EXHIBIT 99.2

WILLIAM M. COBB & ASSOCIATES, INC.

Worldwide Petroleum Consultants

12770 Coit Road, Suite 907	(972) 385-0354
Dallas, Texas 75251	Fax: (972) 788-5165

January 17, 2024

Via email: jcoates@protongreen.com

Mr. John Coates Proton Green LLC

2000 Bering Drive, Suite 210

Houston TX 77057

As requested by Proton Green LLC (Proton Green), William M. Cobb & Associates, Inc. (Cobb & Associates) has prepared this report describing our evaluation of developing the in-place and potentially-recoverable volumes of helium within that portion of the St. Johns Field leased by Proton Green and located in Arizona (the Field), and the resulting potential value of developing those volumes. This analysis is based on the well data, test data, prior studies, and development cost estimates made available to us, and provides estimates of the helium project’s recoverable volumes and economics over a range of economic assumptions.

This report replaces the prior Cobb & Associates helium studies prepared for Proton Green in 2022. This report does not include the “proved developed producing reserves” volumes and value associated with the ongoing production from the 11-8-30 St. Johns Well, which were described in the November 2023 report. Also, this report does not include the additional potential value of beverage grade carbon dioxide (CO²) sales, which has been presented in the January 2024 Cobb & Associates report. This report assumes that those beverage grade CO² sales occur, reducing the cost of gas re-injection in the Field.

Evaluation Stipulations

This report describes the estimation of the in-place and potentially-recoverable helium gas volumes in the St. Johns Field. Because these gases are not hydrocarbons, they are not subject to the SEC’s or the petroleum industry’s hydrocarbon reserves definitions. However, to put these volumes into a technical context, this report treats them as “contingent resources” associated with the Field’s remaining development, as defined by the petroleum industry’s Petroleum Resources Management System, revised in June 2018 (the PRMS).

The PRMS defines “contingent resources” as “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.” The “contingent” aspect of this resource relates to the current absence of a budgeted development project for the wells beyond the 11-8-30 St. Johns Well. Commitments to the execution of a development project would remove this contingency for those portions of the Field subject to those commitments. Reserves could then be assigned to those portions of the Field associated with production, and would increase as wells are brought on production either through reactivation or drilling and completion.

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In contrast to this project’s commercial contingency, several of the technical uncertainties associated with this project have been addressed by the extensive data gathering and well testing programs carried out by the prior operators of the Field (Ridgeway, Enhanced Oil Resources, and Kinder Morgan). This evaluation was based on well data, production test data, and prior studies supplied by Proton Green. Kinder Morgan, in particular, expended a considerable amount of technical effort in analyzing the development of potential of the Field. Cobb & Associates has reviewed those studies, considers them reliable, and has incorporated their results into this evaluation where appropriate.

No review has been made of any agreements under which the Field would be developed and operated. No on-site Field inspection or review of the title to the properties has been carried out. No review has been made of the permitting requirements of this project, nor of the ability of Proton Green to obtain any such needed permits or approvals.

The results presented in this report are based on geologic and engineering judgment, and as such are estimates. There are uncertainties in the analysis of the available data. Any estimated future production volumes may or may not, in fact, occur. Volumes may increase or decrease as a result of future operations, or as the result of unforeseen geological conditions. Therefore, these results are not warranted or guaranteed as to their accuracy, but represent opinions based on the interpretation of technical data.

Summary

The Field contains a mixture of gases, predominantly CO², nitrogen, and helium, and if fully developed would be one of the larger sources of helium in the world. Helium is used in the space industry, cryogenic creation of superconductors (such as in the rapidly-growing MRI scanning needs of the health-care industry), pressurizing and purging systems of contaminants, controlled atmospheres used for semiconductor manufacturing, inert gas welding, and several other industries. The nitrogen and CO² would be separated, the nitrogen vented, and the CO² either sold as beverage-grade CO² or reinjected into the southern portion of the Field.

The goals of this feasibility study include estimating, or incorporating other experts’ estimates, of the following: 1) the volume of total gas in place within the Field; 2) the amount of gas that might be produced under reasonable development scenarios; 3) the resulting volumes of recoverable helium; 4) the approximate cost and timing of wells and facilities required to recover those volumes; and 5) the overall potential economic value of the project. All these results are estimates with significant uncertainty associated with their values. These values will change, and the uncertainty will be reduced, as additional information is gathered in the Field as a result of development activities.

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Based on geologic maps developed for each of the major geologic zones in the St. Johns Field and the distribution of helium within those geologic zones, Cobb & Associates arrived at the following estimates of the Field’s in-place and recoverable gas volumes. Volumes are given in billions of standard cubic feet (BCF). Helium volumes are listed as the volume of pure helium contained in the gas produced by the processing facility, which will recover approximately 95 percent of the helium processed, and will produce a sales stream with a helium concentration of approximately 98 percent. The Development Case assumes a staged development from 40 million cubic feet per day (MMCF/D) of offtake to 160 MMCF/D to 310 MMCF/D, and assumes development of the Amos Wash and Granite formations in the northern Field area, which has a higher helium concentration. The area contributing helium and subject to development was estimated using a minimum economic helium content cutoff for each formation. Table 1 summarizes the estimated overall size of the resource and the amount that might be developed by this project.

Table 1: St. Johns Field Analysis Summary

	Total		Development			Development Case Without
	Field		Case			11-8-30 Well
Original Gas In Place (OGIP), BCF		9,307		4,940			4,940
Helium In Place, BCF		33.4		21.7			21.7
Total Gas Produced, BCF				2,472			2,468
Total Helium Produced, BCF				10.33			10.32
Percent of OGIP Processed				50.04	%		49.96	%
Maximum Helium Production Rate, MCF/D				1296			1296

The potential economic value of this helium extraction project is most affected by uncertainty in helium pricing and project capital and operating costs. Current helium production is sold for $610/MCF. Lower-price sensitivity cases of $400/MCF and $500/MCF were run to address some of the uncertainty in helium pricing. Some of the project cost uncertainty was addressed by running high-cost sensitivity cases with a 50 percent increase in all capital and operating costs. Expenditures are assumed to begin January 1, 2024, production on January 1, 2025, with the present values, discounted at 10 percent, referenced to a January 1, 2024 as-of date.

Table 2 summarizes the pre-tax economic analysis results for the six resulting cases, with the economic assumptions given in Table 3. The effect of assumed helium price on IRR and PV10 values for the base and high-cost cases is given in Figure 1.

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Table 2: St. Johns Field Economic Analysis Results

	$400/MCF			$500/MCF			$610/MCF
Base Cost Cases:
IRR		51	%		76	%		107	%
PV10, Millions	$	506		$	768		$	1,055
Payout, Years		5			4			4
High-Cost Cases:
IRR		22	%		36	%		53	%
PV10, Millions	$	241		$	502		$	790
Payout, Years		8			6			5

Figure 1: Potential Helium Extraction Project Economics

 

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Table 3: St. Johns Field Economic Assumptions

Factor	Value
% Net Revenue Interest		80	%
Average % Helium		0.44	%
Average % Nitrogen		6.23	%
Average % CO2		93.33	%
Helium Recovery Efficiency		95	%
Facility O&M, $/MCF	$	0.25
Prod., Inj. Well O&M, $/Well/Month	$	3,000
Prod, Inj. Well Capex, $/Well	$	750,000
Gathering System Cost per Well	$	100,000
Injection Lines	$	2,000,000
Facility Rental/mo for one IACX 10 MMCF/D Train	$	70,000
Facility Capex, $ for first 150 MMCF/D Train	$	75,000,000
Add Facility Capex, $ for second 150 MMCF/D Train	$	75,000,000

Field Geology and Gas Content

Geologic Setting: The St. Johns field structurally trends Northwest-to-Southeast in Apache County in east-central Arizona and Catron County in west-central New Mexico. The field area is located on the southern edge of the Colorado Plateau, northeast of the Mogollon Rim and north-northeast of the White Mountains. Volumetric analysis in this report is confined to that portion of the St. Johns field leased by Proton Green and located in Arizona (the Field). The various operators have conducted productive CO² tests in three separate zone, the Fort Apache, Amos Wash, and Granite.

Lithologically, the Ft. Apache Member of the Yeso Formation is categorized as dominantly dolomite with subordinate amounts of anhydrite, sandstone, and siltstone. The Amos Wash Member is dominantly sandstone with subordinate amounts of siltstone, dolomite, and anhydrite. The target of Kinder Morgan’s efforts was the fractured Granite formation, comprised of variable Precambrian granites.

Petrophysical Analysis: The porosity values used in this report are derived from cross-plotting the neutron and density curves to resolve lithology variations and gas effects. Once a petrophysical porosity model was established and verified against core porosity, water saturation (Sw) was estimated.

Gas-Water Contact Depth Estimation: The gas accumulation at St. Johns appears to be underlain by water. Estimating the location of the contact between gas and water affects the calculation of OGIP because the contact depths determine how much of each zone in the reservoir contains gas. To determine the contact locations, Cobb & Associates reviewed the pressure data and estimated the average reservoir pressures by zone, determined the depth of the lowest known gas, and then combined that depth with the pressure data to calculate the gas-water contact (GWC) depth for each zone.

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Helium Concentration Map: The available helium and nitrogen composition data was examined and found to vary aerially while being relatively consistent between zones. The mapped helium and nitrogen composition data reflect average values by location, resulting in the helium composition map presented in Figure 2. The helium concentration is highest in the north. This variation in composition permits optimization of the development plan by allowing Field development and facilities to be designed for the relatively helium-rich gas in the northern part of the Field, resulting in the Development Case.

Figure 2: Helium Concentration (Fraction) Map

 

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Zone and Field Maps: Seven separate maps were created for each of the zones to spatially distribute the industrial gas pore thickness (IGPT, equal to net thickness * porosity * 1-Sw), and result in reasonable estimates of OGIP in the Field area. These maps were: structure top, gross thickness, net-to-gross ratio, net thickness, porosity, Sw, and IGPT. The GWCs were used to constrain the lateral extent of each final individual IGPT map. Areal locations of the GWCs were used as vertical “cookie-cutters” on initial unconstrained IGPT maps.

OGIP Results: Once the total gas-bearing reservoir pore volume was known for each zone, the OGIP was calculated. The reservoir volume of total gas was converted to a volume of gas at standard conditions based on the average pressure for each zone and the appropriate pressure- volume adjustment factor (known as the gas formation volume factor, denoted as Bg). The standard conditions used in this analysis were 60^o F and 14.7 psia.

Helium Volume Results: The resulting zone IGPT maps were then converted to maps of feet of helium at standard conditions by multiplying the IGPT by that zone’s gas formation volume factor and by the helium concentration map. These standard feet of gas maps were then used to calculate the helium target volume in each zone (see below). The by-zone standard condition helium thickness maps are illustrated in Figures 3 and 4 for the Amos Wash and Granite zones.

Figure 3: Amos Wash Helium Content Figure 4: Granite Zone Helium Content

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Development Evaluation

Development Area Identification: Helium concentrations vary across the Field, with lower values in the south and higher values in the north. Incremental well economics were run at various helium content values to estimate the minimum standard conditions helium thickness for each of the two target zones, the Amos Wash and the Granite, that would be economic to develop. That cutoff was found to be approximately 1.5 feet of helium for the Granite zone and 3.0 feet of helium for the Amos Wash (because of its lower productivity). The corresponding contours are identified with the red arrows on the helium content maps. Volumetric calculations were then performed on those two geologic zones to estimate the area, the OGIP and helium GIP for the development areas.

Development Plan: The project consists of a three-phase expansion of gas processing over a three- year period. It begins with the installation of four 10 MMCF/D IACX trains for a total initial gas processing capacity of 40 MMCF/D. Each train costs $70,000/month to rent (assumed to start on production startup). The next year a portion of the main plant would be installed sufficient to handle 150 MMCF/D at a cost of $75,000,000. At that time three of the IACX trains would be removed, resulting in a total gas processing capacity of 160 MMCF/D. The third phase would occur one year later, with the main plant expanded to handle a total of 300 MMCF/D at an additional cost of $75,000,000, resulting in a total gas processing capacity of 310 MMCF/D. Once total Field rates decline below 300 MMCF/D the rental cost of the remaining IACX train is eliminated from the economic calculations. The facility costs and capacities were provided by a third-party engineering firm and are assumed to be reasonable.

Sufficient wells were drilled to support production, with wells drilled as needed to maintain the design rate of the facility. The Granite zone was chosen as the first development target, based on the high productivity of this zone as observed by Kinder Morgan. They found that open hole horizontal wells had test rates of up to 20 MMCF/D. For this evaluation each Granite zone well was assumed to develop 640 acres which contained an average GIP of 7.94 BCF. An initial total gas rate of 10 MMCF/D was assumed for the first year, with the rate declined as needed to produce 80 percent of that GIP (based on prior simulation results) down to a minimum rate of 0.1 MMCF/D. This resulted in a well life of six years. There are approximately 61 available 640-acre Granite zone well sites.

Once the 61 Granite zone locations were drilled the Amos Wash zone was developed. Each Amos Wash zone well was assumed to develop 320 acres which contained an average GIP of 15.92 BCF. An initial rate of 2 MMCF/D was assumed for the first year, with the rate declined as needed to produce 50 percent of that GIP (based on prior simulation results) down to a minimum rate of 0.1 MMCF/D, or 20 years, whichever occurred first. There are approximately 280 available 320-acre Amos Wash well sites.

The project includes the use of three existing Granite zone Kinder Morgan wells (one being the 11-8-30 well now on production), which reduces the initial capital costs.

In addition, CO² injection wells in the southern low-helium-concentration area of the Field or vented as nitrogen. The analyses assumed each injector would handle 20 MMCF/D, with periodic replacements required over time.

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Table 4 presents the drilling schedule, with drilling continued until all locations were drilled. The resulting gas production forecast is also presented in Table 4. This table excludes the production associated with the 11-8-30 well.

Table 4: Potential Production Rates and Drilling Schedules

	40/160/310 MMCF/D Case
Year	Tot MCF/Day		Helium MCF/Day		Production Wells		Injection Wells		Total Wells
2024		0		0		3		0		3
2025		36,127		151		14		0		14
2026		156,127		653		24		10		34
2027		307,363		1,285		18		1		19
2028		310,000		1,296		84		1		85
2029		310,000		1,296		47		1		48
2030		310,000		1,296		27		1		28
2031		310,000		1,296		19		1		20
2032		310,000		1,296		15		1		16
2033		310,000		1,296		13				13
2034		310,000		1,296		12				12
2035		310,000		1,296		12				12
2036		310,000		1,296		12				12
2037		310,000		1,296		12				12
2038		310,000		1,296		12				12
2039		310,000		1,296		12				12
2040		310,000		1,296		4				4
2041		293,556		1,227						0
2042		270,952		1,133						0
2043		250,089		1,045						0
2044		230,832		965						0
2045		213,058		891						0
2046		196,652		822						0
2047		181,510		759						0
2048		167,534		700						0
2049		154,634		646						0
2050		142,727		597						0
2051		131,737		551						0

Note: Of 3 2024 Production Wells, 1 is new drill

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Recoverable Gas Volume Estimation: Once the OGIP and helium GIP volumes were calculated from the maps for the two zones, the next step was to estimate the volume of that gas that is potentially recoverable. The average helium content of the processed gas, 0.44 percent, was estimated by dividing the helium GIP by the OGIP for the two zones in the target areas. The producing life of this project was assumed to be approximately 27 years, so the recoverable gas volume for St. Johns was defined to be that volume of gas that was produced and processed over that 27-year period from the target areas. This recoverable volume was dependent on both the OGIP volume and the development plan. The resulting processed total gas volumes and potential sales helium volumes are given in Table 1 for each development case.

Drilling Cost Estimates: The open-hole horizontal Granite zone wells, the fracture-stimulated vertical shallow formation wells, and the injection wells are estimated to cost approximately

$750,000 each. The total well costs are given in Table 3. Future drilling optimization, the use of existing wells, and actual well performance could decrease or increase the number of wells needed to maintain production rates.

Facility Evaluation

The economic viability of a capital-intensive project such as this is greatly affected by the ability to efficiently install a low-cost facility (both in terms of capital and operating expenditures) that can effectively process the volumes of gas required to provide adequate economic return for the investment required. While there is not an exact analog for this type of field elsewhere in the world, standard gas processing technology can be reasonably applied. This facility plan involves the use of proven processing technology: physical solvent followed by pressure swing adsorption (PSA).

Gas Gathering Requirements: The Development Area covers approximately 140 square miles in the northern part of the Field from which gas is to be produced over the 27-year project life. Flow lines will be added on an as-needed basis to connect the central facility to the production wells and to injection wells in the southern part of the Field.

Central Processing Facility: The process chosen for this project is the use of a physical solvent (Coastal AGR/Dow Selexol) followed by PSA. This process was selected by the third-party engineering firm because of its high helium recovery and product gas purity, no inlet dehydration requirement, along with lower power consumption than a straight PSA design. There are opportunities for process improvement and optimization which have not been evaluated because they are beyond the scope of this study.

Capital and Operating Cost Estimates: The total facility capital cost estimates for the development case provided in Table 3 are based on values supplied by the third-party engineering firm. Operating costs were estimated separately for wells and for the processing facilities. For wells an estimate of $3,000 per well per month was used, based on typical oil field experience. A gas processing cost estimate of $0.25 per MCF of produced gas was used, based on information from the third-party engineering firm.

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Project Economics

The calculation of screening economic values was conducted using an economics spreadsheet tool. The calculations were pre-tax and included no inflation. The present worth calculations were brought back to a January 1, 2024 as-of date. A summary of the results is given in Table 2, the key economic assumptions are listed in Table 3, a depiction of the drilling schedule and production rates is given in Table 4, and the potential cash flows are given in Table 5 for the base case, assuming a $610/MCF helium price, and in Table 6 for the case with a 50% cost increase and a $400/MCF helium price.

Table 5: Potential Cash Flows, 40/160/310 MMCF/D, He at $610/MCF, Base Costs, $ Millions

Year	Well Capital		Gathering, Injection System Capital		Helium Recovery Plant Capital		Total Capital		Gas Treatment O&M		IACX Plant Rental		Well O&M		Total O&M		Total Capital and O&M		Total Revenue		Cash Flow
2024	$	1.20	$	0.40	$	0.00	$	1.60	$	0.00	$	0.00	$	0.00	$	0.00	$	1.60	$	0.00	$	(1.60	)
2025	$	10.50	$	1.40	$	75.00	$	86.90	$	3.30	$	3.36	$	0.61	$	7.27	$	94.17	$	26.90	$	(67.27	)
2026	$	25.50	$	5.40	$	75.00	$	105.90	$	14.25	$	0.84	$	1.84	$	16.92	$	122.82	$	116.24	$	(6.58	)
2027	$	14.25	$	1.90	$	0.00	$	16.15	$	28.05	$	0.84	$	2.48	$	31.37	$	47.52	$	228.84	$	181.32
2028	$	63.75	$	8.50	$	0.00	$	72.25	$	28.29	$	0.84	$	5.51	$	34.64	$	106.89	$	230.81	$	123.92
2029	$	36.00	$	4.80	$	0.00	$	40.80	$	28.29	$	0.84	$	7.20	$	36.33	$	77.13	$	230.81	$	153.68
2030	$	21.00	$	2.80	$	0.00	$	23.80	$	28.29	$	0.84	$	8.06	$	37.19	$	60.99	$	230.81	$	169.82
2031	$	15.00	$	2.00	$	0.00	$	17.00	$	28.29	$	0.84	$	8.24	$	37.37	$	54.37	$	230.81	$	176.44
2032	$	12.00	$	1.60	$	0.00	$	13.60	$	28.29	$	0.84	$	7.92	$	37.05	$	50.65	$	230.81	$	180.16
2033	$	9.75	$	1.30	$	0.00	$	11.05	$	28.29	$	0.84	$	7.74	$	36.87	$	47.92	$	230.81	$	182.89
2034	$	9.00	$	1.20	$	0.00	$	10.20	$	28.29	$	0.84	$	8.14	$	37.26	$	47.46	$	230.81	$	183.34
2035	$	9.00	$	1.20	$	0.00	$	10.20	$	28.29	$	0.84	$	8.57	$	37.70	$	47.90	$	230.81	$	182.91
2036	$	9.00	$	1.20	$	0.00	$	10.20	$	28.29	$	0.84	$	9.00	$	38.13	$	48.33	$	230.81	$	182.48
2037	$	9.00	$	1.20	$	0.00	$	10.20	$	28.29	$	0.84	$	9.43	$	38.56	$	48.76	$	230.81	$	182.05
2038	$	9.00	$	1.20	$	0.00	$	10.20	$	28.29	$	0.84	$	9.86	$	38.99	$	49.19	$	230.81	$	181.62
2039	$	9.00	$	1.20	$	0.00	$	10.20	$	28.29	$	0.84	$	10.30	$	39.42	$	49.62	$	230.81	$	181.18
2040	$	3.00	$	0.40	$	0.00	$	3.40	$	28.29	$	0.84	$	10.44	$	39.57	$	42.97	$	230.81	$	187.84
2041	$	0.00	$	0.00	$	0.00	$	0.00	$	26.79	$	0.00	$	10.44	$	37.23	$	37.23	$	218.56	$	181.34
2042	$	0.00	$	0.00	$	0.00	$	0.00	$	24.72	$	0.00	$	10.44	$	35.16	$	35.16	$	201.74	$	166.57
2043	$	0.00	$	0.00	$	0.00	$	0.00	$	22.82	$	0.00	$	10.44	$	33.26	$	33.26	$	186.20	$	152.94
2044	$	0.00	$	0.00	$	0.00	$	0.00	$	21.06	$	0.00	$	10.44	$	31.50	$	31.50	$	171.86	$	140.36
2045	$	0.00	$	0.00	$	0.00	$	0.00	$	19.44	$	0.00	$	10.44	$	29.88	$	29.88	$	158.63	$	128.75
2046	$	0.00	$	0.00	$	0.00	$	0.00	$	17.94	$	0.00	$	10.44	$	28.38	$	28.38	$	146.42	$	118.03
2047	$	0.00	$	0.00	$	0.00	$	0.00	$	16.56	$	0.00	$	10.44	$	27.00	$	27.00	$	135.14	$	108.14
2048	$	0.00	$	0.00	$	0.00	$	0.00	$	15.29	$	0.00	$	10.44	$	25.73	$	25.73	$	124.74	$	99.01
2049	$	0.00	$	0.00	$	0.00	$	0.00	$	14.11	$	0.00	$	10.44	$	24.55	$	24.55	$	115.13	$	90.58
2050	$	0.00	$	0.00	$	0.00	$	0.00	$	13.02	$	0.00	$	10.44	$	23.46	$	23.46	$	106.27	$	82.80
2051	$	0.00	$	0.00	$	0.00	$	0.00	$	12.02	$	0.00	$	10.44	$	22.46	$	22.46	$	98.08	$	75.62

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Table 6: Potential Cash Flows, 40/160/310 MMCF/D, He at $400/MCF, High Costs, $ Millions

Year	Well Capital		Gathering, Injection System Capital		Helium Recovery Plant Capital		Total Capital		Gas Treatment O&M		IACX Plant Rental		Well O&M		Total O&M		Total Capital and O&M		Total Revenue		Cash Flow
2024	$	1.80	$	0.60	$	0.00	$	2.40	$	0.00	$	0.00	$	0.00	$	0.00	$	2.40	$	0.00	$	(2.40	)
2025	$	15.75	$	2.10	$	112.50	$	130.35	$	4.94	$	3.36	$	0.92	$	9.22	$	139.57	$	17.64	$	(121.93	)
2026	$	38.25	$	8.10	$	112.50	$	158.85	$	21.37	$	0.84	$	2.75	$	24.96	$	183.81	$	76.22	$	(107.59	)
2027	$	21.38	$	2.85	$	0.00	$	24.23	$	42.07	$	0.84	$	3.73	$	46.64	$	70.86	$	150.06	$	79.20
2028	$	95.63	$	12.75	$	0.00	$	108.38	$	42.43	$	0.84	$	8.26	$	51.53	$	159.91	$	151.35	$	(8.56	)
2029	$	54.00	$	7.20	$	0.00	$	61.20	$	42.43	$	0.84	$	10.80	$	54.07	$	115.27	$	151.35	$	36.08
2030	$	31.50	$	4.20	$	0.00	$	35.70	$	42.43	$	0.84	$	12.10	$	55.37	$	91.07	$	151.35	$	60.28
2031	$	22.50	$	3.00	$	0.00	$	25.50	$	42.43	$	0.84	$	12.37	$	55.64	$	81.14	$	151.35	$	70.21
2032	$	18.00	$	2.40	$	0.00	$	20.40	$	42.43	$	0.84	$	11.88	$	55.15	$	75.55	$	151.35	$	75.80
2033	$	14.63	$	1.95	$	0.00	$	16.58	$	42.43	$	0.84	$	11.61	$	54.88	$	71.46	$	151.35	$	79.89
2034	$	13.50	$	1.80	$	0.00	$	15.30	$	42.43	$	0.84	$	12.20	$	55.48	$	70.78	$	151.35	$	80.57
2035	$	13.50	$	1.80	$	0.00	$	15.30	$	42.43	$	0.84	$	12.85	$	56.12	$	71.42	$	151.35	$	79.93
2036	$	13.50	$	1.80	$	0.00	$	15.30	$	42.43	$	0.84	$	13.50	$	56.77	$	72.07	$	151.35	$	79.28
2037	$	13.50	$	1.80	$	0.00	$	15.30	$	42.43	$	0.84	$	14.15	$	57.42	$	72.72	$	151.35	$	78.63
2038	$	13.50	$	1.80	$	0.00	$	15.30	$	42.43	$	0.84	$	14.80	$	58.07	$	73.37	$	151.35	$	77.98
2039	$	13.50	$	1.80	$	0.00	$	15.30	$	42.43	$	0.84	$	15.44	$	58.72	$	74.02	$	151.35	$	77.33
2040	$	4.50	$	0.60	$	0.00	$	5.10	$	42.43	$	0.84	$	15.66	$	58.93	$	64.03	$	151.35	$	87.32
2041	$	0.00	$	0.00	$	0.00	$	0.00	$	40.18	$	0.00	$	15.66	$	55.84	$	55.84	$	143.32	$	87.48
2042	$	0.00	$	0.00	$	0.00	$	0.00	$	37.09	$	0.00	$	15.66	$	52.75	$	52.75	$	132.29	$	79.54
2043	$	0.00	$	0.00	$	0.00	$	0.00	$	34.23	$	0.00	$	15.66	$	49.89	$	49.89	$	122.10	$	72.21
2044	$	0.00	$	0.00	$	0.00	$	0.00	$	31.60	$	0.00	$	15.66	$	47.26	$	47.26	$	112.70	$	65.44
2045	$	0.00	$	0.00	$	0.00	$	0.00	$	29.16	$	0.00	$	15.66	$	44.82	$	44.82	$	104.02	$	59.20
2046	$	0.00	$	0.00	$	0.00	$	0.00	$	26.92	$	0.00	$	15.66	$	42.58	$	42.58	$	96.01	$	53.43
2047	$	0.00	$	0.00	$	0.00	$	0.00	$	24.84	$	0.00	$	15.66	$	40.50	$	40.50	$	88.62	$	48.11
2048	$	0.00	$	0.00	$	0.00	$	0.00	$	22.93	$	0.00	$	15.66	$	38.59	$	38.59	$	81.79	$	43.20
2049	$	0.00	$	0.00	$	0.00	$	0.00	$	21.17	$	0.00	$	15.66	$	36.83	$	36.83	$	75.50	$	38.67
2050	$	0.00	$	0.00	$	0.00	$	0.00	$	19.54	$	0.00	$	15.66	$	35.20	$	35.20	$	69.68	$	34.49
2051	$	0.00	$	0.00	$	0.00	$	0.00	$	18.03	$	0.00	$	15.66	$	33.69	$	33.69	$	64.32	$	30.63

Cobb & Associates appreciates this opportunity to be of service to Proton Green. Please let me know if you have any questions regarding this evaluation.

Sincerely,

WILLIAM M. COBB & ASSOCIATES, INC.

Texas Registered Engineering Firm F-84

/s/ Randal M. Brush

Randal M. Brush, P.E.

President

      RMB