PermRock Royalty Trust (Form: 10-K, Received: 03/30/2020 15:59:46)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2019

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___________ to ___________

Commission File Number: 001-38472

PERMROCK ROYALTY TRUST

(Exact name of registrant as specified in its charter)


Delaware	82-6725102
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

Simmons Bank, Trustee

P.O. Box 470727, Fort Worth, Texas 76147

(Address of principal executive offices)(Zip code)

(855) 588-7839

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:


Title of Each Class	Trading Symbol(s)	Name of Each Exchange on Which Registered
Units of Beneficial Interest	PRT	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No þ

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 þ 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 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, 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 þ		Smaller reporting company þ
		Emerging growth company þ

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 þ

The aggregate market value of Trust units representing beneficial interests in PermRock Royalty Trust held by non-affiliates on June 28, 2019 (the last business day of its most recently completed second fiscal quarter) was approximately $49,984,830 based on the closing price as quoted on the New York Stock Exchange. As of March 30, 2020, 12,165,732 Trust units representing beneficial interests in PermRock Royalty Trust were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: None

TABLE OF CONTENTS


		Page

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS		ii
GLOSSARY OF TERMS		iv

	PART I

Item 1.	Business	1
Item 1A.	Risk Factors	8
Item 1B.	Unresolved Staff Comments	22
Item 2.	Properties	22
Item 3.	Legal Proceedings	29
Item 4.	Mine Safety Disclosures	29

	PART II

Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	30
Item 6.	Selected Financial Data	30
Item 7.	Trustee’s Discussion and Analysis of Financial Condition and Results of Operations	30
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	37
Item 8.	Financial Statements and Supplementary Data	37
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	50
Item 9A.	Controls and Procedures	50
Item 9B.	Other Information	50

	PART III

Item 10.	Directors, Executive Officers and Corporate Governance	51
Item 11.	Executive Compensation	51
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	51
Item 13.	Certain Relationships and Related Transactions and Director Independence	52
Item 14.	Principal Accounting Fees and Services	52

	PART IV

Item 15.	Exhibits and Financial Statement Schedules	53
Item 16.	Form 10-K Summary	53

SIGNATURES		54

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain information included in this Annual Report on Form 10-K (“Annual Report”) contains, and other materials filed or to be filed by the PermRock Royalty Trust (the “Trust”) with the Securities and Exchange Commission (the “SEC”) (as well as information included in oral statements or other written statements made or to be made by the Trust) may contain or include, forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and Section 27A of the Securities Act of 1933, as amended (the “Securities Act”). Such forward-looking statements may be or may concern, among other things, Boaz Energy II, LLC’s (“Boaz Energy”) and Simmons Bank’s (as the trustee of the Trust (the “Trustee”)), expectations, beliefs and plans regarding: (i) Boaz Energy’s capital expenditure budget and anticipated expenditures, including waterflood projects and workovers; (ii) Boaz Energy’s 2020 outlook, including implementation of a new waterflood in the Permian Platform area and optimization of revenue on the Underlying Properties; (iii) estimated capital required for waterflood conformance work to capture certain reserves and maintain an efficient waterflood; (iv) timing for Boaz Energy’s recoupment of development expenses from the Trust; (v) amount and timing of cash reserves by the Trustee; (vi) drilling activity; (vii) estimated present value of future cash flows; (viii) characteristics of the Underlying Properties, including estimates regarding oil and gas reserves; (ix) the impact of a loss of any major customers; (vi) reliance on third parties for facilities and services; (x) the ability of Boaz Energy’s insurance coverage to cover certain claims; (xi) burdens and obligations affecting the Underlying Properties and their impact on the Underlying Properties and Net Profits Interest; (xii) the quality of Boaz Energy’s title to the Underlying Properties; (xiii) the impact of litigation on the Trust and regulatory matters; (xiv) the tax treatment of the Net Profits Interest; (xv) the treatment of the Net Profits Interest in the event of Boaz Energy’s bankruptcy; (xvi) distributions to Trust unitholders, including in the event of contingencies; and (xvii) future cash retentions from distributions. Such forward-looking statements generally are accompanied by words such as “may,” “will,” “estimate,” “expect,” “predict,” “project,” “anticipate,” “goal,” “should,” “assume,” “believe,” “plan,” “intend,” or other words that convey the uncertainty of future events or outcomes. Such statements are based on certain assumptions of the Trustee, and certain assumptions of information provided to the Trust by Boaz Energy, the owner of the Underlying Properties; are based on an assessment of, and are subject to, a variety of factors deemed relevant by the Trustee and Boaz Energy; and involve risks and uncertainties. The following important factors, in addition to those discussed elsewhere in this Annual Report, could affect the future results of the energy industry in general, and Boaz Energy and the Trust in particular, and could cause actual results to differ materially from those projected in such forward-looking statements:

the effect of changes in commodity prices or alternative fuel prices;

the effect of public health concerns such as the recent outbreak of coronavirus disease (COVID-19), or any government response to such outbreak;

political and economic conditions in or affecting other oil and natural gas producing regions or countries, for example, the failure of Saudi Arabia and Russia to reach an accord on oil production volumes, widely referred to as a “price war”;

uncertainties in estimating production and oil and natural gas reserves of the Underlying Properties;

risks associated with the drilling and operation of oil and natural gas wells;

the cost of developing the Underlying Properties;

the ability to maintain anticipated production levels;

the amount of future direct operating expenses, development expenses and other capital expenditures;

availability and terms of capital to fund capital expenditures;

risks associated with Boaz Energy and its ability to transfer operation of the Underlying Properties to third parties without the approval of Trust unitholders;

the performance of such third parties contracted by Boaz Energy and their ability or willingness to provide sufficient facilities and services to Boaz Energy on commercially reasonable terms;

the effect of existing and future laws and regulatory actions;

risks associated with derivative instruments, such as lower than expected production volumes, default of counterparties, and increases in price differentials;

conditions in the capital markets;

competition from others in the energy industry;

uncertainty in whether development projects will be pursued;

severe or unseasonable weather that may adversely affect production;

adequacy of Boaz Energy’s insurance coverage;

costs to comply with current and future governmental regulation of the oil and natural gas industry, including environmental, health and safety laws and regulations, and regulations with respect to hydraulic fracturing and the disposal of produced water;

the effect of existing and future laws and regulatory actions, including real estate, bankruptcy and tax legislation and the ability to accurately interpret the impact of such laws;

general economic conditions affecting the Permian Basin;

risks associated with title deficiencies that may arise with respect to the Underlying Properties and Boaz Energy’s ability to cure any such defects;

actions by Boaz Energy, including such that result in conflicts of interest, that adversely affect the Trust;

the ability to successfully estimate the impact of litigation matters, and certain accounting and tax matters;

the cost of inflation; and

the risk factors discussed in Item 1A of Part I of this Annual Report.

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 this Annual Report, which could affect the future results of the energy industry in general, and the Trust and Boaz Energy 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 Boaz Energy’s business and the Trust. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in such forward-looking statements. The Trust undertakes no obligation to publicly update or revise any forward-looking statements, except as required by applicable law.

Boaz Energy Information

As a holder of a Net Profits Interest, the Trust relies on Boaz Energy for information regarding Boaz Energy and its affiliates; the Underlying Properties, including the operations, acreage, well and completion count, working interests, production volumes, sales revenues, capital expenditures, operating expenses, reserves, drilling plans, drilling results and leasehold terms related to the Underlying Properties; and factors and circumstances that have or may affect the foregoing. See Part II, Item 9A Controls and Procedures.

iii

GLOSSARY OF TERMS


average realized sales price	The average sales price actually received for the sale of oil and natural gas, as distinguished from the NYMEX or other published prices.
Bbl	Barrel (of oil).
Boe	Barrel of oil equivalent.
Btu	A British Thermal Unit, a common unit of energy measurement.
completion	The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
developed oil and natural gas reserves	Reserves of any category that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. See 17 CFR § 210.4-10(aX6).
development well	A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
differential	The difference between a benchmark price of oil and natural gas, such as the NYMEX crude oil spot, and the wellhead price received.
distributable income	An amount paid to Trust unitholders equal to the net profits income received by the Trust during a given period plus interest, less the expenses and payment of liabilities of the Trust, adjusted by any changes in cash reserves.
estimated future net revenues	Computed by applying current oil and natural gas prices (with consideration of price changes only to the extent provided by contractual arrangements and allowed by federal regulation) to estimated future production of proved oil and natural gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions. See l7 CFR § 210.4-10(c)(4)(A). “Estimated future net revenues” are sometimes referred to in this Annual Report on Form 10-K as “estimated future net cash flows.”
farm-in or farm-out agreement	An agreement under which the owner of a working interest in an oil or natural gas lease typically assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a "farm-in" while the interest transferred by the assignor is a "farm-out."
field	An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
GAAP	United States generally accepted accounting principles.
gross acres or wells	The total acres or wells, as the case may be, in which a working interest is owned.
MBbl	One thousand barrels of crude oil or condensate.
MBoe	One thousand barrels of crude oil equivalent.
Mcf	One thousand cubic feet (of natural gas).
MMBoe	One million barrels of crude oil equivalent.
MMBtu	One million Btus.
MMcf	One million cubic feet (of natural gas).
natural gas liquids (NGL)	Those hydrocarbons that are separated from the gas as liquids through the process of absorption, condensation, or other methods in gas processing or cycling plants.


net profits	Gross profits received by Boaz Energy from the sale of production from the Underlying Properties, less applicable costs, as provided in the Conveyance.
net profits income	Net profits multiplied by the net profits percentage of 80%, which is paid to the Trust by Boaz Energy. “Net profits income” is referred to as “royalty income” for tax reporting purposes.
Net Profits Interest	An interest in an oil and natural gas property measured by net profits from the sale of production, rather than a specific portion of production. An 80% net profits interest was conveyed to the Trust entitling the Trust to receive 80% of the net profits from the Underlying Properties.
net acres or net wells	The sum of the fractional working interests owned by a given operator in gross acres or wells, as the case may be.
NGL non-operated	Natural gas liquids. Working interests which are part of the Underlying Properties but are not operated by Boaz Energy.
NYMEX	The New York Mercantile Exchange is a commodity futures exchange that quotes prices for transactions which are the prices paid for various commodities, including oil and natural gas, throughout the world.
plugging of abandoned wells	Activities to remove production equipment and seal off a well at the end of a well's economic life.
proved developed reserves	Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
proved reserves	Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil, elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.


proved undeveloped reserves (PUDs)	Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
PV-10	The present value of estimated future net revenues using a discount rate of 10% per annum.
reasonable certainty	(i) If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered or (ii) if probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease. See 17 CFR § 210.4-10(a)(24).
recompletion	The completion for production of an existing well bore in another formation from which that well has been previously completed.
reservoir	A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
secondary recovery	The second stage of hydrocarbon production during which an external fluid such as water or gas is injected into the reservoir through injection wells located in rock that has fluid communication with production wells. The purpose of secondary recovery is to maintain reservoir pressure and to displace hydrocarbons toward the wellbore. The most common secondary recovery techniques are gas injection and waterflooding.
Tcf	One trillion cubic feet of natural gas.
Trust units	Trust units representing beneficial interests in the Trust.
Underlying Properties	The interest in certain oil and natural gas properties from which the Net Profits Interest was conveyed by Boaz Energy. The Underlying Properties include working interests in oil and natural gas producing properties located in the Permian Basin in Texas.
waterflood	A method of secondary recovery in which water is injected into the reservoir formation to displace residual oil. The water from injection wells physically sweeps the displaced oil to adjacent production wells.
working interest	An operating interest in an oil and natural gas property that provides the owner a specified share of production that is subject to all production expense and development costs.
workover	Operations on a producing well to restore or increase production.

PART I

Item 1. Business

General

PermRock Royalty Trust (the “Trust”) is a Delaware statutory trust formed on November 22, 2017 under the Delaware Statutory Trust Act pursuant to a trust agreement dated November 22, 2017, as amended and restated on May 4, 2018, by and among Boaz Energy II, LLC (“Boaz Energy”), as trustor, Simmons Bank, as Trustee (the “Trustee”), and Wilmington Trust, National Association, as Delaware Trustee (the “Delaware Trustee”) (such amended and restated trust agreement, as amended to date, the “Trust Agreement”). The Trust’s affairs are administered by the Trustee, which maintains its offices at 2200 West 7^th Street, Suite 210, P.O. Box 470727, Fort Worth, Texas 76147.

The Trust was created to acquire and hold the Net Profits Interest for the benefit of the Trust unitholders. The affairs of the Trust are managed by the Trustee. Boaz Energy has no ability to manage the operations of the Trust, and, to the fullest extent permitted by law, does not owe any fiduciary duties or liabilities to the Trust or the unitholders. The Delaware Trustee has only minimal rights and duties as are necessary to satisfy the requirements of the Delaware Statutory Trust Act.

The Trust’s purpose is to own the Net Profits Interest, to distribute to the Trust unitholders cash that the Trust receives in respect of the Net Profits Interest and to perform certain administrative functions in respect of the Net Profits Interest and the Trust units. Other than the foregoing activities, the Trust does not conduct any operations or activities. The Trust derives all or substantially all of its income and cash flow from the Net Profits Interest. The Trust has no employees.

The Trust makes monthly cash distributions of all of its monthly cash receipts, after deduction of fees and expenses for the administration of the Trust and any cash reserves, to holders of its Trust units as of the applicable record date, on or before the 10th business day after the record date. Distributions generally relate to sales from a one-month period.

The Conveyance

In connection with the closing of the initial public offering of Trust units and pursuant to the Conveyance of Net Profits Interest (the “Conveyance”) effective May 4, 2018, Boaz Energy conveyed the Net Profits Interest to the Trust in exchange for Trust units. The Net Profits Interest entitles the Trust to receive 80% of the net profits from the sale of oil and natural gas production from the Underlying Properties. The Net Profits Interest is passive in nature and neither the Trust nor the Trustee has any control over, or responsibility for, costs relating to the operation of the Underlying Properties.

Permian Clearfork area – consists of 2,434 net acres on the Central Basin Platform of the Permian Basin in Hockley and Terry Counties, Texas.

Permian Abo area – consists of 1,667 net acres on the Central Basin Platform of the Permian Basin in Terry and Cochran Counties, Texas.

Permian Shelf area – consists of 14,727 net acres on the Eastern Shelf of the Permian Basin in Glasscock, Schleicher, Stonewall and Coke Counties, Texas.

Permian Platform area – consists of 4,169 net acres on the Central Basin Platform of the Permian Basin in Ward, Crane, Terry and Ector Counties, Texas.

A detailed description of the Underlying Properties is included under Item 2. Properties.

Computation of Net Profit

Net profits are computed monthly, and (i) 80% of the aggregate net profits attributable to the sale of oil and natural gas production from the Underlying Properties and (ii) any amounts received pursuant to derivative put option contracts (net of any costs associated therewith), received during each calendar month are paid to the Trust on or before the end of the following month. The derivative put option contracts that Boaz Energy had in place at the time of the Trust’s initial public offering have expired and after December 31, 2019, Boaz Energy no longer hedges any of the production attributable to the Underlying Properties.

“Gross profits” generally means the aggregate amount received by Boaz Energy from sales of oil and natural gas produced from the Underlying Properties subject to certain adjustments as described in the Conveyance. “Net profits” generally means gross profits less the costs and expenses for, among other things, drilling and development activities, production, operation, maintenance and abandonment operations, taxes, charges and assessments and insurance and, where applicable, losses, liabilities and damages, in each case as incurred by Boaz Energy and attributable to the Underlying Properties (as such items are reduced by any offset amounts, as described in the Conveyance).

The Trust is not liable to the owners of the Underlying Properties or the operators for any operating, capital or other costs or liabilities attributable to the Underlying Properties. In the event that the net profits for any computation period is a negative amount, the Trust will receive no payment for that period, and any such negative amount plus accrued interest will be deducted from gross profits in the following computation period for purposes of determining the net profits for that following computation period.

Gross profits and net profits are calculated on a cash basis, except that certain costs, primarily ad valorem taxes and expenditures of a material amount, may be determined on an accrual basis.

The Trustee is not obligated to return any cash received from the Net Profits Interest. Any overpayments made to the Trust by Boaz Energy due to adjustments to prior calculations of net profits or otherwise will reduce future amounts payable to the Trust until Boaz Energy recovers the overpayments plus interest at a prime rate (as described in the Conveyance).

Boaz Energy must maintain books and records sufficient to determine the amounts payable for the Net Profits Interest to the Trust. Monthly and annually, Boaz Energy must deliver to the Trustee a statement of the computation of the net profits for each computation period. The annual computation must be audited. The Trustee has the right to inspect, review and audit the books and records maintained by Boaz Energy during normal business hours and upon reasonable notice.

Marketing and Customers

Pursuant to the terms of the Conveyance, Boaz Energy has the responsibility to market, or cause to be marketed, the oil and natural gas production attributable to the Net Profits Interest in the Underlying Properties.

During the year ended December 31, 2019, Boaz Energy and other third-party operators of the Underlying Properties sold the oil produced from the Underlying Properties to third-party purchasers. Oil production from the Underlying Properties is typically transported by pipeline or truck from the field to the closest gathering facility or refinery. Boaz Energy and other operators sell the majority of the oil production from the Underlying Properties under contracts based on geographic location using market sensitive pricing. The price received by the operators for the oil production from the Underlying Properties is usually based on a regional price applied to equal daily quantities in the month of delivery that is then reduced for differentials based upon delivery location and oil quality.

All natural gas produced from the Underlying Properties is marketed and sold to third-party purchasers. In all cases, the contract price is based on a percentage of a published regional index price, after adjustments for Btu content, transportation and related charges. Natural gas production is typically transported by pipeline to the closest gathering facility. Natural gas that is processed to remove NGLs is done under a percentage of proceeds contract and the Trust’s percentage of those proceeds are included in the Net Profits Interest.

For the year ended December 31, 2019, Boaz Energy reported that Phillips 66, Plains All American Pipeline, Energy Transfer Partners and Blackbeard Operating LLC accounted for 29.57%, 26.37%, 13.85% and 10.18%, respectively, of its total oil and natural gas revenues, and that no other purchaser accounted for 10% or more of the total revenue of the Underlying Properties. Boaz Energy does not believe that the loss of any of these parties as a purchaser of crude oil or natural gas production from the Underlying Properties would have a material impact on the business or operations of Boaz Energy or the Underlying Properties because of the large number of marketing firms and competitive nature of oil and gas purchasers in the Permian Basin. Oil and natural gas are currently sold to these four customers under short-term contracts at market prices.

Competition and Markets

The oil and natural gas industry is highly competitive. Boaz Energy competes with major oil and natural gas companies and independent oil and natural gas companies for oil and natural gas, equipment, personnel and markets for the sale of oil and natural gas. Many of these competitors are financially stronger than Boaz Energy, but even financially troubled competitors can affect the market because of their need to sell oil and natural gas at any price to attempt to maintain cash flow. Because Boaz Energy and the third-party operators of the Underlying Properties are subject to competitive conditions in the oil and natural gas industry, the Trust’s Net Profits Interest is indirectly subject to those same competitive conditions.

Oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil, natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.

All of the Trust’s assets are located in the United States. Boaz Energy and the third-party operators of the Underlying Properties sell the oil and natural gas produced from the Underlying Properties to third-party purchasers in the United States. Demand for natural gas generally is higher in the winter months, but otherwise seasonal factors do not directly affect the Trust.

Dissolution of the Trust

The Trust is not subject to any pre-set termination provisions based on a maximum volume of oil or natural gas to be produced or the passage of time. The Trust will dissolve upon the earliest to occur of the following:

the Trust, upon the approval of the holders of at least 75% of the outstanding Trust units, sells the Net Profits Interest;

the annual cash proceeds received by the Trust attributable to the Net Profits Interest are less than $2.0 million for each of any two consecutive years;

the holders of at least 75% of the outstanding Trust units vote in favor of dissolution; or

the Trust is judicially dissolved.

Upon dissolution of the Trust, the Trustee is obligated to sell all of the Trust’s assets, either by private sale or public auction, and, after payment or the making of reasonable provision for payment of all liabilities of the Trust, distribute the net proceeds of the sale to the Trust unitholders.

Environmental Matters and Regulation

General. For purposes of the discussion in this section, the oil and natural gas production operations conducted on the Underlying Properties are the operations of Boaz Energy. Boaz Energy’s oil and natural gas exploration and production operations are subject to stringent and comprehensive federal, regional, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose significant obligations on the Boaz Energy’s operations, including, but not limited to, requirements to:

obtain permits to conduct regulated activities;

limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas;

restrict the types, quantities and concentration of materials that can be released into the environment in the performance of drilling and production activities;

initiate investigatory and remedial measures to mitigate pollution from former or current operations, such as restoration of drilling pits and plugging of abandoned wells; and

apply specific health and safety criteria addressing worker protection.

Failure to comply with environmental laws and regulations may result in the assessment of administrative, civil and criminal sanctions, including monetary penalties, the imposition of strict, joint and several liability, investigatory and remedial obligations and the issuance of injunctions limiting or prohibiting some or all of the operations on the Underlying Properties. Moreover, these laws, rules and regulations may restrict the rate of oil, natural gas and NGL production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. The trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly construction, drilling, water management, completion, emission or discharge limits or waste handling, disposal or remediation obligations could increase the cost to Boaz Energy of developing the Underlying Properties. Moreover, accidental releases or spills may occur in the course of operations on the Underlying Properties, causing Boaz Energy to incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons.

Increased costs or operating restrictions on the Underlying Properties as a result of compliance with or liability under environmental laws could result in reduced exploratory and production activities on the Underlying Properties and, as a result, distributable cash to the Trust unitholders. The following is a summary of certain existing environmental, health and safety laws and regulations, each as amended from time to time, to which operations on the Underlying Properties are subject.

Hazardous Substances and Waste Handling

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) also known as the Superfund law, and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. Under CERCLA, these “responsible persons” may include the owner or operator of the site where the release occurred, and entities that transport, dispose of or arrange for the transport or disposal of hazardous substances released at the site. These responsible persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

The Resource Conservation and Recovery Act (“RCRA”) and comparable state laws control the management and disposal of hazardous and non-hazardous waste. These laws and regulations govern the generation, storage, treatment, transfer and disposal of wastes generated. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of oil, natural gas and NGLs, if properly handled, are currently exempt from regulation as hazardous waste under RCRA and, instead, are regulated under RCRA’s less stringent non-hazardous waste provisions, state laws or other federal laws. However, it is possible that certain oil, natural gas and NGL drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address the EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil, natural gas and NGL wastes from regulation as hazardous wastes under RCRA. The consent decree required the EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil, natural gas and NGL wastes or to sign a determination that revision of the regulations is not necessary (which deadline was extended to April 23, 2019 due to a lapse in appropriations). On April 23, 2019, EPA made a determination that revisions to the federal regulations for the management of exploration and production waste under Subtitle D of RCRA are not necessary and issued a report explaining the basis for its decision. EPA stated it will continue to work to identify areas for regulatory improvements and to address emerging issues to ensure exploration and production wastes continue to be managed appropriately. Any future regulatory change due to emerging issues, a change in EPA determination, or otherwise could result in an increase in the costs to manage and dispose of wastes, which could increase the costs of Boaz Energy’s operations.

Certain of the Underlying Properties have been used for oil and natural gas exploration and production for many years. Although the operators may have utilized operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons and wastes may have been disposed of or released on or under the Underlying Properties, or on or under other offsite locations where these petroleum hydrocarbons and wastes have been taken for recycling or disposal. The Underlying Properties and the petroleum hydrocarbons and wastes disposed or released thereon may be subject to CERCLA, RCRA and analogous state laws. Under such laws, the owner or operator could be required to remove or remediate previously disposed wastes, to clean up contaminated property and to perform remedial operations such as restoration of pits and plugging of abandoned wells to prevent future contamination or to pay some or all of the costs of any such action.

Water Discharges

The Federal Water Pollution Control Act, also known as the “Clean Water Act,” and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil, into federal and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Obtaining permits has the potential to delay the development of oil and natural gas projects. In addition, federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. In June 2015, the EPA and the U.S. Army Corps of Engineers (the “Corps”) published a final rule attempting to clarify the federal jurisdictional reach over waters of the United States (“WOTUS”). Several legal challenges to the rule followed, along with attempts to stay implementation following the change in presidential administration. Currently, the WOTUS rule is active in some states and enjoined in others. However, on December 11, 2018, the EPA and the Corps proposed changes to regulations under the CWA that would provide discrete categories of jurisdictional waters and tests for determining whether a particular waterbody meets any of those classifications. On February 14, 2019, the EPA published the proposed new rule defining the scope of waters federally regulated under the Clean Water Act for public comment in the Federal Register. Environmental groups and states have sued to challenge the new rule. Therefore, the scope of jurisdiction under the CWA is uncertain at this time. Spill prevention, control and countermeasure plan requirements imposed under the Clean Water Act require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The Oil Pollution Act of 1990, as amended, or “OPA,” amends the Clean Water Act and establishes strict liability and natural resource damages liability for unauthorized discharges of oil into waters of the United States. OPA requires owners or operators of certain onshore facilities to prepare Facility Response Plans for responding to a worst case discharge of oil into waters of the United States.

Air Emissions

The CAA and comparable state laws restrict the emission of air pollutants from many sources through air emissions permitting programs and also impose various monitoring and reporting requirements. These laws and regulations may require Boaz Energy to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or incur development expenses to install and utilize specific equipment or technologies to control emissions. For example, in June 2016 the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. Any such requirements could increase the costs of development and production on the Underlying Properties, potentially impairing the economic development of the Underlying Properties and reducing the amount of cash distributable to Trust unitholders. Obtaining permits has the potential to delay the development of oil and natural gas projects. Federal and state regulatory agencies may impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations.

Climate Change

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish PSD, construction and Title V operating permit reviews for certain large stationary sources.

At the federal level, no comprehensive climate change legislation has been implemented to date. The EPA has, however, adopted rules under authority of the CAA that, among other things, establish Potential for Significant Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are also potential major sources of certain principal, or criteria, pollutant emissions. Under these regulations, facilities required to obtain PSD permits must meet “best available control technology” standards for those GHG emissions. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the U.S., including, among others, onshore and offshore production facilities, which include certain operations on the Underlying Properties. The EPA has expanded the GHG reporting requirements to all segments of the oil and natural gas industry, including gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil wells.

Federal agencies also have begun directly regulating emissions of methane from oil and natural gas operations. For example, in June 2016, the EPA published New Source Performance Standards (“NSPS”), known as Subpart OOOOa, that requires certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions. However, on August 28, 2019, the EPA published a notice of reconsideration proposing to rescind methane-specific requirements for new and modified oil and gas infrastructure, and litigation concerning the regulations is ongoing. As a result, we cannot predict the scope of any final methane regulatory requirements or the cost to comply with such requirements.

At the international level, in December 2015, the United States and 194 other participating countries adopted the Paris Agreement, which calls for each participating country to establish their own nationally determined standards for reducing carbon output. However, in August 2017 the United States notified the United Nations that it would be withdrawing from the Paris Agreement and, on November 4, 2019, formally notified the United Nations of its withdrawal. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may reenter the Paris Agreement or separately negotiated agreement are unclear at this time. Various state and local governments have publicly committed to furthering the goals of the Paris Agreement.

The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise restrict emissions of GHGs could result in increased compliance costs or additional operating restrictions for Boaz Energy, and could have a material adverse effect on our business, financial condition and results of operations. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that oil and gas will continue to represent a major share of global energy use through 2040, and other private sector studies project continued growth in demand for the next two decades. However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector. Moreover, activist shareholders have introduced proposals that may seek to force companies to adopt aggressive emission reduction targets or to shift away from more carbon-intensive activities. While we cannot predict the outcomes of such proposals, they could make it more difficult for Boaz Energy to engage in exploration and production activities, ultimately reducing distributable cash to Trust unitholders. Finally, many scientists have concluded that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climate events that could have an adverse effect on operations of the Underlying Properties and, as a result, the amount of cash distributable to Trust unitholders.

Hydraulic Fracturing Activities

Boaz Energy engages in hydraulic fracturing. Hydraulic fracturing is a common practice that is used to stimulate production of hydrocarbons from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Currently, hydraulic fracturing is generally exempt from regulation under the U.S. Safe Drinking Water Act’s Underground Injection Control program and is typically regulated by state oil and gas commissions or similar agencies.

However, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, in June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants. Additionally, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain limited circumstances. From time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. In the event that new federal restrictions relating to the hydraulic fracturing process are adopted in areas where we own mineral or royalty interests, Boaz Energy may incur additional costs or permitting requirements to comply with such federal requirements that may be significant and that could result in added delays or curtailment in Boaz Energy’s pursuit of exploration, development or production activities, which would in turn reduce the oil, natural gas and NGLs produced from the Underlying Properties.

Moreover, some states and local governments have adopted, and other governmental entities are considering adopting, regulations that could impose more stringent permitting, disclosure and well-construction requirements on hydraulic fracturing operations, including states in which the Underlying Properties are located. For example, Texas has adopted regulations that impose new or more stringent permitting, disclosure, disposal and well construction requirements on hydraulic fracturing operations. States could also elect to prohibit high volume hydraulic fracturing altogether. In addition to state laws, local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in particular.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to, and litigation concerning, oil, natural gas and NGL production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs for Boaz Energy in the production of oil, natural gas and NGLs, including from the developing shale plays, or could make it more difficult for Boaz Energy to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in Boaz Energy’s completion of new oil and natural gas wells on the Underlying Properties and an associated decrease in the distributable cash in the Trust.

Endangered Species Act and Migratory Birds Treaty Act

In the United States, the Endangered Species Act (the “ESA”) restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”). To the extent species that are listed under the ESA or similar state laws, or are protected under the MBTA, live in the areas where the Underlying Properties are located, Boaz Energy’s abilities to conduct or expand operations on the Underlying Properties could be limited, or Boaz Energy could be forced to incur material additional costs. Moreover, Boaz Energy’s drilling activities may be delayed, restricted or precluded in protected habitat areas or during certain seasons, such as breeding and nesting seasons.

In addition, as a result of one or more settlements approved by the U.S. Fish & Wildlife Service (the “FWS”), the agency was required to make a determination on the listing of numerous other species as endangered or threatened under the ESA by the end of the FWS’ 2017 fiscal year. The agency missed the deadline, and the review is reportedly ongoing. On August 12, 2019, the FWS finalized a package of ESA regulatory revisions addressing standards for listing, delisting, and reclassification of species, consultation parameters, and protections for threatened species, changes which are expected to ease the path for development projects. Nonetheless, the designation of previously unidentified endangered or threatened species could cause Boaz Energy’s operations to become subject to operating restrictions or bans, and limit future development activity in affected areas. For example, recently, there have been renewed calls to review protections currently in place for the Dunes Sagebrush Lizard, whose habitat includes portions of the Permian Basin, and to reconsider listing the species under the ESA. If the Dunes Sagebrush Lizard or other species are listed, the FWS and similar state agencies may designate critical or suitable habitat areas that they believe are necessary for the survival of threatened or endangered species. Such a designation could materially restrict use of or access to federal, state and private lands. To the extent species are listed under the ESA or similar state laws, or previously unprotected species are designated as threatened or endangered in areas where the Underlying Properties are located, operations on the Underlying Properties could incur increased costs arising from species protection measures and face delays or limitations with respect to production activities thereon.

Employee Health and Safety

Operations on the Underlying Properties are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, or “OSHA,” and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens.

Available Information

The Trust maintains a website at www.permrock.com. The SEC maintains an internet site that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC. The Trust’s filings under the Exchange Act are available on the website and are also available electronically from the website maintained by the SEC at www.sec.gov.

Item 1A. Risk Factors

Risks Related to the Units

Described below are certain risks that we believe are associated with an investment in the units of the Trust and the oil and natural gas industry. There may be additional risks that are not presently material or known to us. You should carefully consider each of the following risks and all other information set forth in this Annual Report on Form 10-K. If any of the events described below occur, the Trust’s financial condition could be materially adversely affected, and the Trust may not be able to continue as a going concern.

Oil and natural gas prices are volatile, and lower oil and natural gas prices could reduce proceeds to the Trust and cash distributions to Trust unitholders.

The Trust’s reserves and monthly cash distributions are highly dependent upon the prices realized from the sale of oil and natural gas. Oil and natural gas are commodities, and their prices can be volatile and fluctuate widely in response to market uncertainty and relatively minor changes in the supply of and demand for oil and natural gas. Factors that affect oil and natural gas prices include, among others:

worldwide and regional economic conditions impacting the global supply of and demand for oil and natural gas;

the price and quantity of foreign imports and U.S. exports of oil and natural gas;

the effect of public health concerns such as the recent outbreak of COVID-19, or any government response to such outbreak;

expectations about future prices of, or the supply of and demand for oil and natural gas;

the effects of the United Kingdom’s withdrawal from the European Union, known as “Brexit”;

seasonal energy consumption trends, weather conditions and other natural disasters;

the volatility and uncertainty of regional pricing differentials, particularly prevailing prices on local price indexes in the Permian Basin;

technological advances affecting energy consumption, energy storage and energy supply;

the price and availability of alternative fuels;

the proximity, capacity, cost and availability of gathering and transportation facilities;

U.S. federal, state and local governmental regulation and taxation;

energy conservation and environmental measures; and

acts of force majeure.

Lower prices of oil and natural gas will reduce profits to which the Trust is entitled and therefore the cash available for distribution to unitholders and may ultimately reduce the amount of oil and natural gas that is economic to produce from the Underlying Properties. The volatility of oil and natural gas prices also reduces the predictability of future cash distributions to unitholders. Oil prices have declined sharply in the first quarter of 2020 in response to the economic effects of the recent announcements by Saudi Arabia to abandon output restraints and the COVID-19 pandemic. Substantial and extended declines in oil, natural gas and natural gas liquids prices have resulted and may continue to result in reduced net proceeds to which the Trust is entitled, which could materially reduce or completely eliminate the amount of cash available for distribution to Trust unitholders, and may ultimately reduce the amount of oil and natural gas that is economic to produce from the Underlying Properties. Sustained lower prices of oil and natural gas could also negatively affect the price of the Trust units and the qualification of the Trust units to remain listed on the New York Stock Exchange.

Because the monthly distributions correlate with the net profits generated each month after payment of costs and expenses related to the Underlying Properties (including direct operating expenses and development expenses), future monthly distributions paid to the Trust unitholders will vary significantly from month to month and may be zero in any given month. Boaz Energy entered into derivative put option contracts with respect to expected oil production in 2018 and 2019, however, those contracts have expired as of December 31, 2019 and Boaz Energy has not entered into any derivative contracts relating to oil and natural gas volumes expected to be produced after December 31, 2019. The terms of the Conveyance prohibit Boaz Energy from entering into new hedging arrangements burdening the Trust or the Underlying Properties. As a result, the amount of cash distributions are subject to a greater fluctuation after December 31, 2019 due to changes in oil and natural gas prices.

The reserves attributable to the Underlying Properties are depleting assets and production from those reserves will diminish over the long term and may eventually cease, therefore, proceeds to the Trust and cash distributions to Trust unitholders will decrease over time and may eventually cease.

The profits payable to the Trust attributable to the Net Profits Interest are derived from the sale of production of oil and natural gas from the Underlying Properties. The reserves attributable to the Underlying Properties are depleting assets, which means that the reserves and the quantity of oil and natural gas produced from the Underlying Properties will decline over time. Actual decline rates have varied and likely will continue to vary from the decline rates projected in reserve reports.

Maintenance projects on the Underlying Properties have affected and will likely continue to affect the quantity of proved reserves that can be economically produced from wells on the Underlying Properties.The timing and size of these maintenance projects will depend on, among other factors, the market prices of oil and natural gas. Boaz Energy is not under contractual obligation to develop or otherwise pay maintenance or other development expenses on the Underlying Properties in the future. Furthermore, with respect to properties for which Boaz Energy is not designated as the operator, Boaz Energy has limited control over the timing or amount of those maintenance projects and other development expenses. Boaz Energy also has the right to non-consent and not participate in maintenance projects and other development activities on properties for which it is not the operator, in which case Boaz Energy and the Trust will not receive the production resulting from such maintenance projects and other development expenses until after payout occurs pursuant to the applicable joint operating agreement. If Boaz Energy or any third-party operator does not implement maintenance projects when warranted, the future rate of production decline of proved reserves may be higher than the rate currently expected by Boaz Energy or estimated in reserve reports. Furthermore, the Trust is not permitted to acquire other oil and natural gas properties or net profits interests to replace the depleting assets and production attributable to the Net Profits Interest.

Because the net profits payable to the Trust are derived from the sale of depleting assets, the portion of the distributions to Trust unitholders attributable to depletion may be considered to have the effect of a return of capital as opposed to a return on investment. Eventually, the Underlying Properties burdened by the Net Profits Interest may cease to produce in commercially paying quantities and the Trust may, therefore, cease to receive any distributions of net profits therefrom.

An increase in the differential between the price realized by Boaz Energy for oil or natural gas produced from the Underlying Properties and the NYMEX or other benchmark price of oil or natural gas could reduce the profits to the Trust and, therefore, the cash distributions by the Trust and the value of Trust units.

The prices received for Boaz Energy’s oil and natural gas production have generally been lower than the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. The difference between the price received and the benchmark price is called a basis differential. The differential may vary significantly due to market conditions, the quality and location of production and other factors, including a regional oversupply of oil in the Permian Basin due to current take-away constraints. Boaz Energy cannot accurately predict oil or natural gas differentials in the future. Increases in the differential between the realized price of oil and natural gas and the benchmark price for oil and natural gas could reduce the profits to the Trust, the cash distributions by the Trust and the value of the Trust units.

Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the Trust and the value of the Trust units.

The value of the Trust units and the amount of future cash distributions to the Trust unitholders will depend upon, among other things, the accuracy of the reserves and future production estimated to be attributable to the Trust’s interest in the Underlying Properties. It is not possible to measure underground accumulations of oil and natural gas in an exact way, and estimating reserves is inherently uncertain. Ultimately, actual production and revenues for the Underlying Properties could vary both positively and negatively and in material amounts from the estimates contained in the reserve reports. Furthermore, direct operating expenses and development expenses relating to the Underlying Properties could be substantially higher than current estimates. Petroleum engineers are required to make subjective estimates of underground accumulations of oil and natural gas based on factors and assumptions that include:

historical production from the area compared with production rates from other producing areas;

oil and natural gas prices, production levels, Btu content, production expenses, transportation costs, severance and other taxes and development expenses;

the availability of enhanced recovery techniques;

relationships with landowners, operators, pipeline companies and others; and

the assumed effect of expected governmental regulation and future tax rates.

Changes in these assumptions and amounts of actual direct operating expenses and development expenses could materially decrease reserve estimates. In addition, the quantities of recovered reserves attributable to the Underlying Properties have decreased, and may decrease in the future, as a result of future decreases in the price of oil or natural gas.

Developing oil and natural gas wells and producing oil and natural gas are costly and high-risk activities with many uncertainties that could adversely affect future production from the Underlying Properties. Any delays, reductions or cancellations in development and producing activities could decrease revenues that are available for distribution to Trust unitholders.

Recovery of proved undeveloped reserves and the development of proved developed non-producing reserves requires capital expenditures and successful drilling operations by Boaz Energy and other third-party operators of the Underlying Properties. The reserve data included in the reserve report of Boaz Energy’s independent petroleum engineer assumes a certain amount of capital expenditures will be made to develop such reserves. The Net Profits Interest bears its proportionate share of these capital expenditures. However, the development of such reserves has in the past and may in the future take longer and may require higher levels of capital expenditures than anticipated. Delays in the development of the reserves, increases in drilling and development costs (including expenses related to secondary and tertiary recovery techniques) of such reserves or decreases or continued volatility in commodity prices will reduce the future net revenues of the estimated proved undeveloped reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could force Boaz Energy to reclassify certain of the proved reserves as unproved reserves.

In addition, the process of developing oil and natural gas wells and producing oil and natural gas on the Underlying Properties is subject to numerous risks beyond Boaz Energy’s control, including risks that could delay Boaz Energy’s or any third-party operators’ current drilling or production schedule and the risk that drilling will not result in commercially viable oil or natural gas production. The ability of the operators to carry out operations or to finance planned development expenses could be materially and adversely affected by any factor that may curtail, delay, reduce or cancel development and production, including:

delays imposed by or resulting from compliance with environmental and other governmental or regulatory requirements, including permitting requirements, limitations on or resulting from wastewater discharge and disposal of exploration and production wastes, including, subsurface injections, as well as additional regulation with respect to GHG emissions;

pressure or irregularities in geological formations;

restricted access to land for drilling or laying pipeline;

lack of available gathering, transportation and processing facilities, including availability on commercially reasonable terms, or delays in construction of gathering facilities;

lack of available capacity on interconnecting transmission pipelines;

equipment failures or accidents;

failure of secondary recovery operations to perform as expected;

unexpected operational events and drilling conditions;

declines in oil or natural gas prices;

limitations in the market for oil or natural gas;

pipe or cement failures;

casing collapses;

shortages, unavailability or high cost of drilling rigs, tubular materials, equipment, supplies, personnel and services;

lost or damaged drilling and service tools;

loss of drilling fluid circulation;

uncontrollable flows of oil and natural gas, water or drilling fluids;

blowouts, explosions fires and natural disasters;

environmental hazards, such as oil and natural gas leaks, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;

adverse weather conditions, such as drought, floods, blizzards, tornados and ice storms; and

title problems or legal disputes regarding leasehold rights.

In the event that planned operations by Boaz Energy or other operators, including drilling of development wells, are delayed or cancelled, or existing wells or development wells have lower than anticipated production due to one or more of the factors above or for any other reason, estimated future distributions to Trust unitholders may be reduced. In the event an operator incurs increased costs due to one or more of the above factors or for any other reason and is not able to recover such costs from insurance, the estimated future distributions to Trust unitholders may be reduced.

Higher production and development costs related to the Underlying Properties and other costs and expenses incurred by the Trust without concurrent increases in revenue, will result in decreased Trust distributions.

The Trust indirectly bears an 80% share of all costs and expenses related to the Underlying Properties, such as direct operating expenses and development expenses (including waterflood expenses), which reduces the amount of cash received by the Trust and distributed to Trust unitholders. Historical costs may not be indicative of future costs, and higher costs and expenses related to the Underlying Properties without concurrent increases in revenue will directly decrease the amount of cash received by the Trust in respect of its Net Profits Interest. In addition, cash available for distribution by the Trust will be further reduced by the Trust’s general and administrative expenses.

If direct operating expenses and development expenses on the Underlying Properties together with the other costs exceed gross profits of production from the Underlying Properties, the Trust will not receive net profits from those properties until future gross profits from production exceed the total of the excess costs, plus accrued interest at the prime rate. If the Trust does not receive net profits pursuant to the Net Profits Interest, or if such net profits are reduced, the Trust will not be able to distribute cash to the Trust unitholders, or such cash distributions will be reduced, respectively. Development activities may not generate sufficient additional revenue to repay the costs.

The generation of cash for distribution by the Trust depends in part on access to and operation of gathering, transportation and processing facilities on commercially reasonable terms or otherwise. Any limitation in the availability of those facilities could interfere with sales of oil and natural gas production from the Underlying Properties.

The marketing of oil and natural gas production depends in large part on the capacity and availability of gathering systems and other pipelines, trucks, storage facilities and other transportation, processing and refining facilities. If these facilities are unavailable on commercially reasonable terms or otherwise, production from the Underlying Properties could be shut in or Boaz Energy or the third-party operators could be required to delay or discontinue drilling plans and commercial production. Boaz Energy relies (and expects to rely in the future) on facilities developed and owned by third parties in order to transport, store, process and sell the oil and natural gas production from the Underlying Properties. Boaz Energy’s plan to develop and sell its oil and natural gas could be materially and adversely affected by the inability or unwillingness of third parties to provide sufficient facilities and services to Boaz Energy on commercially reasonable terms, or otherwise.

The amount of oil and natural gas that can be produced and sold from a well is subject to limitation in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, failure of tendered oil and natural gas to meet quality specifications of gathering lines or downstream transporters, excessive pressure, damage to the gathering, transportation, refining or processing facilities or lack of capacity at such facilities. Increases in activity in the Permian Basin could, in the future, contribute to bottlenecks in processing and transportation that could negatively affect the production, transportation and sale of oil and natural gas from the Underlying Properties, and these adverse effects could be disproportionately severe compared to more geographically diverse operations. If Boaz Energy or the third-party operators are forced to reduce production due to such a curtailment, the revenues of the Trust and the amount of cash distributions to the Trust unitholders would similarly be reduced due to the reduction of profits from the sale of production.

Boaz Energy or any other operator of any Underlying Property may abandon the property, thereby terminating the related Net Profits Interest payable to the Trust that are attributable to the abandoned property.

Boaz Energy or any third-party operator of the Underlying Properties could determine during periods of low commodity prices, including as a result of COVID-19, to shut in or curtail production from wells on the Underlying Properties or plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Boaz Energy or any other operator may abandon any well or property without the consent of the Trust or the Trust unitholders if it reasonably believes that the well or property can no longer produce oil or natural gas in commercially paying quantities. This could result in termination of the Net Profits Interest relating to the abandoned well or property. The Underlying Properties are sensitive to decreasing commodity prices. The commodity price sensitivity is due to a variety of factors that vary from well to well, including the costs associated with water handling and disposal, chemicals, surface equipment maintenance, downhole casing repairs and reservoir pressure maintenance activities that are necessary to maintain production. As a result, the volatility of commodity prices may cause the expenses of certain wells to exceed the well’s revenue. If this scenario were to occur, Boaz Energy or any third-party operator may decide to shut-in the well or plug and abandon the well. This could reduce future cash distributions to Trust unitholders.

A significant portion of the reserves associated with and production from the Underlying Properties will be influenced by the success of secondary recovery techniques. There are uncertainties associated with such techniques and, if these recovery methods do not result in expected production levels, net profits available for distribution to Trust unitholders could be less than expected.

A significant portion of the future production from the Underlying Properties will be associated with secondary recovery projects that are in the early or intermediate stage of implementation. As a result, there can be no assurance that these operations will perform as expected or consistently with the analogous secondary recovery operations used by Boaz Energy in establishing its reserve and production estimates. As secondary recovery techniques such as waterflooding are used, the amount of oil recovered is expected to first increase as a result of such techniques and then will begin to decline over the long term. Risks associated with secondary recovery techniques include, but are not limited to, the following:

higher than projected operating costs;

lower-than-expected production;

longer response times;

unusual or unexpected geological formations;

fluctuations in oil and natural gas prices;

regulatory changes;

shortages of equipment; and

lack of technical expertise.

If these secondary recovery operations do not result in achieving projected production, then the reserves associated with the Underlying Properties may be less than expected.

The standardized measure of the estimated proved oil and natural gas reserves attributable to the Trust’s interest in the Underlying Properties and the associated PV-10 calculation are not necessarily the same as the current market value of those estimated reserves.

The present value of future net cash flow from the proved reserves attributable to the Trust’s interest in the Underlying Properties, or standardized measure, and the related PV-10 calculation, may not represent the current market value of the Trust’s interest in the estimated proved oil and natural gas reserves of the Underlying Properties. In accordance with SEC requirements, the Trust bases the estimated discounted future net cash flow from estimated proved reserves on the 12-month average oil index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month and costs in effect as of the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than current estimates. In addition, the 10% discount factor the Trust uses when calculating discounted future net cash flow for reporting requirements in compliance with the Financial Accounting Standard Board Codification 932, “Extractive Activities-Oil and Gas,” may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Trust or the oil and natural gas industry in general.

The Trust is passive in nature and neither the Trust nor the Trust unitholders have any ability to influence Boaz Energy and other third-party operators or control the operation or development of the Underlying Properties.

The Trust units are a passive investment that entitle the Trust unitholder to only receive cash distributions from the Net Profits Interest conveyed to the Trust. Trust unitholders have no voting rights with respect to Boaz Energy and, therefore, have no managerial, contractual or other ability to influence Boaz Energy’s or other third-party operators’ activities or the operations of the Underlying Properties. Boaz Energy operated approximately 85% of the production from the Underlying Properties as of December 31, 2019 and is generally responsible for making all decisions relating to drilling activities, sale of production, compliance with regulatory requirements and other matters that affect such properties. Boaz Energy may take actions that are in its own interest that may be different from the interests of the Trust. The failure of Boaz Energy or any other third-party operator to conduct its operations, discharge its obligations and comply with regulatory requirements could have an adverse effect on the net profits payable to the Trust.

The unavailability or high cost of equipment, supplies, personnel and services could increase costs of developing and operating the Underlying Properties and result in a reduction in the amount of cash available for distribution to the Trust unitholders.

The demand for qualified and experienced personnel to conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling and workover rigs, pipe and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, supplies, personnel and services. Higher oil and natural gas prices generally stimulate demand and result in increased process for drilling rigs, crews and associated supplies, equipment and services. Shortages of field personnel and equipment or price increases could hinder the ability to conduct operations. The occurrence, timing and duration of these conditions in the future is impossible to predict. Such shortages could delay development and/or operating activities or cause a significant increase in development and operating expenses associated with the Underlying Properties, which would reduce the amount of cash received by the Trust and available for distribution to the Trust unitholders.

The Trust units may lose value as a result of title deficiencies with respect to the Underlying Properties.

Boaz Energy acquired the Underlying Properties through various acquisitions since October 2013. The existence of a material title deficiency with respect to the Underlying Properties could reduce the value of a property or render it worthless, thus adversely affecting the Net Profits Interest and the distributions to Trust unitholders. Boaz Energy does not obtain title insurance covering mineral leaseholds, and Boaz Energy’s failure to cure any title defects may cause Boaz Energy to lose its rights to production from the Underlying Properties. In the event of any such material title problem, profits available for distribution to Trust unitholders and the value of the Trust units may be reduced.

Boaz Energy may transfer all or a portion of the Underlying Properties at any time without Trust unitholder consent, subject to specified limitations.

Boaz Energy may at any time transfer all or part of the Underlying Properties, subject to and burdened by the Net Profits Interest, and may abandon its interest in any individual wells or properties if Boaz Energy, acting as a reasonable and prudent operator, believes a well or property has ceased to produce or is not capable of producing in commercially paying quantities. Trust unitholders are not entitled to vote on any transfer or abandonment of the Underlying Properties, and the Trust will not receive any profits from any such transfer, except in the limited circumstances when the Net Profits Interest is released in connection with such transfer, in which case the Trust will receive an amount equal to the fair value (net of sales costs) of the Net Profits Interest released. Following any sale or transfer of any of the Underlying Properties, if the Net Profits Interest is not released in connection with such sale or transfer, the Net Profits Interest would continue to burden the transferred property and net profits attributable to such property would continue to be calculated as part of the computation of net profits. Boaz Energy may assign to the transferee responsibility for all of Boaz Energy’s obligations relating to the Net Profits Interest on the portion of the Underlying Properties transferred. A transferee of the Underlying Properties may operate the Underlying Properties differently than Boaz Energy and may determine not to pursue development projects to the same extent as Boaz Energy or at all.

In addition, Boaz Energy may, without the consent of the Trust unitholders, require the Trust to release the Net Profits Interest associated with the sale of any interest in the Underlying Properties that accounted for no more than 1.0% of the total production from the Underlying Properties in the prior 12 months, provided that Boaz Energy may not require the release during any 365-day period of portions of the Net Profits Interest having an aggregate fair value to the Trust of greater than $500,000 (a “Qualified De Minimis Sale”). These releases will be made only in connection with a sale by Boaz Energy of the relevant Underlying Properties and the Trust will receive an amount equal to the fair value (net of sales costs) of the Net Profits Interest released.

In addition, Boaz Energy may cause the Trustee to (i) sell all or any part of the Trust estate, including all or any portion of the Net Profits Interest or (ii) release any portion of the Net Profits Interest in connection with the sale, free from and unburdened by the Net Profits Interest, by Boaz Energy and/or its affiliates of a divided or undivided portion of their interests in the Underlying Properties, if approved by Trust unitholders holding at least 75% of the outstanding Trust units, provided that, after December 31, 2022, such a sale or release shall require approval of a majority of the outstanding Trust units if Boaz Energy and its affiliates own less than 25% of the outstanding Trust units. The net proceeds of any such sale or the consideration received in respect of such release, as applicable, shall be distributed to the Trust unitholders in the manner approved by the Trust unitholders at such meeting.

Boaz Energy may also enter into farm-out, operating, participation and other similar agreements to develop the property without the consent or approval of the Trustee or any Trust unitholder.

All of the Underlying Properties are concentrated in the Permian Basin, making the Trust vulnerable to risks associated with operating in only one major geographic area.

As a result of the Trust’s geographic concentration, an adverse development in the industry in the Permian Basin could have a greater impact on revenues of the Trust and the amount of cash distributions to the Trust unitholders than if the Underlying Properties were more geographically diverse. The Underlying Properties may also be disproportionately exposed to the impact of adverse developments in exploration and production of oil and natural gas, regional supply and demand factors, governmental regulation or midstream capacity constraints. Delays or interruptions caused by such factors could have a material adverse effect on revenues of the Trust and the amount of cash distributions to the Trust unitholders.

Similarly, the concentration of the Underlying Properties within the Permian Basin exposes the Trust to risks, which could adversely affect development activities or production relating to such formations. In addition, in areas where exploration and production activities are increasing, Boaz Energy could be subject to increasing competition for drilling rigs, equipment, services, supplies and qualified personnel, which may lead to periodic shortages or delays. The curtailments arising from these and similar circumstances may last from a few days to several months, and in many cases, Boaz Energy may be provided only limited, if any, notice as to when such circumstances will arise and their duration.

The Trustee must, under certain circumstances, sell the Net Profits Interest and dissolve the Trust prior to the expected termination of the Trust. If this were to occur, Trust unitholders may not recover their investment.

The Trustee must sell the Net Profits Interest and dissolve the Trust if the holders of 75% of the outstanding units approve the sale of the Net Profits Interest or approve the dissolution of the Trust. The Trustee must also sell the Net Profits Interest and dissolve the Trust if the annual gross profits from the Underlying Properties attributable to the Net Profits Interest are less than $2.0 million for each of any two consecutive years. The Trust will receive the net proceeds of any such sale, and will distribute such proceeds to its unitholders after deducting Trust expenses.

Boaz Energy may sell Trust units in the public or private markets, and such sales could have an adverse impact on the trading price of the Trust units.

Boaz Energy holds an aggregate of 5,878,332 Trust units, as of March 30, 2020. Boaz Energy or its owners, including NGP Energy Capital Management (“NGP”), may sell Trust units in the public or private markets, and any such sales could have an adverse impact on the price of the Trust units or on any trading market that may develop. The Trust has granted registration rights to Boaz Energy and its affiliates, including NGP, and their respective transferees, which, if exercised, would facilitate sales of Trust units by Boaz Energy or its owners, as applicable.

The trading price for the Trust units may not reflect the value of the Net Profits Interest held by the Trust.

The trading price for publicly traded securities similar to the Trust units tends to be tied to recent and expected levels of cash distributions as well as oil and natural gas prices. The amounts available for distribution by the Trust vary in response to numerous factors outside the control of the Trust, including prevailing prices for sales of oil and natural gas production from the Underlying Properties and the timing and amount of direct operating expenses and development expenses. Consequently, the market price for the Trust units may not necessarily be indicative of the value that the Trust would realize if it sold the Net Profits Interest to a third-party buyer. In addition, such market price may not necessarily reflect the fact that, since the assets of the Trust are depleting assets, a portion of each cash distribution paid with respect to the Trust units should be considered by investors as a return of capital, with the remainder being considered as a return on investment. As a result, distributions made to a Trust unitholder over the life of these depleting assets may not equal or exceed the purchase price paid by the Trust unitholder.

Conflicts of interest could arise between Boaz Energy and its affiliates, on the one hand, and the Trust and the Trust unitholders, on the other hand.

As working interest owners in, and the operator of substantially all of the production from the Underlying Properties, Boaz Energy and its affiliates could have interests that conflict with the interests of the Trust and the Trust unitholders. For example:

Boaz Energy’s interests may conflict with those of the Trust and the Trust unitholders in situations involving the development, maintenance, operation or abandonment of certain wells on the Underlying Properties for which Boaz Energy acts as the operator. Boaz Energy may also make decisions with respect to development expenses that adversely affect the Underlying Properties. These decisions include not incurring or reducing development expenses on properties for which Boaz Energy acts as the operator, which could cause the Trust to not achieve the production growth projected in the reserve report or could cause oil and natural gas production to decline at a faster rate and thereby result in lower cash distributions by the Trust in the future.

Boaz Energy may sell some or all of the Underlying Properties without taking into consideration the interests of the Trust unitholders. Such sales may not be in the best interests of the Trust unitholders. These purchasers may lack Boaz Energy’s experience or its credit worthiness. Boaz Energy also has the right, under certain circumstances, to cause the Trust to release all or a portion of the Net Profits Interest in connection with a sale of a portion of the Underlying Properties to which such Net Profits Interest relates. In such an event, the Trust is entitled to receive the fair value (net of sales costs) of the Net Profits Interest released.

Boaz Energy and its affiliates have registration rights and can sell Trust units without considering the effects such sale may have on Trust unit prices or on the Trust itself. Additionally, Boaz Energy and its affiliates can vote their Trust units in their sole discretion without considering the interests of the other Trust unitholders. Boaz Energy is not a fiduciary with respect to the Trust unitholders or the Trust and does not owe any fiduciary duties or liabilities to the Trust unitholders or the Trust.

Boaz Energy owns and operates oil and natural gas properties that are not included in the Underlying Properties. As a result, Boaz Energy’s management team may dedicate their time and effort to the management of these other properties. Additionally, Boaz Energy is under no obligation to dedicate financial resources to the Underlying Properties and may decide to direct capital expenditures to these other properties.

The Trust is administered by a Trustee who cannot be replaced except by a majority vote of the Trust unitholders at a special meeting, which may make it difficult for Trust unitholders to remove or replace the Trustee.

The affairs of the Trust are managed by the Trustee. The voting rights of Trust unitholders are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of Trust unitholders or for an annual or other periodic re-election of the Trustee, and the Trust does not intend to hold annual meetings of Trust unitholders. The Trust Agreement provides that the Trustee may only be removed and replaced by the holders of a majority of the Trust units present in person or by proxy at a meeting of such holders where a quorum is present, including Trust units held by Boaz Energy, called by either the Trustee or the holders of not less than 10% of the outstanding Trust units. As a result, it will be difficult for public Trust unitholders to remove or replace the Trustee without the cooperation of Boaz Energy so long as it holds a significant percentage of total Trust units.

Trust unitholders have limited ability to enforce provisions of the Conveyance creating the Net Profits Interest, and Boaz Energy’s liability to the Trust is limited.

The Trustee has the power and authority to cause the Trust to sue Boaz Energy or any other future owner of the Underlying Properties to enforce the terms of the Conveyance creating the Net Profits Interest. If the Trustee does not take appropriate action to cause the Trust to enforce provisions of the Conveyance, Trust unitholders’ recourse would likely be limited to bringing a lawsuit against the Trustee to compel the Trustee to take specified actions or, subject to any restrictions in the governing instrument to the Trust, to bring a derivative action seeking authority to bring an action in the name of the Trust to enforce provisions of the Conveyance. As a result, Trust unitholders will not be able to sue Boaz Energy or any future owner of the Underlying Properties to enforce these rights. However, such limitations do not apply to or otherwise limit any claims that the Trust unitholders may have under the federal securities laws. Furthermore, the Conveyance provides that, except as set forth in the Conveyance, Boaz Energy is not liable to the Trust for the manner in which it performs its duties in operating the Underlying Properties as long as it acts without gross negligence or willful misconduct. Further, the Trust Agreement will provide that, to the fullest extent permitted by law, Boaz Energy and its affiliates shall not be subject to fiduciary duties or be liable for conflicts of interest principles.

Courts outside of Delaware may not recognize the limited liability of the Trust unitholders provided under Delaware law.

Under the Delaware Statutory Trust Act, Trust unitholders are entitled to the same limitation of personal liability extended to stockholders of corporations for profit under the General Corporation Law of the State of Delaware. No assurance can be given, however, that the courts in jurisdictions outside of Delaware will give effect to such limitation.

For as long as the Trust is an emerging growth company and a smaller reporting company, it will not be required to comply with certain disclosure requirements that apply to other public companies.

The Trust is an “emerging growth company” as defined in the Jumpstart Our Business Act (“JOBS Act”). For as long as the Trust is an emerging growth company, which may be up to five full fiscal years, unlike other public companies, the Trust will not be required to, among other things, (1) provide an auditor’s attestation report on the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes‑Oxley Act, (2) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (3) comply with any new audit rules adopted by the PCAOB after April 5, 2012 unless the SEC determines otherwise or (4) provide certain disclosures regarding executive compensation required of larger public companies.

In addition, Section 102 of the JOBS Act also provides that an “emerging growth company” can use the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933, as amended (the “Securities Act”), for complying with new or revised accounting standards. An “emerging growth company” can therefore delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. The Trust intends to take advantage of all of the reduced reporting requirements and exemptions under Section 107 of the JOBS Act until it is no longer an emerging growth company. Accordingly, the information that the Trust provides you may be different than the information you may receive from other public companies in which you hold equity interests.

Additionally, the Trust is currently a “smaller reporting company” as defined in the Exchange Act and, in the event that the Trust is still considered a smaller reporting company at such time as it ceases being an emerging growth company, it will be exempt from the provisions of Section 404(b) of the Sarbanes-Oxley Act of 2002 requiring that an independent registered public accounting firm provide an attestation report on the effectiveness of internal control over financial reporting.

The operations of the Underlying Properties are subject to complex federal, state, local and other laws and regulations, including environmental laws and regulations, that could adversely affect the cost, manner or feasibility of conducting operations on them or result in significant costs and liabilities, which could reduce the amount of cash available for distribution to Trust unitholders.

The oil and natural gas exploration and production operations on the Underlying Properties are subject to stringent and comprehensive federal, state and local laws and regulations, including laws governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations, some of which are discussed under “Environmental Matters and Regulation,” may impose numerous obligations that apply to the operations on the Underlying Properties, including the requirement to obtain a permit before conducting drilling, secondary recovery, waste disposal or other regulated activities; the restriction of types, quantities and concentrations of materials that can be released into the environment; restrictions on water withdrawal and use; and the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas. Compliance with such laws and regulations may generate significant costs, such as development expenses to install pollution or safety-related controls at the operated facilities, and impose substantial liabilities for pollution resulting from operations. Failure to comply with these and other laws and regulations may result in litigation, the assessment of administrative, civil or criminal penalties; the imposition of investigatory or remedial obligations; and the issuance of injunctions limiting or preventing some or all of the operations on the Underlying Properties. Furthermore, the inability to comply with environmental laws and regulations in a cost-effective manner, such as removal and disposal of produced water and other generated oil and natural gas wastes, could impair the production of oil and natural gas from the Underlying Properties in a commercial manner, which could further result in a reduction of distributable cash to the Trust unitholders.

There is inherent risk of incurring significant environmental costs and liabilities in the course of operations on the Underlying Properties as a result of the handling of petroleum hydrocarbons and wastes, air emissions and wastewater discharges related to operations, and historical industry operations and waste disposal practices, which in turn could decrease the profitability of the Underlying Properties and result in a reduction of distributable cash to the Trust unitholders. As discussed under “Environmental Matters and Regulation,” Boaz Energy can also be subject to remediation costs related to contamination, which have the potential to adversely affect production on the Underlying Properties and could consequently result in a reduction of distributable cash to the Trust unitholders. Private parties, including the owners of properties upon which wells are drilled and facilities where petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. In addition, the risk of accidental spills or releases could expose the Underlying Properties to significant liabilities that could have a material adverse effect on their financial condition and results of operations, which in turn could reduce the amount of cash available for distribution to Trust unitholders. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly operational control requirements or waste handling, storage, transport, disposal or cleanup requirements could require operations on the Underlying Properties to incur significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on their results of operations, competitive position or financial condition, which could subsequently adversely affect the distribution of cash to the Trust unitholders.

The Trust indirectly bears 80% of all costs and expenses paid by Boaz Energy, including those related to environmental compliance and liabilities associated with the Underlying Properties, including costs and liabilities resulting from conditions that existed prior to Boaz Energy’s acquisition of the Underlying Properties unless such costs and expenses result from the operator’s negligence or misconduct. In addition, as a result of the increased cost of compliance, Boaz Energy may decide to discontinue drilling.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in Boaz Energy incurring increased costs, additional operating restrictions or delays and fewer potential drilling locations.

As discussed under “Environmental Matters and Regulation – Hydraulic Fracturing Activities,” in recent years there has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies and to induce seismic events. As a result, from time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. In the event that new federal restrictions relating to the hydraulic fracturing process are adopted in areas where the Underlying Properties are located, Boaz Energy and outside operators may incur additional costs or permitting requirements to comply with such federal requirements that may be significant and that could result in added delays or curtailment in the pursuit of exploration, development or production activities, which would in turn reduce the oil, natural gas and NGLs produced from the Underlying Properties.

In addition, some states such as Texas, where the Underlying Properties are located, have adopted regulations that impose new or more stringent permitting, disclosure, disposal and well construction requirements on hydraulic fracturing operations. States could also elect to prohibit high volume hydraulic fracturing altogether. In addition to state laws, local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in particular.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to, and litigation concerning, oil, natural gas and NGL production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs for our operators in the production of oil, natural gas and NGLs, including from the developing shale plays, or could make it more difficult for Boaz Energy and outside operators to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in Boaz Energy’s completion of new oil and natural gas wells on the Underlying Properties and an associated decrease in the cash distributable to Trust unitholders.

The adoption and implementation of international, federal or state climate change legislation or regulations could result in increased operating costs for Boaz Energy and reduced demand for the oil, natural gas and NGLs that Boaz Energy produces.

The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise restrict emissions of GHGs, as described under “Environmental Matters and Regulation – Climate Change,” could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on Boaz Energy’s business, financial condition and results of operations. Recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for operators to engage in exploration and production activities, ultimately reducing income generated from the Underlying Properties and, as a result, the cash distributable to Trust unitholders. Moreover, such new legislation or regulatory programs could also increase the cost to consumers, and thereby reduce demand for oil and natural gas, which could reduce the demand for the oil or natural gas produced and lower the value of the reserves.

The potential physical effects of climate change could disrupt production on the Underlying Properties and cause Boaz Energy and other third-party operators to incur significant costs, thereby reducing cash distributable to Trust unitholders.

Some scientists have concluded that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climate events. Extreme weather conditions can interfere with production on the Underlying Properties and increase Boaz Energy’s operating expenses. Such damage or increased expenses from extreme weather may not be fully insured. If any such effects were to occur, they could have an adverse effect on Boaz Energy’s results of operations and, as a result, the cash distributable to Trust unitholders.

The amount of cash available for distribution by the Trust could be reduced by expenses caused by uninsured claims.

Boaz Energy maintains insurance coverage against potential losses that it believes is customary in its industry. Boaz Energy is not required to maintain any minimum levels of insurance and its ability to maintain any such coverages will depend on conditions in the insurance markets among other factors beyond Boaz Energy’s control. In addition, Boaz Energy’s general liability insurance and excess liability policies do not provide coverage with respect to legal and contractual liabilities of the Trust, and the Trust does not maintain such coverage since it is passive in nature and does not have any ability to influence Boaz Energy or control the operations or development of the Underlying Properties. Boaz Energy does not currently have any insurance policies in effect that are intended to provide coverage for losses solely related to waterflooding or other completion operations. These policies may not cover fines, penalties or costs and expenses related to government-mandated remediation of pollution. In addition, these policies do not provide coverage for all liabilities, and Boaz Energy cannot assure you that the insurance coverage will be adequate to cover claims that may arise, including due to potential effects of climate change, or that Boaz Energy will be able to maintain adequate insurance at rates it considers reasonable. The occurrence of an event not fully covered by insurance could result in a significant decrease in the amount of cash available for distribution by the Trust.

Additional restrictions on drilling activities intended to protect certain species of wildlife may adversely affect Boaz Energy’s and other third-party operators' ability to conduct drilling activities.

In the United States, the ESA restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the MBTA. To the extent species that are listed under the ESA or similar state laws, or are protected under the MBTA, live in the areas where the Underlying Properties are located, Boaz Energy’s abilities to conduct or expand operations on the Underlying Properties could be limited, or Boaz Energy could be forced to incur material additional costs. Moreover, Boaz Energy’s drilling activities may be delayed, restricted or precluded in protected habitat areas or during certain seasons, such as breeding and nesting seasons.

In addition, the designation of previously unidentified endangered or threatened species could cause Boaz Energy’s operations to become subject to operating restrictions or bans, and limit future development activity in affected areas. For example, there have been renewed calls to review protections currently in place for the Dunes Sagebrush Lizard, whose habitat includes portions of the Permian Basin, and to reconsider listing the species under the ESA. If the Dunes Sagebrush Lizard or other species are listed, the FWS and similar state agencies may designate critical or suitable habitat areas that they believe are necessary for the survival of threatened or endangered species. Such a designation could materially restrict use of or access to federal, state and private lands. To the extent species are listed under the ESA or similar state laws, or previously unprotected species are designated as threatened or endangered in areas where the Underlying Properties are located, operations on the Underlying Properties could incur increased costs arising from species protection measures and face delays or limitations with respect to production activities thereon.

Terrorism and continued geopolitical hostilities could adversely affect the Trust’s distributions to its unitholders or the market price of its units.

Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign, as well as military or other actions taken in response to such attacks or threats, could cause instability in the global financial, oil and natural gas markets. Terrorism and other geopolitical hostilities could adversely affect the Trust’s distributions to its unitholders or the market price of its units in unpredictable ways, including through the disruption of oil and natural gas supplies and markets, increased volatility in oil and natural gas prices, or the possibility that the infrastructure on which the operators of the Underlying Properties rely could be a direct target or an indirect casualty of an act of terror.

A bankruptcy of Boaz Energy or any third-party operator could adversely affect the operation of the wells and the development of the proved undeveloped reserves and interrupt or decrease distributions to Trust unitholders.

The value of the Net Profits Interest and the Trust’s ultimate cash available for distribution are highly dependent on Boaz Energy’s financial condition. Neither Boaz Energy nor any other operator of the Underlying Properties has agreed with the Trust to maintain a certain net worth or to be restricted by other similar covenants, and Boaz Energy is not obligated to retain and is not retaining all of the net proceeds of this offering to pay costs of operating and developing the Underlying Properties. In addition, Boaz Energy is not required to retain ownership of its Trust units and may sell such units or distribute such units, or the proceeds from the sale thereof, to its owners. The ability to develop and operate the Underlying Properties depends on Boaz Energy’s future financial condition and economic performance and access to capital, which in turn will depend upon the supply of and demand for oil and natural gas, prevailing economic conditions and financial, business and other factors, many of which are beyond the control of Boaz Energy. If the reduced demand for crude oil in the global market as a result of the economic effects of the outbreak of COVID-19, and the recent reduction in the benchmark price of crude oil, persist for the near future or longer, such factors could have a material negative impact on the financial condition and economic performance of Boaz Energy or one or more of the third-party operators of the Underlying Properties.

The bankruptcy of Boaz Energy or any third-party operator of the Underlying Properties could impede the operation of the wells and the development of the proved undeveloped reserves and decrease distributions to the Trust unitholders. For example:

The working interest owners in the affected properties may have to seek a new party to perform the development and the operations of the affected wells. The right to replace an operator would be subject to the terms of any joint operating agreement, and the exercise thereof could be subject to the automatic stay in the operator’s bankruptcy case. Boaz Energy or the other working interest owners may not be able to find a replacement operator, and they may not be able to enter into a new agreement with such replacement party on favorable terms within a reasonable period of time.

The payment of any accrued but unpaid oil and natural gas revenues payable on the Net Profits Interest at the time of a bankruptcy case filing by Boaz Energy or another operator could be delayed or such amounts may be misapplied or not paid to the Trust at all, which would result in a general unsecured claim in favor the Trust against Boaz Energy’s (or the applicable operator’s) bankruptcy estate. There is no certainty that such unsecured claim would receive a distribution from the bankruptcy estate.

Executory contracts to which Boaz Energy or another operator is party (including midstream and transportation contracts) would be subject to possible rejection in the bankruptcy case, which would result in a loss of access to the service provided by the counterparty to such contracts.

The counterparties to Boaz Energy’s derivative contracts would not be subject to the automatic stay in bankruptcy and would be permitted to terminate such derivative contracts, which would result in Boaz Energy losing the benefit of such contracts and could result in any termination payment being applied by a counterparty to other obligations owed to the counterparty by Boaz Energy and therefore not to the Trust.

Boaz Energy is not a reporting company and is not be required to file periodic reports with the SEC pursuant to the Exchange Act. Therefore, Trust unitholders do not have access to financial information about Boaz Energy.

The business of Boaz Energy could be negatively affected by various security threats, including cybersecurity threats, and other disruptions.

Boaz Energy faces various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of the facilities and infrastructure of Boaz Energy and of third parties on which Boaz Energy relies such as processing plants and pipelines. These threats pose a risk to the security of Boaz Energy’s systems and networks, the confidentiality, availability and integrity of its data and the physical security of its employees and assets. Boaz Energy relies on information technology (“IT”) systems and networks in connection with its business activities, including certain of its exploration, development and production activities. Boaz Energy relies on digital technology, including information systems and related infrastructure, as well as cloud applications and services, to, among other things, estimate quantities of oil, natural gas and NGL reserves, analyze seismic and drilling information, process and record financial and operating data and communicate with employees and third parties. As dependence on digital technologies has increased in the oil and gas industry, cyber incidents, including deliberate attacks and attempts to gain unauthorized access to computer systems and networks, have increased in frequency and sophistication. Boaz Energy has experienced cyber-attacks in the past, and may not be successful in preventing future security breaches or cyber-attacks or mitigating their effect. Any security breach or cyber-attack could have a material adverse effect on Boaz Energy’s reputation and competitive position and could lead to losses of sensitive information, critical infrastructure or capabilities essential to Boaz Energy’s operation of the Underlying Properties, its calculation of gross and net profits and its remittance of payments in respect of the Net Profits Interest to the Trust. Cyber-attacks or security breaches also could result in litigation or regulatory action. In addition, Boaz Energy’s implementation of various procedures and controls to monitor and mitigate security threats, including cybersecurity threats, and to increase security for its information, facilities and infrastructure may result in increased capital and operating costs.

Future net profits income to the Trust may be subject to risks relating to the creditworthiness of third parties.

The Trust does not lend money and has limited ability to borrow money. The Trust’s future net profits income, however, may be subject to risks relating to the creditworthiness of the operators of the Underlying Properties and purchasers of the oil and natural gas produced from the Underlying Properties. This creditworthiness may be impacted by the price of oil and natural gas.

Tax Risks Related to the Trust Units

The Trust has not requested a ruling from the IRS regarding the tax treatment of the Trust. If the IRS were to determine (and be sustained in that determination) that the Trust is not a “grantor trust” for U.S. federal income tax purposes, the Trust could be subject to more complex and costly tax reporting requirements that could reduce the amount of cash available for distribution to Trust unitholders.

If the Trust were not treated as a grantor trust for U.S. federal income tax purposes, the Trust should be treated as a partnership for such purposes. Although the Trust would not become subject to U.S. federal income taxation at the entity level as a result of treatment as a partnership, and items of income, gain, loss and deduction would flow through to the Trust unitholders, the Trust’s tax reporting requirements would be more complex and costly to implement and maintain, and its distributions to Trust unitholders could be reduced as a result.

If the Trust were treated for U.S. federal income tax purposes as a partnership, it would likely be subject to new audit rules that alter the procedures for auditing large partnerships and assessing and collecting income taxes due (including applicable penalties and interest) as a result of an audit. These rules effectively would impose an entity level tax on the Trust, and Trust unitholders might have to bear the expense of the adjustment even if they were not Trust unitholders during the audited taxable year.

Neither Boaz Energy nor the Trustee has requested a ruling from the IRS regarding the tax status of the Trust, and neither Boaz Energy nor the Trust can assure you that such a ruling would be granted if requested or that the IRS will not challenge these positions on audit.

Trust unitholders should be aware of any possible state tax implications of owning Trust units.

Trust unitholders are required to pay U.S. federal income taxes on their share of the Trust’s income, even if they do not receive any cash distributions from the Trust.

Trust unitholders are treated as if they own the Trust’s assets and receive the Trust’s income and are directly taxable thereon as though the Trust were not in existence. Because the Trust generates taxable income that can be different in amount than the cash the Trust distributes, Trust unitholders are required to pay any U.S. federal income taxes and, in some cases, state and local income taxes, on their share of the Trust’s taxable income even if they receive no cash distributions from the Trust. Trust unitholders may not receive cash distributions from the Trust equal to their share of the Trust’s taxable income or even equal to the actual tax liability that results from that income.

A portion of any gain recognized on the disposition of the Trust units could be taxed as ordinary income.

A Trust unitholder who sells his Trust units will recognize a gain or loss equal to the difference between the amount realized and the Trust unitholder’s adjusted tax basis in those Trust units. A substantial portion of any gain recognized may be taxed as ordinary income due to potential recapture items, including depletion recapture.

The Trust generally allocates its items of income, gain, loss and deduction between transferors and transferees of the Trust units based upon the monthly record date. The IRS may challenge this treatment.

The Trust generally allocates its items of income, gain, loss and deduction between transferors and transferees of the Trust units each month based upon the ownership of the Trust units on the monthly record date, instead of the date a particular Trust unit is transferred. The IRS could disagree with this allocation method and could assert that income and deductions of the Trust should be determined and allocated on a daily or prorated basis, which could require adjustments to the tax returns of the affected Trust unitholders and result in an increase in the administrative expense of the Trust in subsequent periods.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Description of the Underlying Properties

The Underlying Properties consist of 35,390 gross (22,997 net) acres in the Permian Basin. The Permian Basin extends over 75,000 square miles in West Texas and Southeastern New Mexico, consists of multiple, stacked hydrocarbon-bearing formations and has produced over 30 billion Bbls of oil and more than 75 Tcf of natural gas since its discovery in 1921. The basin is further characterized by a favorable operating environment, high oil and liquids-rich natural gas content, significant in-place midstream infrastructure, a well-developed network of oilfield service providers and long-lived reserves with generally consistent geologic attributes and reservoir quality.

The Underlying Properties consist of long-life reserves in mature, conventional oil fields with established decline curves. As of December 31, 2019, the Underlying Properties had proved reserves of 10.9 MMBoe and 55% of the volumes and 57% of PV-10 value were attributable to proved developed reserves. Approximately 92% of the 10.9 MMBoe of proved reserves, based on PV-10 value, were operated by Boaz Energy. For more information regarding changes in proved reserves, see Note 12 to the financial statements included in Item 8 of this Annual Report.

Major Producing Areas

The Underlying Properties consist of the following four operating areas:

The Permian Clearfork area consists of 2,434 net acres on the Central Basin Platform of the Permian Basin in Hockley and Terry Counties, Texas. A majority of the production in the Permian Clearfork area comes from wells in the Kingdom Clearfork field, which primarily produce from the Clearfork formation. Boaz Energy's waterflooding operations were first implemented in the Kingdom Clearfork field in March 2015. As of December 31, 2019, Cawley, Gillespie & Associates, Inc. (“Cawley Gillespie”) estimates the Underlying Properties in the Permian Clearfork to have 4.3 MMBoe of total proved reserves, 44% of which are proved developed reserves. Decreased reserves in the Permian Clearfork area were primarily the result of a negative price revision.

The Permian Abo area consists of 1,667 net acres on the Central Basin Platform of the Permian Basin in Terry and Cochran Counties, Texas. A majority of the production in the Permian Abo area comes from wells in the Kingdom Abo field, which primarily produce from the Abo formation. In 2011, a waterflood pilot program was implemented in the North West Terry Abo unit (“NWTA”) located in the Kingdom Abo field that converted one producing well to an injection well. Boaz Energy fully converted the field to water injection upon purchasing the NWTA in June 2016, and in January 2017 installed a new injection pump that added an additional injection capacity of 2,500 barrels of water per day. In August 2017, NWTA 313 demonstrated initial waterflood response. As of December 31, 2019, Cawley Gillespie estimates the Underlying Properties in the Permian Abo to have 2.0 MMBoe of total proved reserves, 79% of which are proved developed reserves.

The Permian Shelf area consists of 14,727 net acres on the Eastern Shelf of the Permian Basin in Glasscock, Schleicher, Stonewall and Coke Counties, Texas. A significant portion of the production in the Permian Shelf area comes from wells in the Fort McKavitt and Flowers fields, which primarily produce from the Canyon formation. A significant portion of the production in the Permian Shelf area comes from wells in the Fort McKavitt and Flowers fields, which primarily produce from the Canyon formation. As of December 31, 2019, Cawley Gillespie estimates the Underlying Properties in the Permian Shelf to have 3.1 MMBoe of total proved reserves, 37% of which are proved developed reserves.

The Permian Platform area consists of 4,169 net acres on the Central Basin Platform of the Permian Basin in Ward, Crane, Terry and Ector Counties, Texas. The properties primarily produce from the Clearfork, San Andres, and Devonian formations. The properties primarily produce from the Clearfork, San Andres, and Devonian formations. As of December 31, 2019, Cawley Gillespie estimates the Underlying Properties in the Permian Platform to have 1.4 MMBoe of total proved reserves, 95% of which are proved developed.

Oil and Natural Gas Data

Proved Reserves

Cawley Gillespie, independent petroleum and geological engineers, estimated crude oil and natural gas (including natural gas liquids) proved reserves of the Underlying Properties’ full economic life and for the Trust life as of December 31, 2019. Numerous uncertainties are inherent in estimating reserve volumes and values, and the estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of the reserves may vary significantly from the original estimates. In addition, the reserves and net revenues attributable to the Net Profits Interest include only 80% of the reserves attributable to the Underlying Properties that are expected to be produced within the term of the Net Profits Interest. The technical person primarily responsible for overseeing the review of the third-party reserve reports is Casey Morton, Boaz Energy's Executive Vice President, Engineering. Mr. Morton received a Bachelor of Science in Petroleum Engineering from Texas Tech University in 2003. Prior to joining Boaz Energy, Mr. Morton served as an engineer for Netherland, Sewell & Associates from September 2008 to January 2012. Mr. Morton has over 16 years of experience working in various capacities in the energy industry, including acquisition analysis, reserve estimation, reservoir engineering and operations engineering. Mr. Morton is a Registered Professional Engineer in the State of Texas (License No. 107582). Mr. Morton consults regularly with Cawley Gillespie during the reserve estimation process to review properties, assumptions and relevant data.

The independent petroleum engineer’s report as to the proved oil and natural gas reserves as of December 31, 2019 was prepared by Cawley Gillespie. Cawley Gillespie, whose firm registration number is F-693, was founded in 1961 and is a leader in the evaluation of oil and gas properties. The technical person at Cawley Gillespie primarily responsible for overseeing the reserve estimates with respect to the Underlying Properties and the Net Profits Interest attributable to the Trust is Mr. Zane Meekins. Mr. Meekins has been a practicing consulting petroleum engineer at Cawley Gillespie since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas (License No. 71055) and has over 32 years of practical experience in petroleum engineering, with over 30 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1987 with a Bachelor of Science degree in Petroleum Engineering. Mr. Meekins meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.

Proved reserves are reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expires, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for estimation. If deterministic methods are used, the term "reasonable certainty" implies a high degree of confidence that the quantities of oil or natural gas actually recovered will equal or exceed the estimate. If probabilistic methods are used, there should at least be a 90% probability that the quantities actually recovered will equal or exceed the estimate.

The technical and economic data used in the estimation of the proved reserves include, but are not limited to, production performance decline curve analyses, well logs, geologic maps, well-test data, production data (including flow rates), well data, historical price and cost information, and property ownership interests. Cawley Gillespie uses this technical data, together with a combination of standard engineering and geoscience methods, including the production performance, volumetric and analogy methods. After estimating the reserves of each proved developed property, it was determined that a reasonable level of certainty exists with respect to the reserves which can be expected from any individual undeveloped well in the field. The consistency of reserves attributable to the proved developed wells, which cover a wide area, further supports proved undeveloped classification.

The proved undeveloped locations in the Underlying Properties are predominantly direct offsets of other producing wells. Data from both Boaz Energy and offset operators with which Boaz Energy has exchanged technical data demonstrate a consistency in these conventional plays over an area significantly larger than the Underlying Properties. In addition, information from other analogous fields in similar geographical locations have also been used to analyze secondary reserves on the underlying properties.

Boaz Energy's internal petroleum engineer works closely with its independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to the independent reserve engineers in their reserve estimating process. Periodically, the Boaz Energy petroleum engineer meets with the independent reserve engineers to review properties and discuss methods and assumptions used by Boaz Energy and the independent reserve engineers to prepare reserve estimates.

Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of economically recoverable oil and natural gas and of future net revenues which are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. Please read "Risk Factors" appearing elsewhere in this annual report on Form 10-K.

Proved oil and natural gas reserves were based on the unweighted arithmetic average of the first day of the month prices for the 12-month period before the reporting date. For the year ended December 31, 2019, benchmark prices used were $55.69 per Bbl for oil and $2.58 per MMBtu for natural gas. The WTI price is used for oil prices and the Henry Hub price is used for natural gas. All prices are then further adjusted for quality, transportation fees and regional price differentials.

The following table summarizes estimated proved reserve quantities and PV-10 attributable to the Trust as of December 31, 2019:


	Trust Net Profits Interest
	Oil		Natural Gas(1)		Total(2)		PV-10(3)(4)
	(MBbls)		(MMcf)		(MBoe)		(in thousands)
Proved Developed		2,286.3		1,927.8		2,607.6	$	65,130.2
Proved Undeveloped		2,266.2		1,118.4		2,452.6		49,422.0
Total Proved		4,552.5		3,046.2		5,060.2	$	114,552.2

———————

(1)

Reserves for natural gas liquids are included as a component of natural gas reserves.

(2)

Boe represents an approximate energy equivalent basis such that one Bbl of crude oil equals approximately six Mcf of natural gas. However, the value of oil and natural gas fluctuate, and the value of reserve volumes of oil and natural gas are often substantially different than the amount implied by the Boe ratio.

(3)

PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved crude oil and natural gas reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash inflows using the twelve-month unweighted arithmetic average of the first-day-of-the-month commodity prices, after adjustment for differentials in location and quality, for each of the preceding twelve months. An estimate of PV-10 is provided because it provides useful information to investors as it is widely used by professional analysts and sophisticated investors when evaluating oil and gas companies. PV-10 is considered relevant and useful for evaluating the relative monetary significance of oil and natural gas reserves. PV-10 is not intended to represent the current market value of the estimated reserves of the Underlying Properties.

(4)

For 2019, $2.58 per MMBtu of natural gas and $55.69 per Bbl of oil were used in determining future net revenue.

Reserve quantities and revenues for the Net Profits Interest were estimated from projections of reserves and revenues attributable to the Underlying Properties. Since the Trust has a defined Net Profits Interest, the Trust does not own a specific percentage of the oil and natural gas reserve quantities. Accordingly, reserves allocated to the Trust pertaining to its 80% Net Profits Interest in the Underlying Properties have effectively been reduced to reflect recovery of the Trust’s 80% portion of applicable production and development costs. Because Trust reserve quantities are determined using an allocation formula, any changes in actual or assumed prices or costs will result in revisions to the estimated reserve quantities allocated to the Net Profits Interest.

Estimates of proved reserves were prepared in accordance with guidelines prescribed by the SEC and the Financial Accounting Standards Board, which require that reserve estimates be prepared under existing economic and operating conditions based upon an average of the NYMEX first-day-of-the-month commodity price during the 12-month period ending on the balance sheet date with no provision for price and cost escalations except by contractual arrangements.

Information concerning changes in net proved reserves attributable to the Trust, and the calculation of the standardized measure of the related discounted future net revenues is contained in the notes to the financial statements of the Trust included in this Form 10-K. Boaz Energy has not filed reserve estimates covering the Underlying Properties with any other federal authority or agency.

Proved Undeveloped Reserves (PUDs)

The following table summarizes the changes in estimated proved undeveloped reserves of the Trust for the year ended December 31, 2019:


	Oil (MBbls)(1)			*Natural Gas (MMcf)(1)*			Total (MBoe)
Proved Undeveloped Reserves:
Balance, December 31, 2018		2,555.6			1,764.3			2,849.6
Conversions into proved developed reserves		0			0			0
Revisions of previous estimates		(686.2	)		(645.9	)		(793.9	)
Extensions and discoveries		396.9			0			396.9
Acquisition of reserves		0			0			0
Balance, December 31, 2019		2,266.2			1,118.4			2,452.6

———————

(1)

Reserves for natural gas liquids are included as a component of natural gas reserves.

Changes in proved undeveloped reserves during the year ended December 31, 2019 were primarily due to extensions including 397 MBoe of proved undeveloped reserves in the Kingdom Clearfork Field as a result of 2019 drilling activity. Revisions in the proved undeveloped reserves were because of pricing and added capital expenditures to several waterfloods in the Permian Clearfork. Boaz Energy has estimated that an additional $3,000,000 of capital for waterflood conformance work is required to capture these reserves and maintain an efficient and uniform waterflood. This capital will be used to clean out and stimulate producers and injectors in the field used for extracting oil, natural gas and water and injecting water in secondary recovery methods, respectively.

Developed and Undeveloped Acreage

The following table sets forth information as of December 31, 2019 relating to the leasehold acreage associated with the Underlying Properties. Developed acreage consists of acreage spaced or assigned to productive wells and does not include undrilled acreage held by production under the terms of the lease. Undeveloped acreage is defined as acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.


	Developed Acreage				Undeveloped Acreage				Total Acreage
	Gross(1)		Net(2)		Gross(1)		Net(2)		Gross(1)		Net(2)
Permian Clearfork		1,952		1,825		649		609		2,601		2,434
Permian Abo		1,767		1,437		480		230		2,247		1,667
Permian Shelf		10,494		7,198		8,430		7,529		18,924		14,727
Permian Platform		4,880		1,598		6,738		2,571		11,618		4,169
Total		19,093		12,058		16,297		10,939		35,390		22,997

———————

(1)

A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.

(2)

A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Producing Wells Count

The table below summarizes the producing wells on the Underlying Properties as of December 31, 2019. Although many of these wells produce both oil and natural gas, a well is categorized as an oil well or a natural gas well based upon the ratio of oil to natural gas production. All wells in the table below are oil wells except for 4 gross (2.6 net) natural gas wells.


	Wells(1)
	Gross Wells(2)		Net Wells(3)
Permian Clearfork		63.0		58.9
Permian Abo		54.0		46.0
Permian Shelf		204.0		172.0
Permian Platform		164.0		49.4
Total		485.0		326.3

———————

(1)

Boaz Energy's total gross wells associated with the Underlying Properties include 323 operated wells 162 non-operated wells.

(2)

A gross well is a well in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned.

(3)

A net well is deemed to exist when the sum of the fractional ownership working interests in gross wells equals one. The number of net wells is the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof.

Drilling Results

The following is a summary of the number of development and exploratory wells drilled and completed on the Underlying Properties during the years indicated. The table below does not include wells drilled by third parties on the Memorial Underlying Properties or the Crane County Underlying Properties (each described below) prior to the acquisition of those properties by Boaz Energy in 2017.


	Year Ended December 31,
	2019				2018				2017
	Gross		Net		Gross		Net		Gross		Net
Development Wells:
Productive		31.0		3.3		24.0		2.1		40.0		23.2
Dry holes		0		0		1.0		0.1		0		0
Exploratory Wells:
Productive		0		0		0		0		0		0
Dry holes		0		0		0		0		0		0
Total:
Productive		31.0		3.3		24.0		2.1		40.0		23.2
Dry holes		0		0		1.0		0.1		0		0

During 2019, there were 31 gross (3.3 net) producing wells and 0 injection wells drilled, and 3 producing wells converted into injection wells on the Underlying Properties. During 2018, there were 25 gross (2.2 net) producing wells and 0 injection wells drilled, and 0 producing wells converted into injection wells on the Underlying Properties. During 2017, there were 31 gross (14.4 net) producing wells and 9 injection wells drilled, and 19 producing wells converted into injection wells on the Underlying Properties. As of March 1, 2020, there were no producing wells in the process of being drilled.

On June 14, 2016 and December 14, 2017, Boaz Energy acquired certain oil and gas leasehold acreages located in the State of Texas and various other related rights, permits, contracts, equipment and other assets, known, respectively, as the Memorial Acquisition and the Crane Acquisition. Revenues and direct operating expenses of the assets acquired in the Memorial Acquisition that are subject to the Net Profits Interest are referred to as the "Memorial Underlying Properties". All of the assets acquired in the Crane County Acquisition are subject to the Net Profits Interest and are referred to as the “Crane County Underlying Properties”.

Oil and Natural Gas Production

The following table presents the oil and natural gas sales volumes, average sales prices and average costs per Boe for the Underlying Properties on a historical basis for the years ended December 31, 2019, 2018 and 2017 and on a pro forma basis for the year ended December 31, 2017. The pro forma combined operating data presented below for the year ended December 31, 2017 was prepared to give effect to the acquisition of the Crane County Underlying Properties as if such acquisition had occurred on January 1, 2017. All production derived from the Underlying Properties is from the Permian Basin.


	Year Ended December 31, 2019		Year Ended December 31, 2018		Year Ended December 31, 2017		Pro Forma Year Ended December 31, 2017
Production volumes(1):
Oil (MBbls)		557.5		506.9		553.9		585.3
Natural Gas (MMcf)		605.4		562.8		296.9		571.6
Total (MBoe)		658.4		600.7		603.4		680.6
Average net daily production (Boe/d)		1,803.8		1,645.8		1,653.1		1,864.5
Average realized sales prices:
Oil ($/Bbl)	$	51.06	$	58.91	$	47.57	$	47.61
Natural gas ($/Mcf)	$	2.14	$	4.27	$	3.94	$	3.94
Average price per Boe	$	45.44	$	53.81	$	45.61	$	44.25
Average expenses per Boe:
Lease operating expense	$	8.17	$	7.26	$	9.00	$	8.82
Severance and ad valorem taxes	$	4.01	$	4.70	$	3.61	$	3.42
Total operating expenses per Boe	$	12.18	$	11.96	$	12.61	$	12.24

———————

(1)

Production from the Kingdom Clearfork field during the years ended December 31, 2019, 2018 and 2017 was 142, 191 and 197 MBoe, respectively, consisting of 140, 189 and 194.4, MBbls of oil, respectively, and 8.7, 13.6, and 15.6 MMcf of natural gas, respectively. Production from the Kingdom Abo field during the years ended December 31, 2019, 2018 and 2017 was 98, 109 and 110.9 MBoe, respectively, consisting solely of oil. Such fields are the only fields that contain 15% or more of the total proved reserves attributable to the Underlying Properties as of December 31, 2019, 2018 and 2017.

Production costs for oil and natural gas attributable to the Underlying Properties for the years ended December 31, 2019 and 2018, were as follows:


	Year Ended
	2019		2018
Costs
Severance Tax	$	942,435	$	1,515,691
Ad Valorem Tax		1,694,887		1,309,823
Lease Operating Expense		5,375,666		4,359,750
Development costs		6,842,669		2,781,854
Direct Operating Expense		2,214,828		1,426,474
Other		1,494,139		1,219,250
Total costs	$	18,564,624	$	12,612,842

Abandonment and Sale of Underlying Properties

Boaz Energy or any transferee has the right to abandon its interest in any well or property if Boaz Energy or such transferee, acting as a reasonable and prudent operator, believes a well or property ceases to produce or is not capable of, producing in commercially paying quantities. Upon termination of the lease, the portion of the Net Profits Interest relating to the abandoned property will be extinguished.

Boaz Energy generally may sell all or a portion of its interests in the Underlying Properties, subject to and burdened by the Net Profits Interest, without the consent of the Trust unitholders. In addition, Boaz Energy may, under certain circumstances cause the Trust to release or sell portions of the Net Profits Interest.

Title to Properties

The Underlying Properties are or may be subject to one or more of the burdens and obligations described below. To the extent that these burdens and obligations affect Boaz Energy’s rights to production or the value of production from the Underlying Properties, they have been taken into account in calculating the Trust’s interests and in estimating the size and the value of the reserves attributable to the Underlying Properties.

Boaz Energy’s interests in the oil and natural gas properties comprising the Underlying Properties are typically subject, in one degree or another, to one or more of the following:

royalties and other burdens, express and implied, under oil and natural gas leases and other arrangements;

overriding royalties, production payments and similar interests and other burdens created by Boaz Energy’s predecessors in title;

a variety of contractual obligations arising under operating agreements, farm-out agreements, production sales contracts and other agreements that may affect the Underlying Properties or their title;

liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors and contractual liens under operating agreements that are not yet delinquent or, if delinquent, are being contested in good faith by appropriate proceedings;

pooling, unitization and communitization agreements, declarations and orders;

easements, restrictions, rights-of-way and other matters that commonly affect property;

conventional rights of reassignment that obligate Boaz Energy to reassign all or part of a property to a third party if Boaz Energy intends to release or abandon such property;

preferential rights to purchase or similar agreements and required third-party consents to assignments or similar agreements;

obligations or duties affecting the Underlying Properties to any municipality or public authority with respect to any franchise, grant, license or permit, and all applicable laws, rules, regulations and orders of any governmental authority; and

rights reserved to or vested in the appropriate governmental agency or authority to control or regulate the Underlying Properties and also the interests held therein, including Boaz Energy’s interests and the Net Profits Interest.

Boaz Energy believes that the burdens and obligations affecting the Underlying Properties are conventional in the industry for similar properties. Boaz Energy also believes that the existing burdens and obligations do not, in the aggregate, materially interfere with the use of the Underlying Properties and will not materially adversely affect the Net Profits Interest or its value.

In order to give third parties notice of the Net Profits Interest, Boaz Energy recorded the Conveyance in Texas in the real property records in the Texas counties in which the Underlying Properties are located, or in such other public records of Texas as required under applicable law to place third parties on notice of the Conveyance.

Under Texas law, the Conveyance constitutes the conveyance of a presently vested, non-possessory interest in real property. Therefore, Boaz Energy and the Trust believe that, in a bankruptcy of Boaz Energy, the Net Profits Interest will remain outside of any Boaz Energy bankruptcy estate and will be a continuing obligation of any successor to Boaz Energy as the operator of the Underlying Properties under Texas law and, as such, outside of Boaz Energy’s bankruptcy estate.

Boaz Energy believes that its title to the Underlying Properties is, and the Trust’s title to the Net Profits Interest will be, good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions as are not so material to detract substantially from the use or value of such properties or royalty interests. Under the terms of the Conveyance, Boaz Energy has provided a special warranty of title with respect to the Net Profits Interest, subject to the burdens and obligations described in this section.

Item 3. Legal Proceedings

On October 1, 2018, a lawsuit styled Thaleia L. Marston, Trustee of the Marston Trust v. Blackbeard Operating, LLC, et.al, No. 18-10-24761 – CVW in the 143rd District Court in Ward County, Texas (the “2018 Litigation”) was filed, naming, among others, Boaz Energy and the Trust as defendants. The plaintiff is a lessor under two leases operated by Blackbeard Operating LLC. The Underlying Properties include the interests of Boaz Energy in some of the minerals covered by those leases. The litigation seeks surface use damages and alleges violations of the terms of the leases, among other things. While it is not yet possible to estimate any potential loss or range of loss, Boaz Energy has advised the Trustee that it does not anticipate the litigation will materially affect the Trust. On January 3, 2020, Lawrence M. Marston joined the lawsuit as a plaintiff alleging surface damage claims against Blackbeard and Goodnight Midstream Permian, L.L.C., but not against the Trust. On January 17, 2020, the Trust and the other defendants filed a motion for summary judgment, which would dispose of the claims against the Trust if granted. The parties are working to reschedule depositions for April 2020 with a goal of arguing the motion for summary judgment by May 2020. Pursuant to the current scheduling order, the parties are to mediate the case before April 17, 2020 (which may be extended by agreement). Discovery is set to end on June 14, 2020 and the trial is set for September 14, 2020.

Item 4. Mine Safety Disclosures

Not applicable.

PART II

Item 5. Market for Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities

The Trust units are listed on the New York Stock Exchange (“NYSE”) under the symbol “PRT.” On March 24, 2020, there were 12,165,732 Trust units outstanding held by 18 unitholders of record, including 6,250,000 held by beneficial owners whose shares are held in street name by brokers and nominees.

Distributions

The Trust currently makes, and expects to continue to make, monthly cash distributions of substantially all of its cash receipts, after deducting amounts for the Trust’s administrative expenses and any cash reserves withheld by the Trustee, to holders of its Trust units as of the applicable record date on or before the 10^th business day after the record date.

Equity Compensation Plans

The Trust has no directors, executive officers or employees. Accordingly, the Trust does not maintain any equity compensation plans and there are no Units reserved for issuance under any such plans.

Unregistered Sales of Securities

None.

Purchases of Securities

None.

Item 6. Selected Financial Data

As a “smaller reporting company,” as defined by Rule 12b-2 of the Exchange Act, the Trust has elected scaled disclosure reporting and therefore is not required to provide the information required by this Item.

Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations

Overview

PermRock Royalty Trust, a Delaware statutory trust formed in November 2017 by Boaz Energy, completed its initial public offering in May 2018. The Trust’s only asset and source of income is the Net Profits Interest, which entitles the Trust to receive 80% of the net profits from oil and natural gas production from the Underlying Properties. The Net Profits Interest is passive in nature and neither the Trust nor the Trustee has any management control over or responsibility for costs relating to the operation of the Underlying Properties.

Although the Trust was formed on November 22, 2017, the conveyance of the Net Profits Interest did not occur until May 4, 2018, with an effective date of January 1, 2018, and no proceeds were received by the Trust from Boaz Energy during the three-month period ended March 31, 2018. As a result, the Trust did not recognize any income or make any distributions during the three-month period ended March 31, 2018.

The Trust is required to make monthly cash distributions of substantially all of its monthly cash receipts, after deduction of fees and expenses for the administration of the Trust and any cash reserves, to holders of its Trust units as of the applicable record date on or before the 10th business day after the record date. The Net Profits Interest is entitled to a share of the profits attributable to production. Boaz Energy typically receives payment for oil production 30 to 60 days after it is produced and for natural gas production 60 to 90 days after it is produced. The Trust is not subject to pre-set termination provisions based on a maximum volume of oil or natural gas to be produced or the passage of time. The amount of Trust revenues and cash distributions to Trust unitholders depends on, among other things:

volumes produced;

wellhead prices;

price differentials;

production and development costs;

potential reductions or suspensions of production; and

the amount and timing of Trust administrative expenses.

Oil prices have declined sharply during the first quarter of 2020 in response to the economic effects of the recent announcement of Saudi Arabia’s abandonment of output restraints and the COVID-19 pandemic. Continued low oil and gas prices on production from the Underlying Properties could cause (i) a reduction in the amount of net proceeds to which the Trust is entitled, which could materially reduce or completely eliminate the amount of cash available for distribution to Trust unitholders and (ii) a reduction in the amount of oil and natural gas that are economic to produce from the Underlying Properties. As discussed below, all derivative contracts expired as of December 31, 2019 and the terms of the Conveyance prohibit Boaz Energy from entering into new hedging arrangements. Consequently, the amount of cash contributions to the Trust are subject to even greater fluctuation after December 31, 2019.

2019 Recap and 2020 Outlook

In 2019, Boaz Energy optimized waterflood operations, converted additional wells to injection wells where prudent and continued to participate in Permian Platform drilling proposed by non-operating partners. Boaz Energy completed two new wells operated by Boaz Energy in the Permian Clearfork area in 2019. The first was completed in August 2019 and came on-line in September 2019. The second new well reached total depth and came on-line in December 2019.

In 2020, Boaz Energy plans to implement a new waterflood in the Permian Platform area and optimize revenue on the Underlying Properties.

RESULTS OF OPERATIONS

Distributable Income

Years Ended December 31, 2019 and 2018


	Year Ended December 31,
	2019			2018
Net profits income	$	10,439,020		$	16,229,480
Interest income		10,640			9,305
Total revenue		10,449,660			16,238,785
Expenditures – general and administrative		(1,011,289	)		(648,930	)
Cash reserves		(600,000	)		(0	)
Distributable income	$	8,838,371		$	15,589,855
Distributable income per unit (12,165,732 Trust units)	$	0.726501		$	1.281456

The decrease in net profits income was primarily due to decreased oil and natural gas prices and increased development costs. See “Computation of Income from the Net Profits Interest Received by the Trust” below.

Interest Income. Interest income increased slightly for the year ended December 31, 2019, as compared to the prior year, primarily due to cash reserves beginning in May 2019, and also due to the increased number of days invested in 2019 compared to 2018 when the Trust’s IPO was completed in May 2018 resulting in only seven months for interest income in the year ended December 31, 2018.

General and Administrative Expenditures. General and administrative expenditures increased for the year ended December 31, 2019, as compared to the prior year, primarily because the Trust’s IPO was completed in May 2018 resulting in only seven months of general and administrative expenditures in the year ended December 31, 2018.

Cash Reserves. Pursuant to the Trust Agreement, the Trustee was authorized to begin retaining cash reserves for administrative expenses beginning in May 2019; therefore, no cash reserves were recorded for the year ended December 31, 2018.

Based on 12,165,732 Trust units outstanding at each date listed below, the per unit distributions during the year ended December 31, 2019 were as follows:


Record Date	Payment Date	Distribution per Unit
January 31, 2019	February 14, 2019	$	0.087678
February 28, 2019	March 14, 2019		0.040955
March 29, 2019	April 12, 2019		0.041582
April 30, 2019	May 14, 2019		0.054990
May 31, 2019	June 14, 2019		0.090091
June 28, 2019	July 15, 2019		0.072391
July 31, 2019	August 14, 2019		0.070041
August 30, 2019	September 16, 2019		0.070069
September 30, 2019	October 15, 2019		0.070014
October 31, 2019	November 15, 2019		0.040777
November 29, 2019	December 13, 2019		0.037331
December 31, 2019	January 15, 2020		0.050582
		$	0.726501

Computation of Income from the Net Profits Interest Received by the Trust

The table below outlines the computation of income from the Net Profits Interest received by the Trust for the years ended December 31, 2019 and 2018:


	Year Ended December 31,
	2019			2018
Underlying Properties sales volumes⁽¹⁾:
Oil (Bbl)		557,448			506,926
Natural gas (Mcf)⁽²⁾		605,432			562,757
NYMEX price:
Oil (per Bbl)	$	55.69		$	65.56
Natural gas (per MMBtu)		2.58		$	3.10
Average realized sales price:
Oil (per Bbl)	$	51.06		$	58.91
Natural gas (per Mcf)		2.14			4.27

Calculation of net profits:
Gross profits:
Oil sales	$	28,467,654		$	29,935,072
Natural gas sales		1,298,094			2,391,358
Other revenue		151,013			132,233
Divestitures (Qualified De Minimis Sale)		0			234,341
Total gross profits		29,916,761			32,693,004
Costs:
Direct operating expenses:		2,214,828			1,426,474
Lease operating expenses		5,375,666			4,359,750
Severance and ad valorem taxes⁽³⁾		2,637,322			2,825,514
Development expenses		6,842,669			2,781,854
Other expenses		1,494,139			1,219,250
Total costs		(18,564,624	)		(12,612,842	)
Settlement of derivative contracts⁽⁴⁾		688,562			206,688
Net profits		12,040,699			20,286,850
Percentage allocable to Net Profits Interest		80	%		80	%
Net profits income (before capital reserve)		9,632,560			16,229,480
Capital Reserve⁽⁵⁾		0			0
Operator advance⁽⁶⁾		822,000			0
Net profits interest audit fee		(15,540	)		0
Net profits income received by the Trust	$	10,439,020		$	16,229,480

———————

(1)

Annual sales volumes for 2019 reflect production volumes for November 2018 through October 2019. Because the Trust’s first distribution in May 2018 reflected production from January and February of 2018, annual sales volumes for 2018 reflect production volumes for January 2018 through October 2018.

(2)

Sales volumes for natural gas include NGLs.

(3)

In calculating the previously reported monthly distribution for May 2019, Boaz Energy included a one-time severance tax refund of $0.29 million on its Terry County Clearfork waterflood. Boaz Energy has advised that the Texas Comptroller of Public Accounts denied the claim for that severance tax refund, and that Plains Pipeline, the purchaser of the production subject to that severance tax, offset the amount of the refunded severance tax against the payments otherwise due to Boaz Energy for the purchase of oil and gas during the month of June 2019. Boaz Energy nevertheless processed cash flows for the month of June as though Plains Pipeline had made payment in full for June 2019 and calculated the Net Profits Interest accordingly, such that Boaz Energy bore the cost of that severance tax pending the outcome of an administrative hearing on the controversy. On February 10, 2020 the claim for the severance tax refund was approved. The reduction in severance tax attributable to the Terry County Clearfork waterflood will continue to be applicable.

(4)

Reflects gross cash proceeds from settlement of derivative contracts relating to production as discussed in Note 7 to consolidated financial statements and elsewhere in this Annual Report.

(5)

Boaz Energy is entitled under the Conveyance to reserve up to $3 million from the net profits for certain taxes and development expenses. Boaz Energy held back $553,000 net to the Trust in 2019. Those accumulated reserves were subsequently expended as development costs in 2019 and therefore, the capital reserve net activity for 2019 is $0.

(6)

Boaz Energy advanced $822,000 net to the Trust to cover capital costs of a new well to be operated by Boaz Energy in Terry County as described in Note 4 to consolidated financial statements.

Years Ended December 31, 2019 and 2018

Important factors used in calculating the Trust’s net profits income include the volumes of oil and gas produced from the Underlying Properties and the realized prices received for the sale of those minerals, including natural gas liquids, as well as direct operating and development expenses.

Sales Volumes

Oil. Oil sales volumes increased for the year ended December 31, 2019 as compared to the prior year. This was primarily due to the two additional production months included in the calculations for the year ended December 31, 2019 as compared to the prior year.

Natural Gas. Natural gas sales volumes increased for the year ended December 31, 2019 as compared to the prior year. This was primarily due to the two additional production months included in the calculations for the year ended December 31, 2019 as compared to the prior year.

Sales Prices

Oil. The average realized oil price per Bbl decreased for the year ended December 31, 2019 as compared to the prior year. The average realized oil price per Bbl for the year ended December 31, 2019 is primarily related to production from November 2018 through October 2019, when the average NYMEX price was $55.96 per Bbl.

Natural Gas. The average realized natural gas price per Mcf decreased for the year ended December 31, 2019 as compared to the prior year. The average realized natural gas price per Mcf for the year ended December 31, 2019 is primarily related to production from November 2018 through October 2019, when the average NYMEX price was $2.81 per Mcf. Boaz Energy reports that its natural gas pricing was affected in the Permian Basin where robust drilling activities have resulted in an oversupply of ethane and other natural gas liquids produced in conjunction with the oil and natural gas produced in those activities, requiring Boaz Energy to incur costs to dispose of those excess natural gas liquids.

Costs

Direct Operating Expenses. Direct operating expenses increased for the year ended December 31, 2019 as compared to the prior year primarily due to the two additional production months included in the calculations for the year ended December 31, 2019 as compared to the prior year, as well as increased marketing costs attendant to the sale of ethane and other natural gas liquids during the second half of 2019.

Lease Operating Expenses. Lease operating expenses increased for the year ended December 31, 2019 as compared to the prior year primarily due to the two additional production months included in the calculations for the year ended December 31, 2019 as compared to the prior year. In addition, Boaz Energy reported that it was more active in conducting workovers during 2019.

Severance and Ad Valorem Taxes. Severance and ad valorem taxes decreased for the year ended December 31, 2019 as compared to the prior year primarily due to the severance tax refund discussed in footnote (3) above.

Development Expenses Related to the Underlying Properties. Development expenses related to the Underlying Properties increased for the year ended December 31, 2019 as compared to the prior year because of an increase in development activity during the year ended December 31, 2019, including two new wells in 2019, injector cleanouts and preparations for planned waterflooding. The increase was also because of the timing of the Conveyance and the Trust’s IPO in May 2018, which caused fewer months to be included in the 2018 calculations.

Other Expenses. Other expenses increased for the year ended December 31, 2019 as compared to the prior year, primarily because of two additional months being used in the calculation for 2019.

Capital Reserve and Operator Advance. Boaz Energy is entitled under the Conveyance to reserve up to $3 million from the net profits for certain taxes and development expenses. Boaz Energy held back $553,000 net to the Trust in 2019. Those accumulated reserves were expended in 2019 for development costs of a new well to be operated by Boaz Energy in Terry County, as well as an additional $822,000 net to the Trust of funds advanced by Boaz Energy in 2019. Boaz Energy reported that the advancement would be recouped in the calculation of the Net Profits Interest in 2020. As of March 20, 2020, Boaz Energy reported that $742,000 had been recouped and that it anticipates the balance of $80,000 net to the Trust will be recouped in development expenses over the next one to two months.

Derivative Contracts

Income from the Net Profits Interest is exposed to fluctuations in energy prices in the normal scope of business. To mitigate the negative effects of a possible decline in oil prices on distributable income to the Trust, Boaz Energy entered into derivative put option contracts with respect to approximately 100% of expected oil production attributable to the Net Profits Interest during 2018 and 76% of such production during 2019. These derivative contracts consisted of put option contracts with strike prices of $60 per barrel in 2018 and $50 per barrel in 2019. Boaz Energy believes that these put option contracts provided downside protection to the Trust in the event spot prices for crude oil declined below the applicable strike price, while still allowing the Trust to benefit from increasing crude oil prices. If prices for crude oil as quoted on NYMEX declined below the applicable strike prices, Boaz Energy could exercise its put option and would receive payment generally equal to the difference between the applicable strike price and the market price for crude oil at the time of exercise, multiplied by the notional quantity of crude oil hedged under the applicable put option contract being exercised. These contracts expired as of December 31, 2019, and after December 31, 2019, Boaz Energy no longer hedges any of the production attributable to the Underlying Properties.

Liquidity and Capital Resources

The Trust’s principal sources of liquidity and capital are cash flow generated from the Net Profits Interest and borrowings, if any, to fund administrative expenses. The Trust’s primary uses of cash are distributions to Trust unitholders, payment of Trust administrative expenses, including, if applicable, any reserves established by the Trustee for future liabilities.

Administrative expenses include the Trustee and Delaware Trustee fees, accounting, engineering, legal, tax advisory and other professional fees, and tax reporting and distribution expenses. The Trust is also responsible for paying other expenses incurred as a result of being a publicly traded entity, including costs associated with annual, quarterly and current reports to the SEC, New York Stock Exchange listing fees, independent auditor fees and registrar and transfer agent fees. If the Trustee determines that cash on hand and cash to be received in respect of the Net Profits Interest are, or will be, insufficient to cover the Trust’s liabilities and expenses, the Trustee may cause the Trust to borrow funds to pay liabilities of the Trust. Pursuant to the Trust Agreement, the Trustee is authorized beginning May 2019 to retain cash from the distributions it receives (i) in an amount not to exceed $1.0 million at any one time to be used by the Trust in the event that its cash on hand (including available cash reserves) is not sufficient to pay ordinary course administrative expenses as they become due and (ii) in such amounts as the Trustee in its discretion deems appropriate to pay for future liabilities of the Trust. Boaz Energy provided the Trust with a $1.0 million Letter of Credit that could be drawn by the Trust to pay its administrative expenses. The Trustee continues to retain cash from distributions in such amount as the Trustee determines but not less than $25,000 per month or more than $100,000 per month until the reserve described in clause (i) equals or exceeds $1.0 million, at which time, the Trustee is required to release the Letter of Credit. As of December 31, 2019, the Trustee had retained $600,000 in cash reserves, and as of March 19, 2020, the Trustee had retained $900,000 in cash reserves. The Trustee expects to have retained an aggregate of $1.0 million before the end of April 2020. As of March 19, 2020, the Letter of Credit, which will expire on May 2, 2020, has been decreased by the amount of the $900,000 cash reserves, and the current available amount of the Letter of Credit now totals $100,000.

If the Trustee causes the Trust to borrow funds, or if the Trustee draws on the Letter of Credit being provided by Boaz Energy, the Trust unitholders will not receive distributions until the borrowed funds or the amount drawn, as applicable, are repaid.

Boaz Energy Capital Expenditure Budget

Boaz Energy’s estimated 2020 capital budget for the Underlying Properties is $2 million, of which approximately $800,000 has been expended as of March 30, 2020. Based on current oil and gas prices, there are no significant capital projects planned for the remainder of 2020. The majority of what has been spent so far in 2020 is attributable to properties not operated by Boaz Energy. Boaz Energy anticipates some capital expenditure on waterflood projects and workovers in Crane County which is included in the $2 million estimate. The estimate is subject to change based on, among other things, changes in the price of oil and natural gas, including the impact of the COVID-19 outbreak on such prices, Boaz Energy’s actual capital requirements, the pace of regulatory approvals and the mix of projects.

Boaz Energy’s capital expenditure by the end of 2019 was updated to $7.0 million.

Off-Balance Sheet Arrangements

As of December 31, 2019, the Trust had no off-balance sheet arrangements.

New Accounting Pronouncements

As the Trust’s financial statements are prepared on the modified cash basis, most accounting pronouncements are not applicable to the Trust’s financial statements. No new accounting pronouncements have been adopted or issued that would impact the financial statements of the Trust.

Critical Accounting Policies and Estimates

The Trust uses the modified cash basis of accounting to report Trust receipts of the Net Profits Interest and payments of expenses incurred. The Net Profits Interest represents the right to receive revenues (oil and natural gas sales), less direct operating expenses (lease operating expenses and severance and ad valorem taxes) and development expenses of the Underlying Properties, multiplied by 80%, plus any payments received in connection with the settlement of certain derivative contracts. Cash distributions of the Trust are made based on the amount of cash received by the Trust pursuant to terms of the Conveyance creating the Net Profits Interest.

The financial statements of the Trust, as prepared on a modified cash basis, reflect the Trust’s assets, liabilities, Trust corpus, earnings and distributions as follows:

Income from the Net Profits Interest is recorded when distributions are received by the Trust;

Distributions to Trust unitholders are recorded when declared by the Trust;

Trust general and administrative expenses (which includes the Trustee’s fees as well as accounting, engineering, legal, tax advisory and other professional fees) are recorded when paid;

Cash reserves for Trust expenses may be established by the Trustee for certain expenditures that would not be recorded as contingent liabilities under accounting principles generally accepted in the United States of America (“GAAP”);

Amortization of the investment in the Net Profits Interest is calculated on a unit-of-production basis and is charged directly to Trust corpus, and such amortization does not affect distributions from the Trust; and

The Trust’s investment in the Net Profits Interest is periodically assessed to determine whether its aggregate value has been impaired below its total capitalized cost basis and, if an impairment loss is indicated by the carrying amount of the assets exceeding the sum of the undiscounted expected future net cash flows, then an impairment loss is recognized for the amount by which the carrying amount of the asset exceeds its estimated fair value.

The financial statements of the Trust are prepared on a modified cash basis of accounting, which is considered to be the most meaningful basis of preparation for a royalty trust because monthly distributions to the Trust unitholders are based on net cash receipts. Although this basis of accounting is permitted for royalty trusts by the SEC, the financial statements of the Trust differ from financial statements prepared in accordance with GAAP because net profits income is not accrued in the month of production, expenses are not recognized when incurred and cash reserves may be established for certain contingencies that would not be recorded in GAAP financial statements. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the SEC as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.

The preparation of financial statements requires the Trust to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Oil and Natural Gas Reserves. The proved oil and natural gas reserves for the Underlying Properties are estimated by independent petroleum engineers. Reserve engineering is a subjective process that is dependent upon the quality of available data and the interpretation thereof. Estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices, may justify revision of such estimates. Because proved reserves are required to be estimated using prices at the date of the evaluation, estimated reserve quantities can be significantly impacted by changes in product prices. Accordingly, oil and natural gas quantities ultimately recovered and the timing of production may be substantially different from original estimates.

The Financial Accounting Standards Board requires supplemental disclosures for oil and gas producers based on a standardized measure of discounted future net cash flows relating to proved oil and natural gas reserve quantities. Under this disclosure, future cash inflows are computed by applying the average prices during the 12-month period prior to fiscal year-end, determined as an unweighted arithmetic average of the first-day-of-the-month benchmark price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Future price changes are only considered to the extent provided by contractual arrangements in existence at year-end. The standardized measure of discounted future net cash flows is achieved by using a discount rate of 10% a year to reflect the timing of future cash flows relating to proved oil and natural gas reserves. Changes in any of these assumptions, including consideration of other factors, could have a significant impact on the standardized measure. The standardized measure does not necessarily result in an estimate of the current fair market value of proved reserves.

Amortization of Net Profits Interest. The Trust calculates amortization of the Net Profits Interest in oil and natural gas properties on a unit-of-production basis based on the Underlying Properties’ production and reserves. The reserves upon which the amortization rate is based are quantity estimates which are subject to numerous uncertainties inherent in the estimation of proved reserves. The volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. These estimates are expected to change as additional information becomes available in the future. Downward revisions in proved reserves may result in an increased rate of amortization. Amortization is recorded on sales volumes paid by the Trust during the relevant period and is charged directly to the Trust corpus balance. As a result, amortization does not affect the cash earnings of the Trust.

Impairment of Net Profits Interest. The Net Profits Interest in oil and natural gas properties is periodically assessed for impairment whenever events or circumstances indicate that the current fair value based on expected future cash flows of the Underlying Properties may be less than the carrying value of the Net Profits Interest. During the year ended December 31, 2019, the Trust did not recognize any impairment of the Net Profits Interest. Future downward revisions in actual production volumes relative to current forecasts, higher than expected operating costs, or lower than anticipated market pricing could result in recognition of impairment in future periods.

Refer to Note 2 to the financial statements included in Item 8 of this report for the Trust’s significant accounting policies.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

Item 8. Financial and Supplementary Data

Financial Statements. The following documents are filed as part of the Trust’s financial statements for the year ended December 31, 2019:


	Report of Independent Registered Public Accounting Firm	38
	Statements of Assets, Liabilities and Trust Corpus	39
	Statements of Distributable Income	40
	Statements of Changes in Trust Corpus	41
	Notes to Consolidated Financial Statements	42

[PERMROCK_10K001.JPG]

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Unitholders of PermRock Royalty Trust and
Simmons Bank, Trustee

OPINION ON THE FINANCIAL STATEMENTS

We have audited the accompanying statements of assets, liabilities, and trust corpus of PermRock Royalty Trust (the Trust) as of December 31, 2019 and 2018, and the related statements of distributable income and changes in trust corpus for the years then ended, and the related notes (collectively referred to as the financial statements). In our opinion, the financial statements present fairly, in all material respects, the assets, liabilities, and trust corpus of the Trust as of December 31, 2019 and 2018, and the distributable income and changes in trust corpus for the year then ended, in conformity with the modified cash basis of accounting, as described in Note 2 to the financial statements.

BASIS FOR OPINION

These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on these financial statements based on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Trust in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Trust is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

BASIS OF ACCOUNTING

As described in Note 2 to the financial statements, these financial statements were prepared on the modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.

[PERMROCK_10K003.GIF]

WEAVER AND TIDWELL, L.L.P.

We have served as the Trust’s auditor since 2018.

Austin, Texas
March 30, 2020

Weaver and Tidwell, L.L.P.
1601 South MoPac Expressway, Suite D250 | Austin, Texas 78746

Main: 512.609.1900

CPAS AND ADVISORS | WEAVER.COM

Statement of Assets, Liabilities, and Trust Corpus


	December 31
	2019		2018
ASSETS
Cash and Short-Term Investments	$	1,215,386	$	1,394,128
Receivable		0		10
Net Profits Interests		89,043,803		92,186,166
TOTAL	$	90,259,189	$	93,580,304

		December 31
		2019		2018
LIABILITIES & TRUST CORPUS
Distribution Payable to Unitholders	$	615,386	$	1,394,128
Cash Reserves		600,000		0
Trust Corpus – 12,165,732 Trust Units Issued and Outstanding		89,043,803		92,186,176
TOTAL	$	90,259,189	$	93,580,304

These Financial Statements should be read in conjunction with the accompanying
Notes to Financial Statements included herein.

Statements of Distributable Income


	Year Ended December 31, 2019			Year Ended December 31, 2018
Net Profits Income	$	10,439,020		$	16,229,480
Interest Income		10,640			9,305
Total Revenue		10,449,660			16,238,785
Expenditures – General and Administrative		(1,011,289	)		(648,930	)
Cash Reserves		(600,000	)		0
Distributable Income	$	8,838,371			15,589,855
Distributable Income per Unit – 12,165,732 Trust Units Issued and Outstanding	$	0.726501		$	1.281456

These Financial Statements should be read in conjunction with the accompanying
Notes to Financial Statements included herein.

Statements of Changes in Trust Corpus


	Year Ended December 31, 2019			Year Ended December 31, 2018
Trust Corpus, Beginning of Period	$	92,186,176		$	10
Conveyance of Net Profits Interest		0			95,809,136
Amortization of Net Profits Interest		(3,142,373	)		(3,622,970	)
Distributable Income		8,838,371			15,589,855
Distributions Declared		(8,838,371	)		(15,589,855	)
Trust Corpus, End of Period	$	89,043,803		$	92,186,176

These Financial Statements should be read in conjunction with the accompanying
Notes to Financial Statements included herein.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Organization of Trust

The Trust was created to acquire and hold the Net Profits Interest for the benefit of the Trust unitholders. In connection with the closing of the initial public offering of Trust units, on May 4, 2018, Boaz Energy conveyed the Net Profits Interest to the Trust in exchange for Trust units pursuant to a conveyance agreement between Boaz Energy, the Trustee and the Delaware Trustee (the “Conveyance”). The Net Profits Interest represents an interest in the Underlying Properties.

The Net Profits Interest entitles the Trust to receive 80% of the net profits from the sale of oil and natural gas production from the Underlying Properties. The Net Profits Interest is passive in nature and neither the Trust nor the Trustee has any control over, or responsibility for, costs relating to the operation of the Underlying Properties. The Trust has and will continue to make monthly cash distributions of all of its monthly cash receipts, after deduction of fees and expenses for the administration of the Trust and any cash reserves, to holders of its Trust units as of the applicable record date on or before the 10th business day after the record date. Distributions generally relate to sales from a one-month period.

The Trustee may deposit funds awaiting distribution in an account with an FDIC-insured or national bank, including the Trustee, 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.

In May 2018, Boaz Energy completed an initial public offering of 6,250,000 of the total of 12,165,732 Trust units outstanding, retaining ownership of the remaining 5,915,732 Trust units.

Trust Significant Accounting Policies

Basis of Accounting

The Trust uses the modified cash basis of accounting to report Trust receipts of the Net Profits Interest and payments of expenses incurred. The Net Profits Interest represents the right to receive revenues (primarily oil and natural gas sales), less direct operating expenses, lease operating expenses, severance and ad valorem taxes and development expenses of the Underlying Properties, multiplied by 80%, less any payments made or plus any payments received in connection with the settlement of certain hedge contracts. Cash distributions of the Trust are made based on the amount of cash received by the Trust pursuant to terms of the Conveyance creating the Net Profits Interest.

The financial statements of the Trust, as prepared on a modified cash basis, reflect the Trust’s assets, liabilities, Trust corpus, earnings and distributions as follows:

Income from the Net Profits Interest is recorded when distributions are received by the Trust;

Distributions to Trust unitholders are recorded when declared by the Trust;

Trust general and administrative expenses (which includes the Trustee’s fees as well as accounting, printing, engineering, legal, tax advisory and other professional fees) are recorded when paid; cash reserves for Trust expenses may be established by the Trustee for certain expenditures that would not be recorded as contingent liabilities under United States generally accepted accounting principles (“GAAP”);

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Financial Statements.

Use of Estimates.

Risks and Uncertainties.

The Trust’s revenue and distributions are substantially dependent upon the prevailing and future prices for oil and natural gas, each of which depends on numerous factors beyond the Trust’s control such as economic conditions, the global political environment, regulatory developments and competition from other energy sources. Oil and natural gas prices historically have been volatile and may be subject to significant fluctuations in the future.

Contingencies.

Contingencies related to the Underlying Properties that are unfavorably resolved would generally be expected to result in reductions to cash receipts to the Trust in respect of the Net Profits Interest with corresponding reductions to cash distributions to Trust unitholders. Please see the discussion of litigation in Note 11.

Income Taxes

Tax counsel advised the Trust at the time of formation that for U.S. federal income tax purposes, the Trust is treated as a grantor trust and is be subject to federal income tax at the trust level. Trust unitholders are treated for such purposes as owning a direct interest in the assets of the Trust, and each Trust unitholder is taxed directly on its pro rata share of the income and any gain, if sold, attributable to the assets of the Trust and is entitled to claim its pro rata share of deductions and expenses attributable to the assets of the Trust. Each Trust unitholder should consult his or her own tax advisor regarding income tax requirements, if any, applicable to such unitholder’s ownership of Trust units.

Cash Reserves

Pursuant to the Trust Agreement, beginning in May 2019, the Trustee was authorized to begin retaining cash from the distributions the Trust receives (i) in an amount not to exceed $1.0 million at any one time to be used by the Trust in the event that its cash on hand (including available cash reserves) is not sufficient to pay ordinary course administrative expenses as they become due and (ii) in such amounts as the Trustee in its discretion deems appropriate to pay for future liabilities of the Trust. Boaz Energy provided the Trust with a $1.0 million letter of credit (the “Letter of Credit”) that could be drawn by the Trust to pay administrative expenses of the Trust. The Trustee continues to retain cash from distributions in such amount as the Trustee determines but not less than $25,000 per month or more than $100,000 per month until the reserve described in clause (i) equals or exceeds $1.0 million, at which time, the Trustee is required to release the Letter of Credit. Cash reserves held by the Trustee for administrative expenses totaled $600,000 as of December 31, 2019 and $900,000 as of March 19, 2020. The Trustee expects to have retained an aggregate of $1.0 million before the end of April 2020. As of March 19, 2020, the Letter of Credit, which will expire on May 2, 2020, has been decreased by the amount of the $900,000 cash reserves, and the current available amount of the Letter of Credit now totals $100,000.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Boaz Energy is entitled under the Conveyance to reserve up to $3 million from the net profits for certain taxes and development expenses. Boaz Energy held back $553,000 net to the Trust in 2019. Those accumulated reserves were expended in 2019 for development costs of a new well to be operated by Boaz Energy in Terry County, as well as an additional $822,000 net to the Trust of funds advanced by Boaz Energy in 2019. Boaz Energy reported that the $822,000 advancement would be recouped in the calculation of the Net Profits Interest in 2020. As of March 20, 2020, Boaz Energy reported that $742,000 has been recouped and the balance of $80,000 net to the Trust will be recouped in development expenses over the next one to two months.

Distributions to Unitholders

The Trust makes monthly cash distributions of all of its monthly cash receipts, after deduction of fees and expenses for the administration of the Trust and any cash reserves, to holders of its Trust units as of the applicable record date on or before the 10th business day after the record date.

Based on 12,165,732 Trust units outstanding at each date listed below, the monthly per unit distributions during the year ended December 31, 2019 were as follows:


Record Date	Payment Date	Distribution per Unit
January 31, 2019	February 14, 2019	$	0.087678
February 28, 2019	March 14, 2019		0.040955
March 29, 2019	April 12, 2019		0.041582
April 30, 2019	May 14, 2019		0.054990
May 31, 2019	June 14, 2019		0.090091
June 28, 2019	July 15, 2019		0.072391
July 31, 2019	August 14, 2019		0.070041
August 30, 2019	September 16, 2019		0.070069
September 30, 2019	October 15, 2019		0.070014
October 31, 2019	November 15, 2019		0.040777
November 29, 2019	December 13, 2019		0.037331
December 31, 2019	January 15, 2020		0.050582
		$	0.726501

Related Party Transactions

Trustee Administrative Fee. Under the terms of the Trust Agreement, the Trust pays an annual administrative fee to the Trustee and Delaware Trustee. The Delaware Trustee’s annual fee is $4,000. In 2019, the Trustee received $183,600 for the period from January through December 2019. For 2020, the Trustee’s annual administrative fee will be $189,072. The Trustee’s annual administrative fee will increase at a rate of 3% per year for the first three years of the Trust’s existence, increase at a rate of 2% per year for the following two years, then increase at a rate of 1% per year until the 20th anniversary of the Trust’s formation and then remain flat thereafter. These costs of the Trust, which are included in administration expenses, are deducted by the Trust before distributions are made to Trust unitholders.

Agreements with Boaz Energy. On May 4, 2018, the Trust entered into a registration rights agreement for the benefit of Boaz Energy and certain of its affiliates and transferees, pursuant to which the Trust agreed to register the offering of the Trust units held by Boaz Energy and certain of its affiliates and permitted transferees upon request by Boaz Energy. As of March 30, 2020, Boaz Energy owned 5,878,332 Trust units of the 12,165,732 Trust units issued and outstanding.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Derivative Contracts

Boaz Energy previously entered into derivative contracts with respect to approximately 100% of expected oil production attributable to the Net Profits Interest during 2018 and 76% of such production during 2019, which were intended to mitigate the negative effects of a decline in oil prices on distributable income to the Trust. These derivative contracts consisted of put option contracts with strike prices of $60 per barrel in 2018 and $50 per barrel in 2019. These contracts have expired and after December 31, 2019, Boaz Energy no longer hedges any of the production attributable to the Underlying Properties.

Certain Contracts

The Trust is not a party to any purchase, gathering, or processing contracts. Boaz Energy and other outside operators are parties to oil and natural gas sales contracts. For the year ended December 31, 2019, Boaz Energy reports that Phillips 66, Plains All American Pipeline, Energy Transfer Partners. and Blackbeard Operating LLC accounted for 29.57%, 26.37%, 13.85% and 10.81%, respectively, of total oil and natural gas revenues, and that no other purchaser accounted for 10% or more of the total revenue of the Underlying Properties. Boaz Energy does not believe that the loss of any of these parties as a purchaser of crude oil or natural gas production from the Underlying Properties would have a material impact on the business or operations of Boaz Energy or the Underlying Properties because of the large number of marketing firms and competitive nature of oil and gas purchasers in the Permian Basin.

Significant Customers

Information as to significant purchasers of oil and gas production attributable to the Trust’s economic interests is included in Note 8, above.

10.

Development Costs

Boaz Energy’s original 2019 capital expenditure estimate was $4.0 million. That budget was revised in the second quarter of 2019 to $5.0 million, and again in the third quarter of 2019 to $7.0 million. The increased capital expenditures were due to increased drilling activity in Terry County, implementation of new waterflood patterns in the Kingdom Clearfork and Permian Platform areas, and the completion of two new wells operated by Boaz Energy in the Permian Clearfork.

Boaz Energy’s estimated 2020 capital budget for the Underlying Properties is $2 million, of which approximately $800,000 has been expended as of March 30, 2020. The majority of what has been spent so far in 2020 is attributable to properties not operated by Boaz Energy. Based on current oil and gas prices, there are no significant capital projects planned for the remainder of 2020. The majority of what has been spent so far in 2020 is attributable to properties not operated by Boaz Energy. Boaz Energy anticipates some capital expenditure on waterflood projects and workovers in Crane County which is included in the $2 million estimate. The estimate is subject to change based on, among other things, changes in the price of oil and natural gas, including the impact of the COVID-19 outbreak on such prices, Boaz Energy’s actual capital requirements, the pace of regulatory approvals and the mix of projects.

11.

Settlements and Litigation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In calculating the previously reported monthly distribution for May 2019, Boaz Energy included a one-time severance tax refund of $0.29 million on its Terry County Clearfork waterflood. Boaz Energy has advised the Trustee that the Texas Comptroller of Public Accounts denied the claim for that severance tax refund, and that Plains Pipeline, the purchaser of the production subject to that severance tax, has offset the amount of the refunded severance tax against the payments otherwise due to Boaz Energy for the purchase of oil and gas during the month of June 2019. Boaz Energy nevertheless processed cash flows for the month of June as though Plains Pipeline had made payment in full for June 2019 and calculated the Net Profits Interest accordingly, such that Boaz Energy bore the cost of that severance tax pending the outcome of an administrative hearing on the controversy. On February 10, 2020 the claim for the severance tax refund was approved so the reduction in severance tax attributable to the Terry County Clearfork waterflood will continue to be applicable.

12.

Supplemental Oil and Gas Reserve Information (Unaudited)

Proved Oil and Natural Gas Reserves

Proved oil and gas reserves have been estimated by independent petroleum engineers. Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods, and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods in which the cost of the required equipment is relatively minor compared with the cost of a new well. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling and production history and from changes in economic factors.

The following table presents a reconciliation of proved reserve quantities attributable to the Trust as of the dates indicated below:


	Oil (MBbls)			Natural Gas (MMcf)			Total (MBoe)
Balance, Proved Reserves as of December 31, 2017		6,583			4,787			7,381
Revisions of previous estimates		(785	)		(671	)		(897	)
Extensions, discoveries and other additions		122			155			148
Production		(268	)		(281	)		(315	)
Balance, Proved Reserves as of December 31, 2018		5,652			3,990			6,318
Revisions of previous estimates		(1,421	)		(878	)		(1,568	)
Extensions, discoveries and other additions		509			133			531
Production		(188	)		(199	)		(221	)
Balance, Proved Reserves as of December 31, 2019		4,552			3,046			5,060
Proved developed reserves:
December 31, 2017		4,953			3,263			5,497
December 31, 2018		3,097			2,226			3,467
December 31, 2019		2,286			1,928			2,607
Proved undeveloped reserves:
December 31, 2017		1,630			1,524			1,884
December 31, 2018		2,556			1,764			2,850
December 31, 2019		2,266			1,118			2,452

Extensions and discoveries. During the year ended December 31, 2019, 31 gross wells (3.3 net) were drilled in the Permian Platform area. Extensions and discoveries included 531 MBoe of proved developed and undeveloped reserves that were a result of 2019 drilling activity in the Kingdom Clearfork Field and the Permian Platform area by working interest partners.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

During the year ended December 31, 2018, there were 25 gross (2.2 net) wells drilled. Extensions included approximately 148 MBoe of proved developed and undeveloped reserves that were a result of working interest partners’ drilling wells not classified in the year ending December 31, 2017.

Revisions of previous estimates. During the year ended December 31, 2019, revisions of previous estimates decreased oil reserves by 25%, primarily due to a decrease in the average oil price used to estimate future net reserves. The NYMEX average oil price of $55.69 per Bbl used to determine reserves as of December 31, 2019 was 15% lower than the $65.56 per Bbl used to determine reserves as of December 31, 2018. Revisions in the proved undeveloped reserves were also reduced due to added capital expenditures to several waterfloods in the Permian Clearfork. Boaz Energy has estimated that an additional $3,000,000 of capital for waterflood conformance work is required to capture these reserves and maintain an efficient and uniform waterflood. This capital will be used to clean out and stimulate producers and injectors in the field used for extracting oil, natural gas and water and injecting water in secondary recovery methods, respectively.

During the year ended December 31, 2018, revisions of previous estimates decreased oil reserves by 12%, primarily due to a negative revision of 1,830 MBoe in proved developed reserves in the Permian Basin Clearfork area as a result of waterflood conformance requirements in one of the waterfloods in Terry County, which was partially offset by an increase in the average oil price used to estimate future net reserves. The NYMEX average oil price of $65.56 per Bbl used to determine reserves as of December 31, 2018 was 28% higher than the $51.34 per Bbl average NYMEX oil price as of December 31, 2017.

Production. During the year ended December 31, 2019, production decreased oil reserves by 315 MBoe.

During the year ended December 31, 2018, production decreased oil reserves by 221 MBoe.

Standardized Measure of Discounted Future Net Cash Flows

The following is a summary of a standardized measure of discounted future net cash flows related to the Trust’s Net Profits Interest in total proved natural gas and oil reserve quantities. Information presented is based upon valuation of proved reserves by using discounted cash flows based upon average oil and gas prices during the 12-month period prior to the fiscal year-end, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions and severance and ad valorem taxes, if any, and economic conditions, discounted at the required rate of 10%. As the Trust is not subject to taxation at the Trust level, no provision for income taxes has been made in the following disclosure. Trust prices may differ from posted NYMEX prices due to differences in product quality and property location. The impact of changes in current prices on reserves could vary significantly from year to year. Accordingly, the information presented below should not be viewed as an estimate of the fair market value of the Trust’s oil and natural gas reserves or the costs that would be incurred to acquire equivalent reserves. A market value determination would require the analysis of additional parameters.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves attributable to the Trust was as follows as of the dates indicated (in thousands):


	December 31, 2019			December 31, 2018
Future costs	$	0		$	0
Future net cash flows		232,379			346,569
Discount of future net cash flows at 10%		(117,827	)		(180,774	)
Standardized measure of discounted future net cash flows	$	114,552		$	165,795

Estimates of proved oil and natural gas reserves are by their nature imprecise. Estimates of future net revenue attributable to proved reserves are sensitive to the unpredictable prices of oil and natural gas and other variables. Accordingly, under the allocation method used to derive the Trust’s quantity of proved reserves, changes in prices will result in changes in quantities of proved oil and natural gas reserves and estimated future net revenues.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves attributable to the Trust for the periods indicated (in thousands):


	Total
	2019			2018
Balance at the beginning of the period⁽¹⁾	$	165,795		$	161,301	⁽²⁾
Net change in prices and production costs		(22,498	)		32,164
Net change in future development costs		0			0
Sales of oil and natural gas, net of production costs		(10,400	)		(16,612
Extensions and discoveries		14,681			4,234
Purchase of reserves		0			0
Divestiture of reserves		0			(6
Revisions of previous quantity estimates		(39,734	)		(19,901
Previously estimated development costs incurred		0			0
Net change in income taxes		0			0
Accretion of discount		16,579			16,130
Changes in timing and other		(9,871	)		(11,515	)
Balance at the end of the period (December 31)	$	114,552		$	165,795

———————

(1)

Balance is as of December 31 of the previous year.

(2)

The Conveyance was effective as of January 1, 2018; however, the balance is presented as of December 31, 2017.

For 2019, $2.58 per MMBtu of natural gas and $55.69 per Bbl of oil were used in determining future net revenue. These prices were based on a 12-month unweighted average of the first-day-of-the-month pricing of Henry Hub natural gas and WTI oil.

For 2018, $3.10 per MMBtu of natural gas and $65.56 per Bbl of oil were used in determining future net revenue. These prices were based on a 12-month unweighted average of the first-day-of-the-month pricing of Henry Hub natural gas and WTI oil.

For 2017, $2.98 per MMBtu of natural gas and $51.34 per Bbl of oil were used in determining future net revenue. These prices were based on a 12-month unweighted average of the first-day-of-the-month pricing of Henry Hub natural gas and WTI oil.

13.

Quarterly Schedule of Distributable Income (Unaudited)

The following is a summary of the unaudited quarterly schedule of distributable income for the year ended December 31, 2019:


2019	Net Profits Income		Distributable Income		Distributable Income Per Unit
First Quarter	$	2,323,209	$	2,070,802	$	0.170215
Second Quarter		3,140,783		2,645,711		0.217472
Third Quarter		2,950,430		2,556,326		0.210124
Fourth Quarter		2,024,598		1,565,532		0.128690
Total	$	10,439,020	$	8,838,371	$	0.726501

14.

Subsequent Events

On January 21, 2020, the Trust declared a cash distribution of $0.032164 per Trust unit to unitholders of record as of January 31, 2020. The distribution was paid on February 14, 2020.

On February 18, 2020, the Trust declared a cash distribution of $0.051115 per Trust unit to unitholders of record as of February 28, 2020. The distribution was paid on March 13, 2020.

On March 20, 2020, the Trust declared a cash distribution of $0.014951 per Trust unit to unitholders of record as of March 31, 2020. The distribution will be paid on or about April 14, 2019.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On January 3, 2020, Lawrence M. Marston joined the lawsuit as a plaintiff alleging surface damage claims against Blackbeard and Goodnight Midstream Permian, L.L.C., but not against the Trust. On January 17, 2020, the Trust and the other defendants filed a motion for summary judgment, which would dispose of the claims against the Trust if granted. The parties are working to reschedule depositions for April 2020 with a goal of arguing the motion for summary judgment by May 2020. Pursuant to the current scheduling order, the parties are to mediate the case before April 17, 2020 (which may be extended by agreement). Discovery is set to end on June 14, 2020 and the trial is set for September 14, 2020.

On February 10, 2020 the claim for the one-time severance tax refund of $0.29 million on Boaz Energy’s Terry County Clearfork waterflood was approved by the Texas Comptroller of Public Accounts so the reduction in severance tax attributable to the Terry County Clearfork waterflood will continue to be applicable. See Note 11 to Consolidated Financial Statements for additional information.

As of March 20, 2020, Boaz Energy reported that it had recouped $742,000 of the $822,000 net to the Trust it advanced to the Trust in 2019 to cover development costs and the balance of $80,000 net to the Trust will be recouped in development expenses over the next one to two months. See Note 4 of these Notes to Consolidated Financial Statements for additional information on cash reserves.

In each of January, February and March 2020, the Trustee retained $100,000 from the net profits income the Trust receives from Boaz Energy such that the cash reserves described in Note 4 of these Notes to Consolidated Financial Statements totaled $900,000 as of March 19, 2020. The Trustee expects to retain an additional $100,000 from the net profits income in April 2020 for an aggregate cash reserve of $1.0 million.

In March 2020, the failure of an alliance between the Saudi Arabia-led Organization of Petroleum Exporting Countries and Russia to reach an agreement on oil production volumes resulted in what is widely referred to in the media as a “price war.” Also in March 2020, the World Health Organization made the assessment that COVID-19 can be characterized as a pandemic. The price war and the declaration of the pandemic have resulting in a sharp fall in global oil prices.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. The Trustee conducted an evaluation of the effectiveness of the Trust’s disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(a) and 15d-15(a) as of the end of the period covered by this annual report. Based on this evaluation, the Trustee has concluded that the disclosure controls and procedures of the Trust are effective as of December 31, 2019, that the information required to be disclosed by the Trust in its reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and such information is accumulated and communicated, as appropriate to allow timely decisions regarding required disclosure. In its evaluation of disclosure controls and procedures, the Trustee has relied, to the extent considered reasonable, on information provided by Boaz Energy.

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 the Trust Agreement and the Conveyance of Net Profits Interest, the Trustee’s disclosure controls and procedures related to the Trust necessarily rely on (A) information provided by Boaz Energy, 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 (B) conclusions and reports regarding reserves by the Trust’s independent reserve engineers.

Trustee’s Report on Internal Control over Financial Reporting. The information required to be furnished pursuant to this item is set forth below.

The Trustee is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Exchange Act. The Trustee conducted an evaluation of the effectiveness of the Trust’s internal control over financial reporting based on the criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Trustee’s evaluation under the framework in Internal Control-Integrated Framework (2013), the Trustee concluded that the Trust’s internal control over financial reporting was effective as of December 31, 2019.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Changes in Internal Control over Financial Reporting. There were no changes in the Trust’s internal control over financial reporting during the quarter ended December 31, 2019 that have materially affected, or are reasonably likely to materially affect, the Trust’s internal control over financial reporting. The Trustee notes for purposes of clarification that it has no authority over, has not evaluated and makes no statement concerning, the internal control over financial reporting of Boaz Energy.

Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The Trust has no directors or executive officers. The Trustee is a corporate trustee that may only be removed and replaced by the holders of a majority of the Trust units present in person or by proxy at a meeting of such holders where a quorum is present, including Trust units held by Boaz Energy, called by either the Trustee or the holders of not less than 10% of the then outstanding Trust units.

Audit Committee and Nominating Committee

Because the Trust does not have a board of directors, it does not have an audit committee, an audit committee financial expert or a nominating committee.

Code of Ethics

Because the Trust has no employees, it does not have its own code of ethics. Employees of the Trustee, Simmons Bank, must comply with the bank’s standards of conduct, a copy of which will be provided to unitholders without charge, upon request made to Simmons Bank, Trustee, P.O. Box 470727, Fort Worth, Texas 76147, Attention: Lee Ann Anderson.

Item 11. Executive Compensation

The Trust does not have any executive officers, directors or employees. The Trust does not have a board of directors, and it does not have a compensation committee. Pursuant to the Trust Agreement, the Trust pays an annual administrative fee to the Trustee of $180,000 per year subject to escalation, as described in Note 6. Administrative fees paid to the Trustee in 2019 were $183,600. Administrative fees paid to the Trustee in 2018 for May through December 2018 were $120,000.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

(a)

Security Ownership of Certain Beneficial Owners.

The following table sets forth certain information regarding the beneficial ownership of the Trust units as of March 30, 2020 by each person who, to the Trustee’s knowledge, beneficially owns more than 5% of the outstanding Trust units.


Name and Address of Beneficial Owner	Title of Class	Amount and Nature of Beneficial Ownership		Percent of Class
Boaz Energy II, LLC 201 West Wall Street, Suite 421 Midland, Texas 79701	Trust units		5,878,332		48.3	%

Pursuant to Schedule 13D filed with the SEC and dated May 4, 2018, Boaz Energy indicated it was then the sole record and beneficial owner of 5,915,732 Trust units and had sole voting and dispositive power over all the Trust units. By virtue of their respective ownership of 61.213% and 33.777% of the limited liability company interests in Boaz Energy, two Boaz Energy affiliates (NGP X US Holdings, LP and NGP Boaz Energy II Co-Invest, LLC (the “Boaz Energy Affiliates”) and their respective indirect owners, 5221 N. O’Connor Blvd., Suite 1100, Irving, Texas 75039) may be deemed to indirectly beneficially own all or some portion of such Trust units then owned directly by Boaz Energy and may be deemed to share voting and dispositive power over such Trust units. NGP Energy Capital Management, L.L.C. (“NGP ECM”) has been delegated full power and authority to manage the Boaz Energy Affiliates and, accordingly, NGP ECM may be deemed to be the beneficial owner of these Trust units and may also be deemed to share voting and dispositive power over these Trust units.

(b)

Security Ownership of Trustee.

As of March 30, 2020, Simmons Bank has no beneficial ownership of or power to vote any of the outstanding Trust units.

(c)

Changes in Control.

The Trustee knows of no arrangement, including any pledge by any person of securities of the Trust or any of its parents, the operation of which may at a subsequent date result in a change of control of the Trust.

Item 13. Certain Relationships and Related Transactions and Director Independence

Trustee Administrative Fee. In 2018, the Trust paid the Trustee $120,000 in administrative fees for May through December 2018. In 2019, the Trust paid the Trustee $183,600 in administrative fees. Under the terms of the Trust Agreement, the Trust pays an annual administrative fee of $180,000 subject to escalation as described in Note 6 to the Trustee and $4,000 to the Delaware Trustee.

Registration Rights Agreement. The Trust and Boaz Energy are parties to a Registration Rights Agreement whereby Boaz Energy, its affiliates and certain permitted transferees holding registrable Trust units are entitled, upon receipt by the Trustee of written notice from holders of a majority of the then outstanding registrable Trust units, to demand that the Trust effect the registration of the registrable Trust units. The holders of the registrable Trust units are entitled to demand a maximum of five such registrations. In connection with the preparation and filing of any registration statement, Boaz Energy 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. Any underwriting discounts and commissions will be borne by the seller of the Trust units. The foregoing description of the Registration Rights Agreement is qualified in its entirety by the terms of the Registration Rights Agreement, a copy of which is incorporated by reference as an exhibit to this Form 10-K.

Director Independence

The Trust does not have a board of directors. Further, the Trust relies on an exemption from the director independence requirements of the New York Stock Exchange set forth in Rule 10A-3(c)(7) under the Exchange Act, applicable to listed issuers organized as trusts that do not have a board of directors.

Item 14. Principal Accounting Fees and Services

The Trust does not have an audit committee. Any pre-approval and approval of all services performed by the principal auditor or any other professional service firms and related fees are granted by the Trustee.

The following table presents fees for professional audit services rendered by Weaver and Tidwell, L.L.P. for the audit of the Trust’s financial statements for 2019 and 2018 and fees billed for other services rendered by Weaver and Tidwell, L.L.P.


	2019		2018
Audit fees(1)	$	66,800	$	31,300
Audit-related fees		0		0
Tax fees		0		0
All other fees		0		0
Total fees	$	66,800	$	31,300

———————

(1)

Fees for audit services in 2019 and 2018 consisted of the audit of the Trust’s annual financial statements and reviews of the Trust’s quarterly financial statements.

PART IV

Item 15. Exhibits and Financial Statement Schedules

The following documents are filed as a part of this Annual Report on Form 10-K:

(1)

Financial Statements

Included in Part II. Item 8 of this Annual Report on Form 10-K:

Report of Independent Registered Public Accounting Firm

Statements of Assets, Liabilities and Trust Corpus

Statements of Distributable Income

Statements of Changes in Trust Corpus

Notes to Consolidated Financial Statements

(2)

Financial Statement Schedules

Financial statement schedules are omitted because of the absence of conditions under which they are required or because the required information is given in the financial statements or notes thereto.

(3)

Exhibits

The exhibits below are filed or furnished herewith or incorporated herein by reference.


Exhibit No.		Description of Exhibit
3.1*		Certificate of Trust of PermRock Royalty Trust (incorporated by reference to Exhibit 3.3 to the Registration Statement on Form S-1, filed on April 6, 2018 (Registration No. 333-224191)).
3.2*		Trust Agreement of PermRock Royalty Trust (incorporated by reference to Exhibit 3.4 to the Registration Statement on Form S-1, filed on April 6, 2018 (Registration No. 333-224191)).
3.3*		Amended and Restated Trust Agreement of PermRock Royalty Trust, dated May 4, 2018, among Boaz Energy II, LLC, Wilmington Trust, National Association, as Delaware Trustee of PermRock Royalty Trust, and Simmons Bank, as Trustee of PermRock Royalty Trust (incorporated by reference to Exhibit 3.1 to the Trust’s Current Report on Form 8-K, filed on May 8, 2018 (File No. 001-38472)).
4.1		Description of Trust units.
10.1*		Conveyance of Net Profits Interest, dated effective as of January 1, 2018, by and between Boaz Energy II, LLC and Boaz Energy II Royalty, LLC (incorporated by reference to Exhibit 10.1 to the Trust’s Current Report on Form 8-K, filed on May 8, 2018 (File No. 001-38472)).
10.2*		Registration Rights Agreement, dated as of May 4, 2018, by and between Boaz Energy II, LLC and PermRock Royalty Trust (incorporated by reference to Exhibit 10.2 to the Trust’s Current Report on Form 8-K, filed on May 8, 2018 (File No. 001-38472)).
23.1		Consent of Cawley, Gillespie & Associates, Inc.
31.1		Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1		Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.1		Report of Cawley, Gillespie & Associates, Inc.

———————

Asterisk indicates exhibit previously filed with the SEC and incorporated herein by reference.

Item 16. Form 10-K Summary

Not Applicable

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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.


PERMROCK ROYALTY TRUST


By: Simmons Bank, as Trustee


By:	/s/ Lee Ann Anderson
	Lee Ann Anderson
	Senior Vice President
	Date: March 30, 2020

The registrant, PermRock Royalty 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 any such function exists pursuant to the terms of the Trust Agreement under which it serves.

EXHIBIT 4.1

DESCRIPTION OF THE REGISTRANT’S SECURITIES

REGISTERED PURSUANT TO SECTION 12 OF THE

SECURITIES EXCHANGE ACT OF 1934

PermRock Royalty Trust (the “Trust”) has one class of securities registered under Section 12 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”): its units of beneficial interest, which are referred to in this exhibit as “Trust units.” The following description of the Trust’s registered securities is intended as a summary only and therefore is not a complete description of the Trust units. This description is based upon, and is qualified by reference to, the Trust’s Amended and Restated Trust Agreement, dated May 4, 2018 (the “Trust Agreement”), the Conveyance of Net Profits Interest, effective as of January 1, 2018 (the “Conveyance”) and applicable provisions of Delaware law. You should read these documents, each of which is incorporated by reference as an exhibit to the Trust’s Annual Report on Form 10-K filed with the Securities and Exchange Commission of which this Exhibit is a part, for the provisions that are important to you.

Description of Trust Units

Pursuant to the Conveyance, Boaz Energy II, LLC (“Boaz Energy”), conveyed to the Trust an 80% net profits interest (the “Net Profits Interest”) in exchange for 12,165,732 Trust units. Immediately following the Conveyance, Boaz Energy completed an initial public offering of 6,250,000 of its Trust units. Upon completion of the offering, Boaz Energy owned 5,915,732 Trust units of the 12,165,732 Trust units issued and outstanding. Each Trust unit is a unit of beneficial interest in the Trust assets and is entitled to receive cash distributions from the Trust on a pro rata basis. Each Trust unitholder has the same rights regarding each of his Trust units as every other Trust unitholder has regarding his units. The Trust units are in book-entry form only and are not represented by certificates. The Trust had 12,165,732 Trust units outstanding as of December 31, 2019. The Trust units are traded on the New York Stock Exchange under the symbol “PRT”.

Distributions and Income Computations

Each month, Simmons Bank, as Trustee of the Trust (the “Trustee”) determines the amount of funds available for distribution to the Trust unitholders. Available funds are the cash, if any, received by the Trust from Net Profits Interest and other sources (such as interest earned on any amounts reserved by the Trustee) that month, over the Trust’s liabilities for that month. Available funds are reduced by any cash the Trustee decides to hold as a reserve against future liabilities. The holders of Trust units as of the applicable record date are entitled to monthly distributions payable on or before the 10th business day after the record date.

Unless otherwise advised by counsel or the Internal Revenue Service, the Trustee treats the income and expenses of the Trust for each month as belonging to the Trust unitholders of record on the monthly record date. Trust unitholders generally recognize income and expenses for tax purposes in the month the Trust receives or pays those amounts, rather than in the month the Trust distributes the cash to which such income or expenses (as applicable) relate. Minor variances may occur. For example, the Trustee could establish a reserve in one month that would not result in a tax deduction until a later month.

Transfer of Trust Units

Trust unitholders may transfer their Trust units in accordance with the Trust Agreement. The Trustee does not require either the transferor or transferee to pay a service charge for any transfer of a Trust unit. The Trustee may require payment of any tax or other governmental charge imposed for a transfer. The Trustee may treat the owner of any Trust unit as shown by its records as the owner of the Trust unit. The Trustee will not be considered to know about any claim or demand on a Trust unit by any party except the record owner. A person who acquires a Trust unit after any monthly record date will not be entitled to the distribution relating to that monthly record date.

Periodic Reports

The Trustee files all required Trust federal and state income tax and information returns. The Trustee prepares and mails or otherwise makes available to Trust unitholders annual reports that Trust unitholders need to correctly report their share of the income and deductions of the Trust. The Trustee also causes to be prepared and filed reports required to be filed under the Exchange Act and by the rules of any securities exchange or quotation system on which the Trust units are listed or admitted to trading, and also causes the Trust to comply with all of the provisions of Sarbanes-Oxley Act of 2002, including but not limited to, establishing, evaluating and maintaining a system of internal control over financial reporting in compliance with the requirements of Section 404 thereof.

Liability of Trust Unitholders

Under the Delaware Statutory Trust Act, Trust unitholders are entitled to the same limitation of personal liability extended to stockholders of private corporations for profit under the General Corporation Law of the State of Delaware. No assurance can be given, however, that the courts in jurisdictions outside of Delaware will give effect to such limitation.

Voting Rights of Trust Unitholders

The Trustee or Trust unitholders owning at least 10% of the outstanding Trust units may call meetings of Trust unitholders. The Trust is responsible for all costs associated with calling a meeting of Trust unitholders unless (i) such meeting is called by the Trust unitholders, in which case the Trust unitholders will be responsible for all costs associated with calling such meeting of Trust unitholders or (ii) such meeting is called for the purpose of approving the sale or release of the Net Profits Interest at Boaz Energy’s request, in which case the Trust will be responsible for 80% of all costs associated with calling such meeting of Trust unitholders and Boaz Energy will be responsible for 20% of such costs. Meetings must be held in such location as is designated by the Trustee in the notice of such meeting. The Trustee must send notice of the time and place of the meeting and the matters to be acted upon to all of the Trust unitholders at least 20 days and not more than 60 days before the meeting. Trust unitholders representing a majority of Trust units outstanding must be present or represented to have a quorum.

Each Trust unitholder is entitled to one vote for each Trust unit owned. Abstentions and broker non-votes shall not be deemed to be a vote cast.

Unless otherwise required by the Trust Agreement, a matter may be approved or disapproved by the affirmative vote of a majority of the Trust units present in person or by proxy at a meeting where there is a quorum. This is true, even if a majority of the total Trust units did not approve it. The affirmative vote of the holders of at least 75% of the outstanding Trust units is required to:

dissolve the Trust; or

amend the Trust Agreement (except with respect to certain matters that do not adversely affect the rights of Trust unitholders in any material respect).

Boaz Energy may cause the Trustee to (i) sell all or any part of the Trust estate, including all or any portion of the Net Profits Interest or (ii) release any portion of the Net Profits Interest in connection with the sale, free from and unburdened by the Net Profits Interest, by Boaz Energy and/or its affiliates of a divided or undivided portion of their interests in the underlying properties, if approved by Trust unitholders holding at least 75% of the outstanding Trust units, provided that, after December 31, 2022, such a sale or release shall require approval of a majority of the outstanding Trust units if Boaz Energy and its affiliates own less than 25% of the outstanding Trust units. The net proceeds of any such sale or the consideration received in respect of such release, as applicable, shall be distributed to the Trust unitholders in the manner approved by the Trust unitholders at such meeting.

In addition, Boaz Energy may, without the consent of the Trust unitholders, require the Trust to release the Net Profits Interest associated with any interest in the Underlying Properties that accounted for no more than 1.0% of the total production from the Underlying Properties in the prior 12 months, provided that Boaz Energy may not require the release during any 365-day period of portions of the Net Profits Interest having an aggregate fair value to the Trust of greater than $500,000.

Duration of the Trust; Sale of the Net Profits Interest

the Trust, upon the approval of the holders of at least 75% of the outstanding Trust units, sells the Net Profits Interest;

the annual cash proceeds received by the Trust attributable to the Net Profits Interest are less than $2.0 million for each of any two consecutive years;

the holders of at least 75% of the outstanding Trust units vote in favor of dissolution; or

the Trust is judicially dissolved.

Upon dissolution of the Trust, the Trustee will sell all of the Trust’s assets in one or more sales, and, after payment or the making of reasonable provision for payment of all liabilities of the Trust, distribute the net proceeds of the sale to the Trust unitholders.

EXHIBIT 23.1

[PERMROCK_EX23Z1001.JPG]

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We hereby consent to the references to our firm in the form and context in which they are included in this Annual Report on Form 10-K (including any amendments thereto) filed by PermRock Royalty Trust (“Annual Report”), to our estimates of reserves and value of reserves and our report on reserves as of December 31, 2018 and December 31, 2019 of the underlying properties and net profits interest owned by PermRock Royalty Trust and to the inclusion of our report dated March 13, 2020 as an Exhibit to the Annual Report.


	Sincerely,



	Cawley, Gillespie & Associates, Inc.
	Texas Registered Engineering Firm F-693

March 30, 2020

Fort Worth, Texas

EXHIBIT 31.1

Certification Pursuant to Rule 13a-14(a) and Rule 15d-14(a)

of the Securities Exchange Act of 1934, as amended

I, Lee Ann Anderson, certify that:

I have reviewed this Annual Report on Form 10-K of PermRock Royalty Trust (the “registrant”), for which Simmons Bank acts as Trustee;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, distributable income and changes in Trust corpus of the registrant as of, and for, the periods presented in this report;

I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), or for causing such controls and procedures to be established and maintained, for the registrant and have:

designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under my supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to me by others within those entities, particularly during the period in which this report is being prepared;

designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under my supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes;

evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report my conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

I have disclosed, based on my most recent evaluation of internal control over financial reporting, to the registrant’s auditors:

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

In giving the certifications in paragraphs 4 and 5 above, I have relied to the extent I consider reasonable on information provided to me by Boaz Energy II, LLC.



		SIMMONS BANK, TRUSTEE FOR PERMROCK ROYALTY TRUST

Date: March 30, 2020	By:	/s/ Lee Ann Anderson
		Lee Ann Anderson,
		Senior Vice President
		Simmons Bank

EXHIBIT 32.1

Certification Under Section 906

of the Sarbanes-Oxley Act of 2002, 18 U.S.C. § 1350

In connection with the Annual Report of PermRock Royalty Trust (the “Trust”) on Form 10-K for the period ended December 31, 2019, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, not in its individual capacity but solely as the Trustee of the Trust, certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to her knowledge:

(1)

The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2)

The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Trust.



		SIMMONS BANK, TRUSTEE FOR PERMROCK ROYALTY TRUST

Date: March 30, 2020	By:	/s/ Lee Ann Anderson
		Lee Ann Anderson,
		Senior Vice President
		Simmons Bank

A signed original of this written statement required by Section 906 has been provided to PermRock Royalty Trust and will be retained by PermRock Royalty Trust and furnished to the Securities and Exchange Commission or its Staff upon request.

EXHIBIT 99.1

[PERMROCK_EX99Z1001.JPG]

March 13, 2020

Ms. Lee Ann Anderson

PermRock Royalty Trust

Simmons Bank, Trustee

2200 West 7^th Street, Suite 210

Fort Worth, TX 76107

Re:

Evaluation Summary

PermRock Royalty Trust Net Profits Interest

Proved Reserves

Various Counties, Texas

As of December 31, 2019

Dear Ms. Anderson:

As requested, we are submitting our estimates of proved reserves and our forecasts of the resulting economics attributable to the above captioned interests. We completed our evaluation on March 13, 2020. It is our understanding that the proved reserves estimated in this report constitute 100% of all proved reserves owned by PermRock Royalty Trust. This report has been prepared for use in filings with the Securities and Exchange Commission. In our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

Composite reserve estimates and economic forecasts are summarized below:


			Proved
		Proved	Developed	Proved
		Developed	Non-	Un-
		Producing	Producing	Developed	Proved
Net Reserves
Oil	– Mbbl	1,921.8	364.4	2,266.2	4,552.5
Gas	– MMcf	1,252.8	675.0	1,118.4	3,046.2
Revenue
Oil	– M$	96,804.0	18,075.9	113,963.9	228,843.8
Gas	– M$	1,504.5	761.4	1,269.5	3,535.5
Severance and
Ad Valorem Taxes	– M$	0.0	0.0	0.0	0.0
Operating Expenses	– M$	0.0	0.0	0.0	0.0
Investments	– M$	0.0	0.0	0.0	0.0
Net Operating Income (BFIT)	– M$	98,308.6	18,837.4	115,233.3	232,379.3
Discounted @ 10%	– M$	57,113.4	8,016.8	49,422.0	114,552.2

Evaluation Summary

PermRock Royalty Trust Net Profits Interests

As of December 31, 2019

Page 2 of 6

In accordance with the Securities and Exchange Commission guidelines, the operating income (BFIT) has been discounted at an annual rate of 10% to determine its “present worth”. The discounted value shown above should not be construed to represent an estimate of the fair market value by Cawley, Gillespie & Associates, Inc.

The annual average Henry Hub spot market gas price of $2.58 per MMBtu and the annual average WTI Cushing spot oil price of $55.69 per barrel were used in this report. In accordance with the Securities and Exchange Commission guidelines, these prices are determined as an unweighted arithmetic average of the first-day-of-the-month price for 12 months prior to the effective date of the evaluation. The oil and gas prices were held constant and were adjusted to wellhead prices by property based on values supplied by Boaz Energy II, LLC (“Boaz”). Deductions were applied to the net gas volumes for fuel and shrinkage. The adjusted volume-weighted average product prices over the life of the properties are $50.33 per barrel of oil and $1.16 per Mcf of gas.

Operating expenses and capital costs for the underlying properties were supplied by Boaz and reviewed for reasonableness. Severance tax rates were specified by property based on published state rates, with 50% oil severance tax abatements for 10 years on qualified waterflood projects. Ad valorem taxes were forecast as 2.48% to 3.5% of net revenue. As per the Securities and Exchange Commission guidelines, neither expenses nor investments were escalated. The cost of plugging and the salvage value of equipment have not been considered.

All proved reserve classifications conform to criteria of the Securities and Exchange Commission as set forth in Rules 4-10 of Regulation S-X and defined in pages 1 and 2 of the Appendix. The proved developed non-producing reserves include those associated with behind-pipe zones, workovers and proved waterflood projects with current water injection and very minor remaining capital expenditures. The reserves and economics are predicated on the regulatory agency classifications, rules, policies, laws, taxes and royalties in effect on the effective date except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions have not been considered. The reserves were estimated using a combination of the production performance, volumetric and analogy methods, in each case as we considered to be appropriate and necessary to establish the conclusions set forth herein. The methods employed in estimating reserves are described in page 3 of the Appendix. All reserve estimates represent our best judgment based on data available at the time of preparation and assumptions as to future economic and regulatory conditions. It should be realized that the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.

The reserve estimates were based on interpretations of factual data furnished by Boaz and PermRock Royalty Trust. Ownership interests were supplied by and were accepted as furnished. To some extent, information from public records has been used to check and/or supplement these data. The basic engineering and geological data were utilized subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data. An on-site inspection of these properties has not been made nor have the wells been tested by Cawley, Gillespie & Associates, Inc.

Evaluation Summary

PermRock Royalty Trust Net Profits Interests

As of December 31, 2019

Page 3 of 6

Cawley, Gillespie & Associates, Inc. is independent with respect to PermRock Royalty Trust as provided in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers (“SPE Standards”). Neither Cawley, Gillespie & Associates, Inc. nor any of its employees has any interest in the subject properties. Neither the employment to make this study nor the compensation is contingent on the results of our work or the future production rates for the subject properties.

Our work-papers and related data are available for inspection and review by authorized parties.


	Respectfully submitted,

	CAWLEY, GILLESPIE & ASSOCIATES, INC.
	Texas Registered Engineering Firm F-693

APPENDIX

Reserve Definitions and Classifications

The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requires adherence to the following definitions of oil and gas reserves:

"(22)

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations— prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

"(i)

The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

"(ii)

In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

"(iii)

Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

"(iv)

Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

"(v)

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

"(6)

Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

“(i)

Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

“(ii)

Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

"(31)

Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

“(i)

Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

“(ii)

Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

“(iii)

Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

"(18)

Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

“(i)

When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

“(ii)

Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

“(iii)

Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

“(iv)

See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).

"(17)

Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

“(i)

When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

“(ii)

Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

“(iii)

Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

“(iv)

The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

“(v)

Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

“(vi)

Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.”

Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that "a registrant engaged in oil and gas producing activities shall provide the information required by Subpart 1200 of Regulation S–K." This is relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant is permitted, but not required, to disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.”

"(26)

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

“Note to paragraph (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).”

APPENDIX

Methods Employed in the Estimation of Reserves

The four methods customarily employed in the estimation of reserves are (1) Production Performance, (2) Material Balance, (3) Volumetric and (4) Analogy. Most estimates, although based primarily on one method, utilize other methods depending on the nature and extent of the data available and the characteristics of the reservoirs.

Basic information includes production, pressure, geological and laboratory data. However, a large variation exists in the quality, quantity and types of information available on individual properties. Operators are generally required by regulatory authorities to file monthly production reports and may be required to measure and report periodically such data as well pressures, gas-oil ratios, well tests, etc. As a general rule, an operator has complete discretion in obtaining and/or making available geological and engineering data. The resulting lack of uniformity in data renders impossible the application of identical methods to all properties, and may result in significant differences in the accuracy and reliability of estimates.

A brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy follows:

Production Performance. This method employs graphical analyses of production data on the premise that all factors which have controlled the performance to date will continue to control and that historical trends can be extrapolated to predict future performance. The only information required is production history. Capacity production can usually be analyzed from graphs of rates versus time or cumulative production. This procedure is referred to as "decline curve" analysis. Both capacity and restricted production can, in some cases, be analyzed from graphs of producing rate relationships of the various production components. Reserve estimates obtained by this method are generally considered to have a relatively high degree of accuracy with the degree of accuracy increasing as production history accumulates.

Material Balance. This method employs the analysis of the relationship of production and pressure performance on the premise that the reservoir volume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be estimated by analyzing changes in pressure with respect to production relationships. This method requires reliable pressure and temperature data, production data, fluid analyses and knowledge of the nature of the reservoir. The material balance method is applicable to all reservoirs, but the time and expense required for its use is dependent on the nature of the reservoir and its fluids. Reserves for depletion type reservoirs can be estimated from graphs of pressures corrected for compressibility versus cumulative production, requiring only data that are usually available. Estimates for other reservoir types require extensive data and involve complex calculations most suited to computer models which make this method generally applicable only to reservoirs where there is economic justification for its use. Reserve estimates obtained by this method are generally considered to have a degree of accuracy that is directly related to the complexity of the reservoir and the quality and quantity of data available.

Volumetric. This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of hydrocarbons in-place. The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location. The volumetric method is most applicable to reservoirs which are not susceptible to analysis by production performance or material balance methods. These are most commonly newly developed and/or no-pressure depleting reservoirs. The amount of hydrocarbons in-place that can be recovered is not an integral part of the volumetric calculations but is an estimate inferred by other methods and a knowledge of the nature of the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of accuracy; but the degree of accuracy can be relatively high where rock quality and subsurface control is good and the nature of the reservoir is uncomplicated.

Analogy. This method, which employs experience and judgment to estimate reserves, is based on observations of similar situations and includes consideration of theoretical performance. The analogy method is a common approach used for “resource plays,” where an abundance of wells with similar production profiles facilitates the reliable estimation of future reserves with a relatively high degree of accuracy. The analogy method may also be applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods. Reserve estimates obtained in this manner are generally considered to have a relatively low degree of accuracy.

Much of the information used in the estimation of reserves is itself arrived at by the use of estimates. These estimates are subject to continuing change as additional information becomes available. Reserve estimates which presently appear to be correct may be found to contain substantial errors as time passes and new information is obtained about well and reservoir performance.