Exhibit 99.4

EVALUATION SUMMARY

EARTHSTONE ENERGY, INC. INTERESTS

TOTAL PROVED RESERVES CERTAIN PROPERTIES IN TEXAS

AS OF DECEMBER 31, 2021

NYMEX STRIP PRICE CASE

Cawley, Gillespie & Associates, Inc.

EVALUATION SUMMARY

EARTHSTONE ENERGY, INC. INTERESTS

TOTAL PROVED RESERVES CERTAIN PROPERTIES IN TEXAS

AS OF DECEMBER 31, 2021

NYMEX STRIP PRICE CASE

Cawley, Gillespie & Associates, Inc.

March 22, 2022

Geoff Vernon

Vice President of Reservoir Engineering and A&D Earthstone Energy, Inc.

1400 Woodloch Forest Dr., Suite 300 The Woodlands, Texas 77380

Re:    Evaluation Summary – NYMEX Strip Price

Earthstone Energy, Inc. Interests

Total Proved Reserves Certain Properties in Texas

As of December 31, 2021    

Dear Mr. Vernon:

As you have requested, this report was completed on March 22, 2022 for the purpose of submitting our estimates of total proved reserves and forecasts of economics attributable to the Earthstone Energy, Inc. (“Earthstone”) interests. This report includes 100% Earthstone’s proved reserves, which are made up of oil and gas properties in Texas. This report utilized a NYMEX strip price deck quoted on March 15, 2022. The results of this evaluation are presented in the accompanying tabulation, with a composite summary of the values presented below:

			Proved
		Proved	Developed
		Developed	Non-	Proved	Proved	Total
		Producing	Producing	Developed	Undeveloped	Proved
Net Reserves
Oil	- Mbbl	33,376.8	2,518.6	35,895.3	25,250.4	61,145.7
Gas	- MMcf	184,531.8	6,760.2	191,292.0	93,888.1	285,180.1
NGL	- Mbbl	24,924.0	1,047.0	25,971.0	13,115.0	39,085.9
Net Revenue
Oil	- M$	2,365,095.9	187,166.0	2,552,262.1	1,801,030.5	4,353,293.3
Gas	- M$	564,217.3	20,172.4	584,389.5	277,435.4	861,825.0
NGL	- M$	804,479.2	31,594.3	836,073.4	421,546.5	1,257,620.1
Severance Taxes	- M$	211,446.6	12,492.1	223,938.7	135,271.0	359,209.8
Ad Valorem Taxes	- M$	46,495.0	2,989.0	49,484.0	31,214.6	80,698.6
Operating Expenses	- M$	844,472.3	26,087.7	870,560.0	308,638.7	1,179,198.5
Abandonment Costs	- M$	53,213.2	358.7	53,571.8	4,176.4	57,748.3
Future Development Costs	- M$	0.0	14,950.0	14,950.0	455,058.0	470,008.0
Net Operating Income (BFIT)	- M$	2,578,164.7	182,055.2	2,760,220.7	1,565,653.8	4,325,874.2
Discounted @ 10%	- M$	1,476,400.1	108,617.9	1,585,018.1	763,388.1	2,348,406.3

Cawley, Gillespie & Associates, Inc.

Earthstone Energy, Inc. Interests – NYMEX Strip Price Case

March 22, 2022

Page 2

Future revenue is prior to deducting state production taxes and ad valorem taxes. Future net cash flow is after deducting these taxes, future capital (development) costs and operating expenses, but before consideration of federal income taxes. The future net cash flow has been discounted at an annual rate of ten percent to determine its “present worth”. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the reserves.

The oil reserves include oil and condensate. Oil volumes and NGL volumes are expressed in barrels (42 U.S. gallons). Gas volumes are expressed in thousands of standard cubic feet (Mcf) at contract temperature and pressure base.

Hydrocarbon Pricing

As requested by Earthstone, oil and gas prices were adjusted to the following March 15, 2022 NYMEX strip prices:

	WTI Cushing Oil Price	Henry Hub Gas Price
Year	$/BBL	$/MMBTU
2022	88.84	4.784
2023	78.71	3.914
2024	73.91	3.467
2025	70.89	3.461
2026	68.61	3.486
2027	67.77	3.486
Thereafter	Flat	Flat
Cap	67.77	3.486

Oil prices were held constant beginning January 1, 2027 at $67.77 per BBL, and beginning January 1, 2026, gas prices were held constant at $3.486 per MMBTU. Adjustments to oil and gas prices were made based upon data provided by Earthstone and include the use of forward-looking spreads. NGL prices were applied at 45.5% of WTI Cushing oil prices as provided. These adjustments include local basis differential, treating cost, transportation charges and/or crude quality and gravity corrections.

Future Development Costs, Expenses and Taxes

Capital expenditures (Future Development Costs), lease operating expenses and ad valorem tax values were forecast as provided by Earthstone. As you explained, the capital costs were based on the most current estimates, lease operating expenses were based on the analysis of historical actual expenses, operating overhead is included for non-operated properties and no credit or deduction is made for producing overhead paid to the company by other owners of the operated properties. Lease operating expenses are applied based on location, operatorship and wellbore orientation on a per-property or per-unit basis. Capital costs and lease operating expenses were held constant.

Severance tax rates were applied at normal state percentages of oil and gas revenue. Severance tax rates in certain instances, where authorized by taxing authorities, have severance tax abatements and were provided by your office and applied when appropriate.

Reserve Estimation Methods

The methods employed in estimating reserves are described on page 2 of the Appendix. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast

Cawley, Gillespie & Associates, Inc.

Earthstone Energy, Inc. Interests – NYMEX Strip Price Case

March 22, 2022

Page 3

using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy.

Non-producing reserve estimates, including undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved undeveloped reserves. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.

This evaluation includes six (6) developed non-producing properties and 87 proved undeveloped locations, all of which are commercial using strip pricing presented herein. The developed non-producing reserves include reactivations and drilled-but-uncompleted wells. Each of these commercial drilling locations proposed as part of Earthstone’s development plans conforms to the standards as set forth by the Petroleum Resources Management System. In our opinion, Earthstone has indicated it has every intent to complete this development plan as scheduled. Furthermore, Earthstone has demonstrated that it has adequate company staffing, financial backing and prior development success to ensure this development plan will be fully executed.

Miscellaneous

An on-site field inspection of the properties has not been performed nor has the mechanical operation or condition of the wells and their related facilities been examined, nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered. However, the estimated costs of plugging and abandoning wells have been included herein as provided.

The reserve classifications and the economic considerations applied herein conform to the criteria set forth in the June 2018 Petroleum Resources Management System (PRMS) approved by the Society of Petroleum Engineers (SPE). The SPE-PRMS guidelines are presented in brief form in pages 3 through 7 of the Appendix. The reserves and economics are predicated on 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. 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 and forecasts were based upon interpretations of data furnished by Earthstone and available from our files. Ownership information and economic factors such as liquid and gas prices, price differentials and expenses were furnished by Earthstone. To some extent, information from public records was 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. All estimates represent our best judgment based on the data available at the time of preparation. Due to inherent uncertainties in future production rates, commodity prices and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.

Closing

Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 60 years. This evaluation was supervised by W. Todd Brooker, President at

Cawley, Gillespie & Associates, Inc.

Earthstone Energy, Inc. Interests – NYMEX Strip Price Case

March 22, 2022

Page 4

Cawley, Gillespie & Associates, Inc. and a State of Texas Licensed Professional Engineer (License #83462). We do not own an interest in the properties of Earthstone Energy, Inc. and are not employed on a contingent basis. We have used all methods and procedures that we consider necessary under the circumstances to prepare this report. Our work-papers and related data utilized in the preparation of these estimates are available in our office.

Yours very truly,

Cawley, Gillespie & Associates, Inc.

Professional Qualifications of W. Todd Brooker, P.E.

President of Cawley, Gillespie & Associates

Mr. Brooker has been a Petroleum Consultant for Cawley, Gillespie & Associates (CG&A) since 1992, and became President in 2017. His responsibilities include reserve and economic evaluations, fair market valuations, field studies, pipeline resource studies and acquisition/divestiture analysis. His reserve reports are routinely used for public company SEC disclosures. His experience includes significant projects in both conventional and unconventional resources in every major U.S. producing basin and abroad, including oil and gas shale plays, coalbed methane fields, waterfloods and complex, faulted structures. Prior to CG&A he worked in Gulf of Mexico drilling and production engineering at Chevron USA. Mr. Brooker graduated with honors from the University of Texas at Austin in 1989 with a Bachelor of Science degree in Petroleum Engineering. He is a registered professional engineer in Texas, No. 83462, and a member of the Society of Petroleum Engineers (SPE) and the Society of Petroleum Evaluation Engineers (SPEE).

CAWLEY, GILLESPIE & ASSOCIATES, INC.

TEXAS REGISTERED ENGINEERING FIRM F-693

Cawley, Gillespie & Associates, Inc.

APPENDIX

TABLE OF CONTENTS

Earthstone Energy, Inc. Interests

As of December 31, 2021

REPORT LETTER

TODD BROOKER QUALIFICATIONS TABLE OF CONTENTS

SUMMARIES

•Table I – TP

•Table I – PD

PROVED DEVELOPED PRODUCING TAB

•Table I – PDP

•Table II – PDP (Sorted by Lease Name)

PROVED DEVELOPED NON-PRODUCING TAB

•Table I – PDNP

•Table II – PDNP (Sorted by Lease Name)

PROVED UNDEVELOPED TAB

•Table I – PUD

•Table II – PUD (Sorted by Lease Name)

APPENDIX TAB

•Page 1 - Explanatory Comments for Individual Tables

•Page 2 - Methods Employed in the Estimation of Reserves

•Pages 3,4 - Reserve Definitions and Classifications

Note:    Tables I are Grand Total Summaries of Reserves and Economics.

Tables II are “Lease” Summaries of Economics for wells/leases in corresponding Tables I.

Cawley, Gillespie & Associates, Inc.

APPENDIX

Explanatory Comments for Summary Tables

HEADINGS

Table I

Description of Table Information

Identity of Interest Evaluated

Property Description – Location

Reserve Classification and Development Status

Effective Date of Evaluation

FORECAST

(Columns)

(1) (11) (21)    Calendar or Fiscal years/months commencing on effective date.

(2) (3) (4)    Gross Production (8/8th) for the years/months which are economical. These are expressed as thousands of barrels (Mbbl) and millions of cubic feet (MMcf) of gas at standard conditions. Total future production, cumulative production to effective date, and ultimate recovery at the effective date are shown following the annual/monthly forecasts.

(5) (6) (7)        Net Production accruable to evaluated interest is calculated by multiplying the revenue interest times the gross production. These values take into account changes in interest and gas shrinkage.

(8)Average (volume weighted) gross liquid price per barrel before deducting production-severance taxes.

(9)Average (volume weighted) gross gas price per Mcf before deducting production-severance taxes.

(10)Average (volume weighted) gross NGL price per barrel before deducting production-severance taxes.

(12)Revenue derived from oil sales -- column (5) times column (8).

(13)Revenue derived from gas sales -- column (6) times column (9).

(14)Revenue derived from NGL sales -- column (7) times column (10).

(15)Revenue derived from hedge positions.

(16)Revenue derived from other sources not included in column (12) through column (15); may include revenue from electrical sales, pipeline gas transportation, 3rd party saltwater disposal, etc.

(17)Total Revenue – sum of column (12) through column (16).

(18)Production-severance taxes deducted from gross oil, gas and NGL revenue.

(20)    Revenue after taxes – column (16) less the total of column (17), column (18) and column (19).

(22)Ad Valorem taxes.

(23)Average gross wells.

(24)Average net wells are gross wells times working interest.

(25)Abandonment Costs are cost for plugging and the salvage value of equipment at abandonment.

(26)Overhead Expenses are contractual non-COPAS headquarters “G&A” overhead charges for operated wells.

(27)Other Deductions may include compression-gathering expenses, transportation costs, water disposal costs.

(28)Investments, if any, include re-completions, future drilling costs, pumping units, etc. and may include either tangible or intangible or both, and the costs for plugging and the salvage value of equipment at abandonment may be shown as negative investments at end of life.

(29) (30)        Future Net Cash Flow is column (17) less the total of column (18), column (19), column (22), column (25), column (26), column (27) and column (28). The data in column (29) are accumulated in column (30). Federal income taxes have not been considered.

(31)Cumulative Discounted Cash Flow is calculated by discounting monthly cash flows at the specified annual rates.

MISCELLANEOUS

DCF Profile    • The cumulative cash flow discounted at six different rates are shown at the bottom of columns (30-31). Interest has been compounded monthly.

Life    • The economic life of the appraised property is noted in the lower right-hand corner of the table.

Footnotes    • Comments regarding the evaluation may be shown in the lower left-hand footnotes.

Price Deck    • a table of oil and gas prices, price caps and escalation rates may be shown in the lower middle footnotes.

Cawley, Gillespie & Associates, Inc.

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) volumetricand (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 makes 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.

Cawley, Gillespie & Associates, Inc.

APPENDIX

Petroleum Reserves and Resources Classifications, Definitions and Guidelines

Reference is made herein to the Petroleum Resources Management System approved by the Society of Petroleum Engineers (SPE) Board of Directors, June 2018.

Reference is made herein to the Petroleum Reserves and Resources Classification, Definitions and Guidelines jointly published in 2018 by the Society of Petroleum Engineers (SPE), the World Petroleum Council (WPC), the American Association of Petroleum Geologists (AAPG), the Society of Petroleum Evaluation Engineers (SPEE), the Society of Exploration Geophysicists (SEG), the Society of Petrophysicists and Well Log Analysts (SPWLA), and the European Association of Geoscientists & Engineers (EAGE), hereinafter denoted as the SPE-PRMS Definitions.

Table 1: Recoverable Resources Classes and Sub-Classes

RESERVES

Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions.

Reserves must satisfy four criteria: discovered, recoverable, commercial, and remaining based on the development project(s) applied. Reserves are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by the development and production status.

To be included in the Reserves class, a project must be sufficiently defined to establish its commercial viability. This includes the requirement that there is evidence of firm intention to proceed with development within a reasonable time-frame.

A reasonable time-frame for the initiation of development depends on the specific circumstances and varies according to the scope of the project. While five years is recommended as a benchmark, a longer time-frame could be applied where, for example, development of an economic project is deferred at the option of the producer for, among other things, market-related reasons or to meet contractual or strategic objectives. In all cases, the justification for classification as Reserves should be clearly documented.

To be included in the Reserves class, there must be a high confidence in the commercial maturity and economic producibility of the reservoir as supported by actual production or formation tests. In certain cases, Reserves may be assigned on the basis of well logs and/or core analysis that indicate that the subject reservoir is hydrocarbon-bearing and is analogous to reservoirs in the same area that are producing or have demonstrated the ability to produce on formation tests.

On Production:The development project is currently producing or capable of producing and selling petroleum to market.

The key criterion is that the project is receiving income from sales, rather than that the approved development project is necessarily complete. Includes Developed Producing Reserves.

The project decision gate is the decision to initiate or continue economic production from the project.

Approved for Development:All necessary approvals have been obtained, capital funds have been committed, and implementation of the development project is ready to begin or is under way.

At this point, it must be certain that the development project is going ahead. The project must not be subject to any contingencies, such as outstanding regulatory approvals or sales contracts. Forecast capital expenditures should be included in the reporting entity’s current or following year’s approved budget.

The project decision gate is the decision to start investing capital in the construction of production facilities and/or drilling development wells.

Cawley, Gillespie & Associates, Inc.

APPENDIX

Petroleum Reserves and Resources Classifications, Definitions and Guidelines

Reference is made herein to the Petroleum Resources Management System approved by the Society of Petroleum Engineers (SPE) Board of Directors, June 2018.

Justified for Development: Implementation of the development project is justified on the basis of reasonable forecast commercial conditions at the time of reporting, and there are reasonable expectations that all necessary approvals/contracts will be obtained.

To move to this level of project maturity, and hence have Reserves associated with it, the development project must be commercially viable at the time of reporting and the specific circumstances of the project. All participating entities have agreed and there is evidence of a committed project (firm intention to proceed with development within a reasonable time-frame) There must be no known contingencies that could preclude the development from proceeding (see Reserves class).

The project decision gate is the decision by the reporting entity and its partners, if any, that the project has reached a level of technical and commercial maturity sufficient to justify proceeding with development at that point in time.

CONTINGENT RESOURCES

Those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by application of development projects, but which are not currently considered to be commercially recoverable owing to one or more contingencies.

Contingent Resources may include, for example, projects for which there are currently no viable markets, where commercial recovery is dependent on technology under development, where evaluation of the accumulation is insufficient to clearly assess commerciality, where the development plan is not yet approved, or where regulatory or social acceptance issues may exist.

Contingent Resources are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by the economic status.

Development Pending: A discovered accumulation where project activities are ongoing to justify commercial development in the foreseeable future.

The project is seen to have reasonable potential for eventual commercial development, to the extent that further data acquisition (e.g., drilling, seismic data) and/or evaluations are currently ongoing with a view to confirming that the project is commercially viable and providing the basis for selection of an appropriate development plan. The critical contingencies have been identified and are reasonably expected to be resolved within a reasonable time-frame. Note that disappointing appraisal/evaluation results could lead to a reclassification of the project to On Hold or Not Viable status.

The project decision gate is the decision to undertake further data acquisition and/or studies designed to move the project to a level of technical and commercial maturity at which a decision can be made to proceed with development and production.

Development on Hold: A discovered accumulation where project activities are on hold and/or where justification as a commercial development may be subject to significant delay.

The project is seen to have potential for commercial development. Development may be subject to a significant time delay. Note that a change in circumstances, such that there is no longer a probable chance that a critical contingency can be removed in the foreseeable future, could lead to a reclassification of the project to Not Viable status.

The project decision gate is the decision to either proceed with additional evaluation designed to clarify the potential for eventual commercial development or to temporarily suspend or delay further activities pending resolution of external contingencies.

Development Unclarified: A discovered accumulation where project activities are under evaluation and where justification as a commercial development is unknown based on available information.

Cawley, Gillespie & Associates, Inc.

APPENDIX

Petroleum Reserves and Resources Classifications, Definitions and Guidelines

Reference is made herein to the Petroleum Resources Management System approved by the Society of Petroleum Engineers (SPE) Board of Directors, June 2018.

The project is seen to have potential for eventual commercial development, but further appraisal/evaluation activities are ongoing to clarify the potential for eventual commercial development.

This sub-class requires active appraisal or evaluation and should not be maintained without a plan for future evaluation. The sub-class should reflect the actions required to move a project toward commercial maturity and economic production.

Development Not Viable: A discovered accumulation for which there are no current plans to develop or to acquire additional data at the time because of limited production potential.

The project is not seen to have potential for eventual commercial development at the time of reporting, but the theoretically recoverable quantities are recorded so that the potential opportunity will be recognized in the event of a major change in technology or commercial conditions.

The project decision gate is the decision not to undertake further data acquisition or studies on the project for the foreseeable future.

PROSPECTIVE RESOURCES

Those quantities of petroleum that are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations.

Potential accumulations are evaluated according to the chance of geologic discovery and, assuming a discovery, the estimated quantities that would be recoverable under defined development projects. It is recognized that the development programs will be of significantly less detail and depend more heavily on analog developments in the earlier phases of exploration.

Prospect: A project associated with a potential accumulation that is sufficiently well defined to represent a viable drilling target.

Project activities are focused on assessing the chance of geologic discovery and, assuming discovery, the range of potential recoverable quantities under a commercial development program.

Lead: A project associated with a potential accumulation that is currently poorly defined and requires more data acquisition and/or evaluation to be classified as a Prospect.

Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to confirm whether or not the Lead can be matured into a Prospect. Such evaluation includes the assessment of the chance of geologic discovery and, assuming discovery, the range of potential recovery under feasible development scenarios.

Play: A project associated with a prospective trend of potential prospects, but that requires more data acquisition and/or evaluation to define specific Leads or Prospects.

Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to define specific Leads or Prospects for more detailed analysis of their chance of geologic discovery and, assuming discovery, the range of potential recovery under hypothetical development scenarios.

Table 2: Reserves Status Definitions and Guidelines

DEVELOPED RESERVES

Developed Reserves are expected quantities to be recovered from existing wells and facilities.

Reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor compared to the cost of a well. Where required facilities become unavailable, it may be necessary

Cawley, Gillespie & Associates, Inc.

APPENDIX

Petroleum Reserves and Resources Classifications, Definitions and Guidelines

Reference is made herein to the Petroleum Resources Management System approved by the Society of Petroleum Engineers (SPE) Board of Directors, June 2018.

to reclassify Developed Reserves as Undeveloped. Developed Reserves may be further sub-classified as Producing or Non-Producing.

Developed Producing Reserves: Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate.

Improved recovery Reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves: Developed Non-Producing Reserves include Shut-in and Behind-pipe Reserves.

Shut-in Reserves are expected to be recovered from (1) completion intervals that are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES

Undeveloped Reserves are quantities expected to be recovered through future significant investments.

Undeveloped Reserves are to be produced (1) from new wells on undrilled acreage in known accumulations, (2) from deepening existing wells to a different (but known) reservoir, (3) from infill wells that will increase recovery, or (4) where a relatively large expenditure (e.g., when compared to the cost of drilling a new well) is required to (a) recomplete an existing well or (b) install production or transportation facilities for primary or improved recovery projects.

Table 3: Reserves Category Definitions and Guidelines

PROVED RESERVES

Proved Reserves are those quantities of petroleum that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable from a given date forward from known reservoirs and under defined economic conditions, operating methods, and government regulations.

If deterministic methods are used, the term “reasonable certainty” is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability (P90) that the quantities actually recovered will equal or exceed the estimate.

The area of the reservoir considered as Proved includes (1) the area delineated by drilling and defined by fluid contacts, if any, and (2) adjacent undrilled portions of the reservoir that can reasonably be judged as continuous with it and commercially productive 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 hydrocarbon (LKH) as seen in a well penetration unless otherwise indicated by definitive geoscience, engineering, or performance data. Such definitive information may include pressure gradient analysis and seismic indicators. Seismic data alone may not be sufficient to define fluid contacts for Proved.

Reserves in undeveloped locations may be classified as Proved provided that:

A.The locations are in undrilled areas of the reservoir that can be judged with reasonable certainty to be commercially mature and economically productive.

B.Interpretations of available geoscience and engineering data indicate with reasonable certainty that the objective formation is laterally continuous with drilled Proved locations.

Cawley, Gillespie & Associates, Inc.

APPENDIX

Petroleum Reserves and Resources Classifications, Definitions and Guidelines

Reference is made herein to the Petroleum Resources Management System approved by the Society of Petroleum Engineers (SPE) Board of Directors, June 2018.

For Proved Reserves, the recovery efficiency applied to these reservoirs should be defined based on a range of possibilities supported by analogs and sound engineering judgment considering the characteristics of the Proved area and the applied development program.

PROBABLE RESERVES

Probable Reserves are those additional Reserves that analysis of geoscience and engineering data indicates are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves.

It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50% probability (P50) that the actual quantities recovered will equal or exceed the 2P estimate.

Probable Reserves may be assigned to areas of a reservoir adjacent to Proved where data control or interpretations of available data are less certain. The interpreted reservoir continuity may not meet the reasonable certainty criteria.

Probable estimates also include incremental recoveries associated with project recovery efficiencies beyond that assumed for Proved.

POSSIBLE RESERVES

Possible Reserves are those additional reserves that analysis of geoscience and engineering data indicates are less likely to be recoverable than Probable Reserves.

The total quantities ultimately recovered from the project have a low probability to exceed the sum of Proved plus Probable plus Possible (3P), which is equivalent to the high-estimate scenario. When probabilistic methods are used, there should be at least a 10% probability (P10) that the actual quantities recovered will equal or exceed the 3P estimate.

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

Possible estimates also include incremental quantities associated with project recovery efficiencies beyond that assumed for Probable.

PROBABLE AND POSSIBLE RESERVES

See above for separate criteria for Probable Reserves and Possible Reserves.

The 2P and 3P estimates may be based on reasonable alternative technical interpretations within the reservoir and/or subject project that are clearly documented, including comparisons to results in successful similar projects.

In conventional accumulations, Probable and/or 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 minor faulting or other geological discontinuities and have not been penetrated by a wellbore but are interpreted to be in communication with the known (Proved) reservoir. Probable or Possible Reserves may be assigned to areas that are structurally higher than the Proved area. Possible (and in some cases, Probable) Reserves may be assigned to areas that are structurally lower than the adjacent Proved or 2P area.

Caution should be exercised in assigning Reserves to adjacent reservoirs isolated by major, potentially sealing faults until this reservoir is penetrated and evaluated as commercially mature and economically productive. Justification for assigning Reserves in such cases should be clearly documented. Reserves should not be assigned to areas that are clearly separated from a known accumulation by non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results); such areas may contain Prospective Resources.

In conventional accumulations, where drilling has defined a highest known oil (HKO) elevation and there exists the potential for an associated gas cap, Proved Reserves of oil should only be assigned in the structurally higher portions of the reservoir if there is reasonable certainty that such portions are initially above bubble point pressure based on documented engineering analyses. Reservoir portions that do not meet this certainty may be assigned as Probable and Possible oil and/or gas based on reservoir fluid properties and pressure gradient interpretations.

Cawley, Gillespie & Associates, Inc.