the Colony Granite Wash after Chesapeake's fulfillment of its drilling obligation to the Trust.

Royalty Interests.

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PV-10 for the Royalty Interests was calculated exclusive of any production or development costs.

($ in millions)

Estimated future net revenue (a)

Present value of estimated future net revenue (PV-10) (a)

Standardized measure (a)

($ in thousands)

Estimated future net revenue (1)

Present value of estimated future net revenue (PV-10) (1)

Standardized measure (1)

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However, as the Trust is not subject to income tax expense, the two measures are the same as of December 31, 2019 .

A reconciliation of the standardized measure of discounted future net cash flows to PV-10 is presented above.

A comparison of the standardized measure of discounted future net cash flows to PV-10 is presented above.

Neither PV-10 nor the standardized measure of discounted future net cash flows purport to represent the fair value of the proved oil and gas reserves.

The proved reserves were determined using a 12-month unweighted arithmetic average of the first-day-of-the-month prices for oil, natural gas and NGL for the period from January 1, 2019 through December 1, 2019, and were held constant for the life of the properties.

The prices used in the reserve reports, as well as Chesapeake's internal reports, yield weighted average prices at the wellhead, which are based on first-day-of-the-month reference prices and adjusted for transportation and regional price differentials.

For the Royalty Interests, costs of marketing services provided by Chesapeake's affiliates will not be charged to the Trust.

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As of December 31, 2019 , no Royalty Interests were classified as PUDs.

The annual net decline rate on current producing properties is projected to be 15% from 2019 to 2020, 13% from 2020 to 2021, 12% from 2021 to 2022 and 11% from 2022 to 2023.

As of December 31, 2019 , of the total proved reserves, 8,841 mboe and 4,175 mboe attributable to the Underlying Properties and the Royalty Interests, respectively, were classified as proved developed reserves.

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For the life of the Trust, Chesapeake will not be permitted to drill or complete any well that will have a perforated segment within 600 feet of any perforated interval of any Development Well or Producing Well.

Chesapeake's average net

revenue interest in the oil and gas properties underlying the Development Royalty Interest is approximately 63%.

The Development Royalty Interest entitles the Trust to receive 50% of the proceeds attributable to Chesapeake's net revenue interest in future production of oil, natural gas and NGL from the Development Wells.

Chesapeake's average net revenue interest in the oil and gas properties underlying the Development Royalty Interest is approximately 63%.

The Development Royalty Interest entitles the Trust to receive 50% of the proceeds attributable to Chesapeake's net

revenue interest in future production of oil, natural gas and NGL from the Development Wells.

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.

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CEMLLC enters into oil, natural gas and NGL sales arrangements with large aggregators of supply, and these arrangements may be on a month-to-month basis or for a term of up to one year or longer .

The oil, natural gas and NGL are sold at market prices and subsequently

any applicable post-production expenses will be deducted.

The oil, natural gas and NGL are sold at market prices and subsequently any applicable post-production expenses will be deducted.

CEMLLC sells production from the Underlying Properties to a diverse group of aggregators, the identity of which changes from time to time.

As a result, the proceeds to the Trust from the sales of oil, natural gas and NGL production from the Underlying Properties is determined based on the same price (net of post-production costs and production taxes) that Chesapeake receives from third parties for oil, natural gas and NGL production attributable to Chesapeake's remaining interest in the Underlying Properties.

As a result, the proceeds to the

Trust from the sales of oil, natural gas and NGL production from the Underlying Properties is determined based on the same price (net of post-production costs and production taxes) that Chesapeake receives from third parties for oil, natural gas and NGL production attributable to Chesapeake's remaining interest in the Underlying Properties.

Post-production expenses are deducted from proceeds paid to the Trust.

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Average sales prices are net of post-production expenses, including gathering, storage, compression, transportation, processing, treating, dehydrating and non-affiliate marketing expenses.

Production expenses include lease operating costs and ad valorem taxes.

Production taxes are generally based upon (a) volume produced and (b) prices received for production.

Production expenses include lease operating costs.

Production taxes are generally based upon volume produced and prices received for production and include ad valorem taxes.

Oil, Natural Gas and NGL Revenues.

For the year ended December 31, 2019 , oil, natural gas and NGL revenues were $12.9 million compared to $20.8 million for the year ended 2018 .

The $4.3 million decrease in revenues from 2017 to 2018 was primarily due to a decrease in production.

The $7.9 million decrease in revenues from 2018 to 2019 was due to a decrease in average sales prices received and a decrease in production.

The overall decrease in the price received per boe in 2019 compared to 2018 resulted in a $4.5 million decrease in oil, natural gas and NGL revenues.

Decreased sales volumes resulted in a $3.4 million decrease in oil, natural gas and NGL revenues.

Average oil prices increased $17.52 per bbl, from $42.80 per bbl for the year ended December 31, 2017 to $60.32 per bbl for the year ended December 31, 2018 .

Average natural gas prices increased $0.16 per mcf, from $0.46 per mcf for the year ended December 31, 2017 to $0.62 per mcf for the year ended December 31, 2018 .

NGL prices decreased $4.31 per bbl, from $21.22 per bbl for the year ended December 31, 2017 to $16.91 per bbl for the year ended December 31, 2018 .

The overall increase in the price received per boe in 2018 compared to 2017 resulted in a $1.4 million increase in oil, natural gas and NGL revenues, for a net decrease in oil, natural gas and NGL revenues of $4.3 million from 2017 to 2018.

Production Expenses.

For the year ended December 31, 2018 , production expenses, excluding production and ad valorem taxes, were $7.7 million compared to $7.6 million for the year ended 2017 .

On a unit-of-production basis, production expenses, excluding production taxes and including ad valorem taxes, were $5.63 per boe in 2018 compared to $4.32 per boe in 2017 .

For the year ended December 31, 2019 , production expenses were $7.2 million compared to $7.7 million for the year ended 2018 .

On a unit-of-production basis, production expenses were $6.32 per boe in 2019 compared to $5.63 per boe in 2018 .

Production Taxes.

1 unchanged sentence

On a unit-of-production basis, production taxes were $0.74 per boe in 2019 compared to $ 1.13 per boe in 2018 .

The increase in production taxes from 2017 to 2018 is primarily due to the increase in commodity prices.

The decrease in production taxes from 2018 to 2019 was primarily due to the decrease in commodity prices.

The Reserve Report for the Underlying Properties and the Royalty Interests

The oil, natural gas and NGL reserves in this Annual Report were estimated by Software Integrated Solutions, Division of Schlumberger Technology Corporation ("Software Integrated Solutions").

The process to review and estimate

the reserves begins with Chesapeake's Corporate Reserves Department collecting and verifying all pertinent data, including but not limited to well test data, production data, historical pricing, cost information, property ownership interests, reservoir data, and geosciences data.

The process to review and estimate the reserves begins with Chesapeake's Corporate Reserves Department collecting and verifying all pertinent data, including but not limited to well test data, production data, historical pricing, cost information, property ownership interests, reservoir data, and geosciences data.

This data is reviewed by various levels of Chesapeake management for accuracy before consultation with Software Integrated Solutions.

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Internal Controls .

Chesapeake's Director - Corporate Reserves is the technical person primarily responsible for overseeing the preparation of the Trust's reserve estimates.

Chesapeake's Director - Corporate Reserves is the technical person primarily responsible for overseeing the preparation of the Trust's reserve estimates and for coordinating any reserves work conducted by a third-party engineering firm.

Her qualifications include the following:

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 1. Business