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Table of Contents

Tables

Ref: 10356.117285

August 19, 2026

Renergen Limited

1 Bompas Road

Dunkeld West

Johannesburg, 2196

Republic of South Africa

Attn: Mr. Nick Mitchell, Chief Operating Officer

Re: 2025 Update on the Estimation of Natural Gas Reserves, Including Helium, and Associated Economics of Tetra4’s Interest in the Virginia Gas Field in the Free State of the Republic of South Africa (As of February 28, 2025)

Dear Mr. Mitchell,

At the request of Renergen Limited (hereinafter referred to as “Renergen”), Sproule Incorporated (“Sproule ERCE”), an independent sub-surface consultancy based in Calgary, Canada, has conducted an independent assessment of the unconventional methane and helium reserves of Tetra4 (Pty) Ltd. (hereinafter referred to as “Tetra4” or “Company”) in the Virginia Gas Field, on the production right 24/04/07PR, located in the Free State of the Republic of South Africa as of February 28, 2025. Renergen owns 94.5% of the equity interests Tetra4. This report is an update of our prior report titled “2024 Update on the Estimation of Natural Gas Reserves, Including Helium, and Associated Economics of the Tetra4 Interest in the Virginia Gas Field in the Free State of the Republic of South Africa as of February 29, 2024” (the “2024 Report”) and has been prepared for the purpose of Renergen’s use in a filing with the Securities Exchange Commission in the U.S.A. This evaluation is both an engineering and an economic update, based on the analysis methodology described herein using technical and economic data supplied by Tetra4 of Tetra4’s 100% working interest in the South African Production Right 24/04/07PR.

Material changes to this report are reservoir category changes as follows: In the Proved Developed Non-Producing (PDNP) category, 6 wells carried as separate entities in 2024 moved to Proved Developed Producing (PDP) in 2025 as a single entity (the Phase 1C wells), and 2 wells moved to the Temporarily Abandoned (TA) category, which have no reserves assigned. In the Proved Undeveloped (PUD) category, 10 wells were moved from Probable (PRB) in 2024 to PUD in 2025. In the TA category, 2 wells came in from PDNP, and 11 wells were new additions to the TA category, which were wells drilled since the 2024 Report. Other material changes are updated CAPEX and OPEX costs and schedules, updated

currency exchange rates, updated methane and helium prices, the addition of a methane and helium plant efficiency factor, an updated field development plan, and updated execution risk factors assigned to the proved undeveloped wells; which are detailed below.

This evaluation includes estimates of recoverable methane and helium volumes from Proved Reserves including Proved Developed Producing Wells, Proved Developed Non-Producing Wells and Proved Undeveloped Locations. In addition to the total Proved Reserves, Probable and Possible Reserves are also estimated. These reserves constitute over 80% of the Company’s reserve base. Associated pre-tax net present value of future income for selected discount rates are presented for Reserves volumes. Estimates of Net Present Value (NPV), either discounted or undiscounted, are a calculation of the Reserve value at a given date and are not a representation of the fair market value of a company or corporation owning a working interest in the project. This report is of the Company’s assets using estimation methods and data culminating in an opinion on the reasonableness of reserves volumes and economic values consistent with SEC rules and SPE auditing standards. This report and opinion have been prepared in accordance with generally accepted petroleum engineering and evaluation principles per the SPE Standards (June 2019), and SEC Regulations (Rule 4-10 of Reg S-X and Subpart 1200 of Reg S-K). Definitions of reserves categories and terms conform to the SEC definitions per Rule 4-10 and are appended in Appendix A.

The independent Reserve estimates and associated economics contained in this report are prepared in accordance with the United States Securities Exchange Commission (SEC) guidance and provides a Technical Value, defined as an assessment of a mineral asset’s current net economic benefit at the valuation date under a set of assumptions deemed most appropriate by a practitioner as explained in further detail below. Sproule ERCE’s evaluation is based upon data supplied by Tetra4, supplemented where necessary by Sproule ERCE’s corporate awareness of current South African industry costs and best practices and such assumptions, data, methods and procedures are appropriate for the purpose served by this report.

Reserve Estimates

The Reserve and Resource estimates contained in this report have been prepared with a data cutoff date of February 28, 2025, and are independently generated from the data supplied to Sproule ERCE from Tetra4. Sustained commercial sales of methane gas from pilots and from production wells located on the Tetra4 licenses and periodic measurements of the free flow gas volumes from multiple blowers, some producing for decades, allow estimates of the gas production decline rate and thus ultimate recoverable volumes of gas. This opinion covers: proved reserves quantities and volumes; changes in proved reserves during the period; estimates of future net revenue from proved, probable and possible reserves; and the present value (PV-10) of future net revenue discounted as 10% per annum (pre-income tax). This report covers in excess of 80% of the Company’s proved reserves as of the effective date, exceeding the SEC minimum audit coverage threshold of 80%.

Estimated gross and net methane and helium Reserves are summarized in Table 1 and Table 3. For the purposes of clarification, the use of the abbreviation ‘MM’ equates to millions of the specified unit throughout this text. Sproule ERCE has calculated the economics according to the assumptions detailed in this report and the net present values are presented in Table 2 and Table 4 as both Undiscounted (NPV=0), and at the specified discount factor.

Table 1: Methane Reserves Gross and Net Volumes

Notes:

1. Gross Methane does not include the Methane plant shrinkage factor of 6%, therefore there is a 6% reduction from Gross to Net volume.

Table 2: NPV from Methane Sales

Notes:

1. P&A costs for 15 wells excluded in the 2024 Report due to the Company scheduled abandonment dates being outside the report time frame were included in the economic analysis for this report, however they had no material impact on the NPV calculations.

Table 3: Helium Reserves Gross and Net Volumes

Notes:

1. Total PDNP reserves are 0.032 MMCF, but 0.0 in significant digits for table.

2. Gross Helium already includes the Helium plant shrinkage factor of 4.5%, so there is no reduction from Gross to Net volume.

Table 4: NPV from Helium Sales

Statement of Risk

The accuracy of reserves, resources, and economic evaluations is always subject to uncertainty. The magnitude of this uncertainty is generally proportional to the quantity and quality of data available for analysis. As a prospect, project, or well matures and new information becomes available revisions may be required which may either increase or decrease the previous estimates. Sometimes these revisions may result not only in a significant change to the reserves, resources and value assigned to a property, but also may impact the total company reserves, resources and economic status. The independent reserves, resources and economic forecasts contained in this report were based upon a technical analysis of the available data using accepted geoscience and engineering principles. Estimates in this report are, in aggregate, reasonable within established audit tolerance guidelines of 10% in quantities and economic values as outlined in SPE auditing standards and SEC guidance. However, they must be accepted with the understanding that further information and future reservoir performance subsequent to the date of the estimate may justify their revision. Sproule ERCE has reviewed and accepted the Company’s documentation of its lease position and its ability to permit the field development plan and found that it is reasonable, however any significant delay can impact project economics. It is Sproule

ERCE’s opinion that the independent estimated reserves, resources, economics, and other information as specified in this report are reasonable and have been prepared in accordance with SEC rules and guidance as well as generally accepted geoscience and petroleum engineering and evaluation principles. Notwithstanding the aforementioned opinion, Sproule ERCE makes no warranties concerning the data and interpretations of such data. Neither Sproule ERCE, nor any of its employees, have any interest in the subject properties and neither the employment to do this work, nor the compensation, is contingent on Sproule ERCE’s estimates of the resources or economic evaluations for the properties in this report. The data and work papers used in this preparation of this report are available for examination by authorized parties in Sproule ERCE’s offices. Sproule ERCE gives its permission for the release of this report, for public view, by Renergen. Public parties that view the report can do so for informational purposes only.

Thank you for this opportunity to be of service to Renergen. If you have any questions or wish to discuss any aspect of the report further, please feel free to contact either of us.

Sincerely,

Sproule Incorporated

/s/ Jeffrey B. Aldrich

Jeffrey B. Aldrich, L.P.G.

Principal, Geoscientist

Certification

Report Preparation

This report entitled “2025 Update on the Estimation of Natural Gas Reserves, Including Helium, and Associated Economics of Tetra4’s Interest in the Virginia Gas Field in the Free State of the Republic of South Africa as of February 28, 2025” is authenticated by the following Sproule ERCE professionals.

Project Leader

Designated Responsible Member Validation

This report has been reviewed and validated in accordance with the Professional Practice Management Plan of Sproule ERCE by the following Designated Responsible Member of Sproule Incorporated.

Certificate of Qualification

Jeffrey Aldrich, L.P.G., P.Geo.

I, Jeffrey B. Aldrich, Principal, Geoscientist of Sproule Incorporated, 2301 Blake Street, Suite 100, Denver, Colorado, USA, declare the following:

1. I hold the following degree:

a. B.Sc. Geology (1977), Vanderbilt University, Nashville, TN, USA

b. M.Sc. Geology (1983), Texas A&M University, College Station, TX, USA

2. I am a licensed Professional:

a. Licensed Professional Geoscientist (P.G.) Louisiana, USA #394

b. Licensed Professional Geoscientist (P.G.) Texas, USA # 15140

c. Certified Petroleum Geologist (C.P.G) The American Association of Petroleum Geologists #6254

3. I am a member of the following professional organizations:

a. Association of Professional Engineers and Geoscientists of Alberta (APEGA)

b. American Association of Petroleum Geologists (AAPG)

c. Society of Petroleum Engineers (SPE)

4. I am a qualified reserves evaluator and reserves auditor as defined in:

a. the “Canadian Oil and Gas Evaluation Handbook” as promulgated by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and,

b. the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” as promulgated by the Society of Petroleum Engineers and incorporated into the “Petroleum Resource Management System” (SPE-PRMS).

5. My contribution to the report entitled “2025 Update on the Estimation of Natural Gas Reserves, Including Helium, and Associated Economics of Tetra4’s Interest in the Virginia Gas Field in the Free State of the Republic of South Africa (As of February 28, 2025)” is based on my geoscience knowledge and the data provided to me by the Company, from public sources, and from the non-confidential files of Sproule ERCE.

6. I have no interest, direct or indirect, nor do I expect to receive any interest, direct or indirect, in the properties described in the above-named report or in the securities of Renergen Limited.

Certificate of Qualification

Mark Stouffer, P.E.

I, Mark Stouffer, Senior Petroleum Engineer of Sproule Incorporated, 2301 Blake Street, Suite 100, Denver, Colorado, declare the following:

1. I hold the following degrees:

a. M.E. in Petroleum Engineering (1988), Texas A&M University, College Station, TX, USA

b. B.S. in Petroleum Engineering (1983), The University of Tulsa, Tulsa, OK, USA

2. I am a registered Professional:

a. Professional Engineer (P.E.), State of Colorado, USA.

3. I am a member of the following professional organizations:

a. Society of Petroleum Engineers (SPE)

4. I am a qualified reserves evaluator and reserves auditor as defined in:

a. the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” as promulgated by the Society of Petroleum Engineers and incorporated into the “Petroleum Resource Management System” (SPE-PRMS).

5. My contribution to the report entitled “2025 Update on the Estimation of Natural Gas Reserves, Including Helium, and Associated Economics of Tetra4’s Interest in the Virginia Gas Field in the Free State of the Republic of South Africa (As of February 28, 2025)” is based on my engineering knowledge and the data provided to me by the Company, from public sources, and from the non-confidential files of Sproule ERCE.

6. I have no interest, direct or indirect, nor do I expect to receive any interest, direct or indirect, in the properties described in the above-named report or in the securities of Renergen Limited.

Certificate of Qualification

Meghan M. Klein, P.Eng.

I, Meghan M. Klein, Head of Reservoir Engineering, Americas of Sproule International Limited, 900, 140 Fourth Avenue SW, Calgary, Alberta, declare the following:

1. I hold the following degree:

a. B.A.Sc. Geological Engineering (2005), University of Waterloo, Waterloo, ON, Canada

2. I am a registered Professional:

a. Professional Engineer (P.Eng.), Province of Alberta, Canada

3. I am a member of the following professional organizations:

a. Association of Professional Engineers and Geoscientists of Alberta (APEGA)

b. Society of Petroleum Engineers (SPE)

c. Canadian Institute of Mining, Metallurgy and Petroleum (CIM)

4. I am a qualified reserves evaluator and reserves auditor as defined in:

a. the “Canadian Oil and Gas Evaluation Handbook” as promulgated by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and,

b. the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” as promulgated by the Society of Petroleum Engineers and incorporated into the “Petroleum Resource Management System” (SPE-PRMS).

5. My contribution to the report entitled “2025 Update on the Estimation of Natural Gas Reserves, Including Helium, and Associated Economics of Tetra4’s Interest in the Virginia Gas Field in the Free State of the Republic of South Africa (As of February 28, 2025)” is based on my engineering knowledge and the data provided to me by the Company, from public sources, and from the non-confidential files of Sproule ERCE.

6. I have no interest, direct or indirect, nor do I expect to receive any interest, direct or indirect, in the properties described in the above-named report or in the securities of Renergen Limited.

1. Material Changes Since Prior Report

1.1 Field Development and Execution

The Methane LNG and Helium liquefier plant had operational startup difficulties during the reporting period with the helium liquefier being taken offline for all of March and April 2024 then again for the period of November 2024 through January 2025 and only limited test production in the times between. This severely limited the amount of helium that was able to be sold during this reporting period. During the March and April 2024 shutdown, the Methane LNG portion of the plant was offline thus all commodity sales were halted, and wells had to be shut in. Methane and helium production had resumed by the end of the reporting period however the plant still underwent start-up efficiency optimization with further planned shutdowns for the following year. This has delayed the planned start date of the large-scale drilling campaign.

The Company used the time of the low plant productivity to test new exploration concepts within the license area as well as testing alternative completion methods. Thus, the planned drilling of PUD locations was deliberately delayed as there was not an immediate requirement for additional gas production. The Company chose instead to test new exploration concepts with a limited drilling program. The exploration program delivered a new reservoir, the Permian Karoo Vryheid Sandstone, with a good flow test. As of the effective date of this report, more evaluation is required prior to the addition of reserves in the Vryheid Sandstone. It is anticipated that as the Company connects more wells to the Phase I plant and achieves full capacity the Phase II program will be brought online in a timely manner. Sproule ERCE requested and received documentation of Phase II rig contracts and rig availability. Sproule ERCE has modified the assessment assumptions regarding the timing of bringing the plant to full production, the timing of the Phase II drilling program, and the timing of the Phase II plants. Sproule ERCE has reviewed the commitment of Renergen’s parent company, ASP Isotopes, and the Board of Directors to proceed to the Phase II program, the Company’s planning for both the completion of Phase I, the planned execution of Phase II and determined that they are detailed and still meet the requirements of a 5-year plan.

A summary of well status changes since the 2024 Report is included in Table 5.

Table 5: Drilled Wells

2. Economic Parameters

2.1 Capital Costs

Sproule ERCE has reviewed Tetra4’s past expenditures and future budgets. The following summarizes the capital costs provided by Tetra4.

Well drilling and completion CAPEX is budgeted at $360,000 USD per well. Well connection CAPEX is $28,578 per well, making the total well cost $388,578 per well.

Total remaining Phase 1C pipeline gas gathering capital of 10.2 million USD will be spent in February 2026 in the amount of 5.0 million USD and in February 2027 in the amount of 5.2 million USD.

The Phase 2 gas gathering pipeline project will commence construction in February 2027, and will total 187.5 million USD, scheduled as follows: 2.7 million USD in February 2027, 41.5 million USD in February 2028, 124.2 million USD in February 2029, and 19.1 million USD in February 2030.

The number and expenditure dates for the methane and helium liquification plants required for each reserves category are tailored according to the field-wide gas production profile for each reserves category. All methane and helium liquification plants will consist of modular pairs, each with an inlet capacity of 45 MMscfd. If necessary, these plants can operate at a 50% turndown rate, or 22.5 MMscfd.

Capital for a single pair of 45 MMscfd liquifiers is 397.2 million USD and capital for connection to the electrical grid is 8.9 million USD.

Development of the 1P (Proved) Reserves yields a maximum total field rate of 43 MMscfd, requiring a single pair of liquifiers, and capital is scheduled in June 2027.

Development of the 2P (Proved plus Probable) Reserves yields a maximum total field rate of 74 MMscfd, requiring two pairs of liquifiers, and capital is scheduled in June 2027 and August 2028.

Development of the 3P (Proved, Probable plus Possible) Reserves yields a maximum total field rate of 108 MMscfd, requiring three pairs of liquifiers, and capital is scheduled in June 2027, March 2028, and December 2028.

All capital costs were held constant for the life of the project. Due to requirements for separate reporting of Methane and Helium reserves and values, all capital was proportioned at 75% for Methane and 25% for Helium.

2.2 Operating Expenses

The following summarizes the operating expenses provided by Tetra4.

Operating expenses for Phase 1 are 191,555 USD/month, which includes operation of the existing gas gathering system and existing producing wells. Power costs for Phase 1 are an additional 131,060

USD/month. Both costs are the same for the 1P, 2P, and 3P scenarios because Phase 1 consists of only the existing wells, gathering lines, and plant.

Phase 2 costs for generator rental are 3,405,999 USD/month, and is the same for the 1P, 2P, and 3P scenarios.

Phase 2 plant operating expenses are 1,111,111 USD/month for the 1P scenario, 1,994,949 USD/month for the 2P scenario, and 2,752,525 USD/month for the 3P scenario.

Abandonment costs of 20,266 USD per well were included in the evaluation.

All wells were burdened with a royalty paid to Goldsfields, in the amount of 0.21 USD/mcf of wellhead gas.

All operating expenses were held constant for the life of the project. Due to requirements for separate reporting of Methane and Helium reserves and values, all operating expenses were proportioned at 75% for Methane and 25% for Helium.

2.3 Prices and Interests

A methane price of 17.26 USD/MMbtu was provided by Tetra4, based on a weighted average sales price from their gas sales contracts, and held constant over the life of the project.

Similarly, a helium price of 450 USD/Mcf was provided by Tetra4 and held constant over the life of the project.

Renergen owns a 94.5% equity interest in Tetra4. This report is generated at the property (license) level where Tetra4 holds 100% of the interest in the Production License. Therefore, this report reflects 100% Working Interest and 100% Net Revenue Interest aside from the 0.21 USD/mcf of wellhead gas royalty paid to Goldfields. There is no royalty burden other than the Goldfields royalty described in the Operating Expenses section.

2.4 Plant Processing and Efficiency Parameters

Based on information received from Tetra4, Sproule ERCE used a methane BTU factor of 0.9811 MMbtu/Mcf, which is a weighted average of 70% of the gross heating value of methane and 30% of the net heating value of methane.

Based on information received from Tetra4, gas shrinkage from wellhead through the plant is 4.5% for helium, and 6.0% for methane.

Due to operational issues associated with the helium and methane liquification plants described in the Field Development and Execution section, a plant efficiency factor was utilized in the economic evaluation. This factor accounts for the fact that the plants have not operated at 100% efficiency historically but allows for expected stepwise improvements in efficiency as the project progresses into Phase 2.

Historical LNG and Helium sales data were reviewed for 2024 and 2025, and plant efficiency factors were calculated based on those periods. Based on this historical data and expected improvements in efficiency, the following ramping schedules were used for plant efficiency factors.

For Helium, the plant efficiency factor is 0.8% until Phase 2 begins in April 2027, then increases to 50% until April 2028, then increases to 95% for the remaining life of the project.

For Methane, the plant efficiency factor is 70% until January 2026, then increases to 80% until Phase 2 begins in April 2027, then increases to 85% until April 2028, then increases to 95% for the remaining life of the project. The Methane plant efficiency factor has an additional step prior to the startup of Phase 2 because the historical efficiencies in 2024 were significantly lower than in 2025, while for Helium, 2024 and 2025 historical efficiencies were similar.

3. Uncertainties

Any natural gas field development will have unforeseen challenges during the execution of the field development plan, some in geologic nature, some with the ability to successfully drill and complete the wells, others to build, maintain and run the gas processing plants. Proved undeveloped locations in the reserves report prepared by Sproule ERCE are included in our development plan and are scheduled to be drilled within five years from the year they were initially recorded, consistent with the SEC’s five-year rule requirement. Annually, management creates a capital expenditure plan based on our best available data at the time the plan is developed. The development plan is based upon management’s evaluation of a number of qualitative and quantitative factors including estimated risk-based returns, estimated well density, commodity prices and cost forecasts, recent drilling results and well performance, and anticipated availability of services, equipment, supplies, and personnel. All proved undeveloped planned locations are along known faults with penetrations of blowers and wells with sustained gas flows. These are in-fill locations or step out locations from known penetrations along mapped faults (the productive reservoir). Sproule ERCE has built into the economic assessment an execution success factor to reflect the ability of the Company to drill, complete, and flow PUD locations without having to spend extra planned capital. Sproule ERCE has applied these execution success factors by reducing the gross deliverable gas in each type of curve by an execution success factor profile. Based on historical performance with completing development wells Sproule ERCE has assigned a 70% success factor to the first ten PUD wells, a 75% success factor to the following ten PUD wells and an 80% success factor the next 30 PUD wells. The remaining wells are assigned a success factor of 85%. With time, it may be demonstrated that the Company may have a success rate that will allow us to reduce or remove the execution success factor from the economic analysis.

The Company must maintain its development license with the State and obtain all necessary permits to drill out its development plan and construct the connection lines. This requires maintaining a good working relationship with all stakeholders, and to date the Company has an excellent track record maintaining these critical relationships. Delays in future permits can delay the field development thus negatively impact the production of field gases and lower the NPV.

Future commodity prices are subject to global influences and are beyond the Company’s control.

4. Conclusions

Table 6 and Table 7 show a comparison of Methane and Helium reserve values for the current report (February 28, 2025, effective date) compared to the 2024 Report (February 29, 2024, effective date).

Table 6: Virginia Gas Field – Comparison of Gross and Net Methane Reserves

Table 7: Virginia Gas Field – Comparison of Gross and Net Helium Reserves

Appendix A

Appendix A: SEC Reserves Definition

Effective Date: January 1, 2020

Financial Accounting and Reporting for Oil and Gas Producing Activities Pursuant to the Federal Securities Laws and the Energy Policy and Conservation Act of 1975.

Definitions

The following definitions apply to the terms listed below as they are used in this section:

1. Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property,

a. including costs of lease bonuses and options to purchase or lease properties, the portion of costs

b. applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

2. Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock

a. and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

b. Same geological formation (but not necessarily in pressure communication with the

i. reservoir of interest);

c. Same environment of deposition;

d. Similar geological structure; and

e. Same drive mechanism.

f. Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

3. Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid

a. state in natural deposits with a viscosity greater than 10,000 centipoise measured at original

b. temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

4. Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

5. Deterministic estimate. The method of estimating reserves or resources is called deterministic

a. when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

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

a. 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

b. Through installed extraction equipment and infrastructure operational at the time of the

i. reserves estimate if the extraction is by means not involving a well.

7. Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

a. Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

b. Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

c. Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

d. Provide improved recovery systems.

8. Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

9. Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known-to be productive.

10. Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

11. Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

12. Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

a. Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.

b. Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

c. Dry hole contributions and bottom hole contributions.

d. Costs of drilling and equipping exploratory wells.

e. Costs of drilling exploratory-type stratigraphic test wells.

13. Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

14. Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

15. Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in

overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

16. Oil and gas producing activities.

a. Oil and gas producing activities include:

i. The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;

ii. The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

iii. The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

1. Lifting the oil and gas to the surface; and

2. Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

iv. Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

b. Oil and gas producing activities do not include:

i. Transporting, refining, or marketing oil and gas;

ii. Processing of produced oil, gas or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

iii. Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

iv. Production of geothermal steam.

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

a. 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.

b. 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.

c. 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.

d. 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.

e. 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.

f. Pursuant to paragraph (a)(22)(iii) of this section, 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.

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.

a. 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.

b. 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.

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

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

19. Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

20. Production costs.

a. Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

i. Costs of labor to operate the wells and related equipment and facilities.

ii. Repairs and maintenance.

iii. Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

iv. Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

v. Severance taxes.

b. Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

21. Proved area. The part of a property to which proved reserves have been specifically attributed.

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.

a. 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

b. 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.

c. 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.

d. 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.

e. 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.

23. Proved properties. Properties with proved reserves.

24. Reasonable certainty. If deterministic methods are used, reasonable certainty means 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. 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.

25. Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

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 (a)(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).

27. Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

28. Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

29. Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

30. Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.

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.

a. 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.

b. 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.

c. 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.

32. Unproved properties. Properties with no proved reserves.

Appendix B

Appendix B: Reserve Cashflow Summaries

Total Proved Helium Cashflows

Total Proved Methane Cashflows

Total Proved Plus Probable Helium Cashflows

Total Proved Plus Probable Methane Cashflows

Total Proved Plus Probable Plus Possible Helium Cashflow

Total Proved Plus Probable Plus Possible Methane Cashflows

Appendix C

Appendix C: Oneline Summaries

Locations