Exhibit 99.6

January 8, 2021

Mr. Eric Marsh

Chief Executive Officer

Brix Oil & Gas LP

5800 Granite Parkway, Suite 550

Plano, Texas 75024

Re: Brix Oil & Gas LP

Haynesville and Mid-Bossier Shale Properties

Estimate of Reserves and Revenues

Strip Pricing Case

“As of” January 1, 2021

Dear Mr. Marsh:

At your request, W.D. Von Gonten & Co. has prepared estimates of future reserves and projected net revenues for certain property interests owned by Brix Oil & Gas LP (“Brix”). This report was prepared for inclusion in certain filings made by the SEC as a reserves sensitivity analysis in accordance with the definitions and regulations of the SEC other than the use of optional price and cost parameters as specified in the report pursuant to Item 1202(b) of Regulation S-K. The report may be used for inclusion in certain SEC filings by Brix. These properties include producing, non-producing, undeveloped, probable, and possible locations located in Red River, DeSoto, Sabine, Bossier, Webster, Bienville, and Caddo Parishes, Louisiana. This report excludes effects of commodity derivatives. Our third party evaluation was completed on January 8, 2021. Our conclusions, as of January 1, 2021, are as follows:

Strip Price Case	Net to Brix Oil & Gas LP
	Proved Developed						Proved			Total			Probable			Possible
	Producing			Non-producing			Undeveloped			Proved			Undeveloped			Undeveloped
Reserve Estimates
Gas, MMcf		142,834.2			8,259.4			633,801.7			784,895.3			903,271.0			130,416.1
Revenues
Gas, $ (100) %		334,213,760			19,344,042			1,471,887,232			1,825,445,034			2,223,817,984			321,078,944
Total, $		334,213,760			19,344,042			1,471,887,232			1,825,445,034			2,223,817,984			321,078,944
Expenditures
Ad Valorem Taxes, $		8,811,386			239,249			22,573,290			31,623,925			29,468,840			4,702,550
Severance Taxes, $		8,018,685			201,146			18,437,404			26,657,235			23,310,816			3,309,091
Fixed Operating Expense, $		78,076,624			3,731,588			284,501,056			366,309,268			403,849,536			56,635,412
Variable Operating Expense, $		13,394,723			859,658			59,999,620			74,254,001			80,939,120			12,649,084
Marketing and Fuel, $		9,899,435			809,333			50,154,592			60,863,360			81,850,208			10,010,067
Total, $		118,200,853			5,840,974			435,665,962			559,707,789			619,418,520			87,306,204
Investments, $		2,859,510			614,314			576,600,463			580,074,287			946,770,753			142,652,274
Plugging & Abandonment, $		3,594,563			80,829			6,614,129			10,289,521			11,504,319			1,778,638
Total, $		6,454,073			695,143			583,214,592			590,363,808			958,275,072			144,430,912
Estimated Future Net Revenues (FNR)
Undiscounted FNR, $		209,558,816			12,807,920			453,006,688			675,373,424			646,124,352			89,341,872
FNR Disc. @ 10.0%, $		178,928,096			11,219,494			243,751,936			433,899,526			193,665,776			14,203,627
Allocation Percentage by Classification
FNR Disc. @ 10.0%		41.2	%		2.6	%		56.2	%		100.0	%		100.0	%		100.0	%

* Due to computer rounding, numbers in the above table may not sum exactly.

Purpose of Report – The purpose of this report is to provide Brix with an estimate of future reserves and net revenues attributable to interests owned by Brix in the Haynesville and Mid-Bossier shale formations effective as of January 1, 2021.

Scope of Work – W.D. Von Gonten & Co. was engaged by Brix to develop the appropriate reserve projections and estimate the remaining reserves associated with the developed and undeveloped properties included in this report. The properties evaluated by W.D. Von Gonten & Co. represent 100% of the total net proved and undeveloped gas reserves, 100% of the probable reserves, and 100% of the possible reserves owned by Brix as of January 1, 2021. All of Brix’s probable and possible reserves are undeveloped. Once reserves were estimated, future revenues were determined in accordance with Brix provided Henry Hub strip pricing effective December 31, 2020.

Reporting Requirements

Securities and Exchange Commission (SEC) Regulation S-X 210, Rule 4-10 and Regulation S-K 229, Item 1200 (as revised in December 2008, effective 1-1-10), and Accounting Standards Codification Topic 932 require oil and gas reserve information to be reported by publicly held companies as supplemental financial data. These regulations and standards provide for estimates of Proved reserves and revenues discounted at 10% and based on un-escalated prices and costs, however, this report is not prepared with SEC pricing but instead prepared with strip pricing as indicated under “Product Prices” below.

The information presented herein represents optional disclosure pursuant to Item 1202(b) of Regulation S-K.

Estimates of proved, probable and possible reserves presented in the report were prepared in conformance with the Securities and Exchange Commission (SEC) definitions and requirements as set-forth in Rule 4-10(a) of Regulation S-X as required by Item 1202(a)(8)(iv) of Regulation S-K.

Projections – The attached reserves and revenue projections are on a calendar year basis with the first time period being January 1, 2021 through December 31, 2021.

Property Discussion

Brix currently owns, and operates, an approximate 88% working interest in 22 Proved Developed Producing (“PDP”) wells and an approximate 17% working interest in 112 PDP wells that Vine operates. All wells are located in Red River, De Soto, Sabine, Bossier, Webster, Bienville, and Caddo Parishes, Louisiana. All existing proved and future development wells will be producing from the Haynesville and Mid-Bossier shale formations.

Reserve Estimates

Proved Producing Reserves – Reserve estimates for the PDP properties were based on volumetric calculations, log analysis, decline curve analysis, rate transient analysis, and/or analogy to nearby production, including from other operators.

Proved Undeveloped Reserves – The undeveloped reserves were necessarily estimated using volumetric calculations, log analysis, core analysis, geophysical interpretation and/or analogy to nearby recently drilled wells with comparative completion practices to that which Brix will implement. In addition, W.D. Von Gonten & Co. has performed a field study of the Haynesville and Mid-Bossier shale plays independent of this report. Our conclusion from that field study has fortified our confidence in the producing and undeveloped reserves included herein.

Probable and Possible Reserves – Estimates of probable and possible reserves are inherently imprecise and are more uncertain than proved reserves but have not been adjusted for risk due to that

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uncertainty. Probable and possible reserves are based on geoscience and/or engineering data similar to that used in estimates of proved reserves but technical or other uncertainties preclude such reserves being classified as proved. Like the proved producing and proved undeveloped reserves, probable and possible reserves were also estimated using volumetric calculations, log analysis, core analysis, geophysical interpretation and/or analogy to nearby recently drilled wells with comparative completion practices to that which Brix will implement. In addition, W.D. Von Gonten & Co. referenced the field study of the Haynesville and Mid-Bossier shale plays independent of this report. Our conclusion from that field study has fortified our confidence in the probable and possible reserves included herein.

Reserves and schedules of production included in this report are only estimates. The amount of available data, reservoir and geological complexity, reservoir drive mechanism, and mechanical aspects can have a material effect on the accuracy of these reserve estimates. Due to inherent uncertainties in future production rates, well costs, 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. We consider the assumptions, data, methods, and procedures used in this report appropriate hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves and future net revenues.

Product Prices

At the request of Brix, all revenue estimates represented herein are based on a Brix provided Henry Hub strip pricing beginning January of 2021. The following table summarizes the prices utilized in the generation of this report:

Month/Yr.	$/MmBtu	Month/Yr.	$/MmBtu	Month/Yr.	$/MmBtu	Month/Yr.	$/MmBtu	Month/Yr.	$/MmBtu
1/2021	2.467	2/2022	2.939	3/2023	2.599	4/2024	2.306	5/2025	2.331
2/2021	2.539	3/2022	2.792	4/2023	2.299	5/2024	2.281	6/2025	2.365
3/2021	2.526	4/2022	2.429	5/2023	2.265	6/2024	2.318	7/2025	2.403
4/2021	2.538	5/2022	2.384	6/2023	2.299	7/2024	2.362	8/2025	2.408
5/2021	2.555	6/2022	2.412	7/2023	2.338	8/2024	2.370	9/2025	2.400
6/2021	2.611	7/2022	2.447	8/2023	2.346	9/2024	2.368	10/2025	2.427
7/2021	2.685	8/2022	2.455	9/2023	2.334	10/2024	2.401	11/2025	2.527
8/2021	2.715	9/2022	2.435	10/2023	2.365	11/2024	2.519	12/2025	2.752
9/2021	2.712	10/2022	2.458	11/2023	2.458	12/2024	2.749	Thereafter	2.752
10/2021	2.741	11/2022	2.540	12/2023	2.674	1/2025	2.852
11/2021	2.796	12/2022	2.696	1/2024	2.779	2/2025	2.802
12/2021	2.913	1/2023	2.789	2/2024	2.736	3/2025	2.662
1/2022	3.006	2/2023	2.740	3/2024	2.596	4/2025	2.357

Average product prices were determined for the initial $ per MMBtu before adjustments for price differentials weighted by production over the remaining lives of the properties for each reserves category included in the report, e.g. total proved, total probable and total possible. In addition, average realized product prices were determined in $ per Mcf after adjustments for price differentials weighted by production over the remaining lives of the properties for each reserves category included in the report to comply with item 1202(a)(8)(v) of Regulation S-K.

Therefore, the proved reserves category has an average weighted price of $2.61/MMBtu before adjustments and $2.33/Mcf after adjustments. The probable and possible reserves category has an average weighted price of $2.75/MMBtu before adjustments and $2.47/Mcf after adjustments.

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Operating Expenses and Capital Cost

Monthly operating expenses for wells operated by Brix and other 3^rd party companies were provided by Brix. Brix provided W.D. Von Gonten & Co. Brix operated, non-operated, and a blend of both, with 12 months (December 2019—November 2020) of historical fixed and variable operating expense data. W.D Von Gonten & Co. then confirmed and applied Brix’s recommended fixed and variable costs to each individual operated and non-operated property.

Capital costs associated with the drilling and completion of future undeveloped locations were provided by Brix. Support data including drilling, completion, and facility costs, as well as current completion designs rendered applicable for future development wells were provided by Brix for wells spud from May 2019 through September 2020. Where available, these costs were further verified from recently drilled and competed wells from other regional and/or offsetting operators.

All operating expenses and capital costs were held flat for the life of the properties.

Other Considerations

Abandonment Costs – The costs necessary for abandonment of certain properties were provided by Brix. W.D. Von Gonten & Co. expresses no warranties regarding the accuracy or validity of these costs for the generation of this report.

Additional Costs – Costs were not deducted for general and administrative expenses, depletion, depreciation and/or amortization (a non-cash item) or federal income tax.

Data Sources – Data furnished by Brix included basic well information including daily/monthly gas and water production, flowing pressure data, costs (LOE and CAPEX), future development schedules with lateral well locations, lease acreage maps illustrating Haynesville and Mid-Bossier opportunities, and development locations for Haynesville and Mid-Bossier wells identified by Brix. Public data sources such as IHS Energy and the U.S. Geological Survey (USGS) were used to gather any additional necessary data.

Context – We specifically advise that any particular reserve estimate for a specific property not be used out of context from the overall report. The revenues and present worth of future net revenues are not represented to be market value either for individual properties or on a total property basis. The estimation of fair market value for oil and gas properties requires additional analysis other than evaluating undiscounted and discounted future net revenues.

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the January 1, 2021 estimated oil and gas volumes. The reserves in this report can be produced under current regulatory guidelines. Actual future commodity prices may differ substantially from the utilized pricing scenario which may or may not extend or limit the estimated reserve and revenue quantities presented in this report.

We have not inspected the properties included in this report, nor have we conducted independent well tests. W.D. Von Gonten & Co. and our employees have no direct ownership in any of the properties included in this report. Our fees are based on hourly expenses and are not related to the reserve and revenue estimates produced in this report. The responsible technical personnel referenced below have obtained the qualifications and meet the requirements of objectivity for Qualified Reserves Evaluator employed internally by W.D. Von Gonten & Co. as set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information (2019 ed.) promulgated by the SPE.

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Thank you for the opportunity to assist Brix with this report.

	Respectfully submitted,
	William D. Von Gonten, Jr., P.E.
	TX # 73244
	John M. Parker

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PETROLEUM RESERVES AND RESOURCES CLASSIFICATION AND DEFINITIONS

This document contains information excerpted from definitions and guidelines prepared by the Oil and Gas Reserves Committee of the Society of Petroleum Engineers (SPE) and reviewed and jointly sponsored by the World Petroleum Council (WPC), the American Association of Petroleum Geologists (AAPG), and the Society of Petroleum Evaluation Engineers (SPEE).

Preamble

Petroleum resources are the estimated quantities of hydrocarbons naturally occurring on or within the Earth’s crust. Resource assessments estimate total quantities in known and yet-to-be discovered accumulations; resources evaluations are focused on those quantities that can potentially be recovered and marketed by commercial projects. A petroleum resources management system provides a consistent approach to estimating petroleum quantities, evaluating development projects, and presenting results within a comprehensive classification framework.

These definitions and guidelines are designed to provide a common reference for the international petroleum industry, including national reporting and regulatory disclosure agencies, and to support petroleum project and portfolio management requirements. They are intended to improve clarity in global communications regarding petroleum resources. It is expected that this document will be supplemented with industry education programs and application guides addressing their implementation in a wide spectrum of technical and/or commercial settings.

It is understood that these definitions and guidelines allow flexibility for users and agencies to tailor application for their particular needs; however, any modifications to the guidance contained herein should be clearly identified. The definitions and guidelines contained in this document must not be construed as modifying the interpretation or application of any existing regulatory reporting requirements.

1.0 Basic Principles and Definitions

The estimation of petroleum resource quantities involves the interpretation of volumes and values that have an inherent degree of uncertainty. These quantities are associated with development projects at various stages of design and implementation. Use of a consistent classification system enhances comparisons between projects, groups of projects, and total company portfolios according to forecast production profiles and recoveries. Such a system must consider both technical and commercial factors that impact the project’s economic feasibility, its productive life, and its related cash flows.

1.1 Petroleum Resources Classification Framework

Petroleum is defined as a naturally occurring mixture consisting of hydrocarbons in the gaseous, liquid, or solid phase. Petroleum may also contain non-hydrocarbons, common examples of which are carbon dioxide, nitrogen, hydrogen sulfide and sulfur. In rare cases, non-hydrocarbon content could be greater than 50%.

The term “resources” as used herein is intended to encompass all quantities of petroleum naturally occurring on or within the Earth’s crust, discovered and undiscovered (recoverable and unrecoverable), plus those quantities already produced. Further, it includes all types of petroleum whether currently considered “conventional” or “unconventional.”

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Figure 1-1 is a graphical representation of the SPE/WPC/AAPG/SPEE resources classification system. The system defines the major recoverable resources classes: Production, Reserves, Contingent Resources, and Prospective Resources, as well as Unrecoverable petroleum.

The “Range of Uncertainty” reflects a range of estimated quantities potentially recoverable from an accumulation by a project, while the vertical axis represents the “Chance of Commerciality, that is, the chance that the project that will be developed and reach commercial producing status.

The following pages contain the definitions in Tables 1, 2, and 3 that display the major classes and sub-classes of petroleum reserves and resources as defined by the SPE:

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Table 1: Recoverable Resources Classes and Sub-Classes

Class/Sub-Class	Definition	Guidelines
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: they must be discovered, recoverable, commercial, and remaining based on the development project(s) applied. Reserves are further subdivided in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their development and production status. To be included in the Reserves class, a project must be sufficiently defined to establish its commercial viability. There must be a reasonable expectation that all required internal and external approvals will be forthcoming, and 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 5 years is recommended as a benchmark, a longer time frame could be applied where, for example, development of economic projects are 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 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 and selling petroleum to market.	The key criterion is that the project is receiving income from sales, rather than the approved development project necessarily being complete. This is the point at which the project “chance of commerciality” can be said to be 100%. The project “decision gate” is the decision to initiate commercial 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 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 entities 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.

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Class/Sub-Class	Definition	Guidelines
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.	In order 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, based on the reporting entity’s assumptions of future prices, costs, etc. (“forecast case”) and the specific circumstances of the project. Evidence of a firm intention to proceed with development within a reasonable time frame will be sufficient to demonstrate commerciality. There should be a development plan in sufficient detail to support the assessment of commerciality and a reasonable expectation that any regulatory approvals or sales contracts required prior to project implementation will be forthcoming. Other than such approvals/contracts, there should be no known contingencies that could preclude the development from proceeding within a reasonable timeframe (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 due to one or more contingencies.	Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. 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 their 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 re-classification 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.

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Class/Sub-Class	Definition	Guidelines
Development Unclarified or 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 eventual commercial development, but further appraisal/evaluation activities are on hold pending the removal of significant contingencies external to the project, or substantial further appraisal/evaluation activities are required to clarify the potential for eventual commercial development. Development may be subject to a significant time delay. Note that a change in circumstances, such that there is no longer a reasonable expectation that a critical contingency can be removed in the foreseeable future, for example, 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 Not Viable	A discovered accumulation for which there are no current plans to develop or to acquire additional data at the time due to 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 any further data acquisition or studies on the project for the foreseeable future.
Prospective Resources	Those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations.	Potential accumulations are evaluated according to their chance of 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 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 in order 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 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 which requires more data acquisition and/or evaluation in order 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 discovery and, assuming discovery, the range of potential recovery under hypothetical development scenarios.

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Table 2: Reserves Status Definitions and Guidelines

Status	Definition	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 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 to be recovered from completion intervals that are open and producing at the time 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 which 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 which will require additional completion work or future re-completion prior to start of production. 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 investments:	(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.

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Table 3: Reserves Category Definitions and Guidelines

Category	Definition	Guidelines
Proved Reserves	Proved Reserves are those quantities of petroleum, which 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 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 (see “2001 Supplemental Guidelines,” Chapter 8). Reserves in undeveloped locations may be classified as Proved provided that: •  The locations are in undrilled areas of the reservoir that can be judged with reasonable certainty to be commercially productive. •  Interpretations of available geoscience and engineering data indicate with reasonable certainty that the objective formation is laterally continuous with drilled Proved locations. 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 which analysis of geoscience and engineering data indicate 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 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.

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Category	Definition	Guidelines
Possible Reserves	Possible Reserves are those additional reserves which analysis of geoscience and engineering data indicate 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 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 commercial production from the reservoir by a defined 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 and commercial 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 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 oil Reserves 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.

Brix Oil & Gas, L.P. – 01.01.21 3P Reserves Report, Strip Pricing, January 8, 2021 – Page 13