Exhibit 99.3

Reserves Attributable to Trio Petroleum Corp

South Salinas Area

for

Phased and Full Development

Effective Date April 30, 2024

SEC Reserve Definitions & Pricing Guidelines

Prepared for

Trio Petroleum Corp

June 2024

KLS Petroleum Consulting LLC

Reserves Attributable to Trio Petroleum Corp., South Salinas Project

June 28, 2024

Table of Contents

1	Location and Geologic Setting		4
2	Development History		14
	2.1	Texaco HV 1-15	15
	2.2	Texaco HV 2-15	16
	2.3	Sohio HV 1-34	16
	2.4	Sohio BM 1-2	16
	2.5	Trio BM 1-2-RD1	17
	2.6	Venoco BM 2-2	18
	2.7	Seneca BM 201	19
	2.8	Veneco HV 1-35	20
	2.9	Venoco HV 1-35-RD1	20
	2.10	Venoco BM 2-6	21
	2.11	Venoco HV 3-6	21
	2.12	Trio HV-3A	21
	2.13	Trio HV-1	23
3	Reserves Assessment		25
	3.1	Analog Fields	25
	3.2	Average Reservoir and Fluid Properties	30
	3.3	South Salinas Estimate of Oil & Gas In-Place	35
	3.4	Probabilistic Modeling of Reserves	37
4	Development Plan and Reserves Forecast		45
5	Economic Analysis		49
6	Economic Results		52

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List of Tables

Table 1.	Summary of Reservoir & Oil Properties for Targeted Reservoirs	31
Table 2.	Parameter Ranges & Distributions Used in Probabilistic Modeling	35
Table 3.	Number of Possible Wells w/ Full Development by Area & Reservoir	36
Table 4.	Estimated South Salinas OOIP & OGIP within Leasehold	37
Table 5.	Development Plan - Phases 1, 2 & 3 Wells and Targeted Reservoirs	46
Table 6.	South Salinas Economic Parameters	49
Table 7.	First-of-Month Oil & Gas Benchmark Pricing	50
Table 8.	Estimated Capital for Permitting & Field Infrastructure	51
Table 9.	One-Line Economic Summary for Phase 1 Wells	52
Table 10.	One-Line Economic Summary for Phase 2 Wells	53
Table 11.	Economic Output for Phase 1 Probable (P2) Reserves	55
Table 12.	Economic Output for Phase 2 Probable (P2) Reserves	56
Table 13.	Economic Output for Phase 3 Probable (P2) Reserves	57
Table 14.	Economic Output for Total South Salinas Probable Reserves	58
Table 15.	Economic Output for Phase 1 Possible (P3) Reserves	59
Table 16.	Economic Output for Phase 2 Possible Reserves	60
Table 17.	Economic Output for Phase 3 Possible (P3) Reserves	61
Table 18.	Economic Output for Total South Salinas Possible (P3) Reserves	62
Table 19.	Economic Output for Monterey Blue Well HV-2 Probable (P2) Reserves	63
Table 20.	Economics for Monterey Yellow Well HV 56-19 Probable (P2) Reserves	64
Table 21.	Economics for Vaqueros Well BM 23-1-H Possible (P10) Reserves	65
Table 22.	Glossary of Terms Used to Characterize Reserves & Projects	66

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List of Figures

Figure 1.	Regional Setting of South Salinas Project (Source: Trio)	4
Figure 2.	Subregional Location Map of South Salinas (Source: Trio)	5
Figure 3.	Humpback and Presidents Areas with Estimated Productive Area	6
Figure 4.	Monterey Shelf-to-Basin Stratigraphic Cross-Section	7
Figure 5.	Type Log from Sohio HV 1-34 Well (Source: Trio)	8
Figure 6.	Stratigraphic Cross-Section NW-SE Across South Salinas Project Area	9
Figure 7.	Summarized Well Log from Sohio BM 1-2	10
Figure 8.	Top of Monterey Blue Zone w/ Estimated Productive Area (Source: Trio)	11
Figure 9.	Top of Monterey Yellow Zone w/ Estimated Productive Areas (Source: Trio)	12
Figure 10.	Top of Vaqueros Sand w/ Estimated Productive Areas (Source: Trio)	13
Figure 11.	Significant Oil Tests in South Salinas (Source: Modified from Venoco)	15
Figure 12.	N-S X-Section Showing BM 1-2 & 1-2-RD1 Placement in Monterey	18
Figure 13.	Bradley Minerals (BM) 2-2 Completion Summary (Source: Trio)	19
Figure 14.	Trio NW-SE Cross Section Showing Completed Intervals in HV 1-35 (RD)	20
Figure 15.	HV-3A Initial, Subsequent & Planned Perforations (Source: Trio)	22
Figure 16.	Summary of Tests by Target Interval (Source: Venoco)	24
Figure 17.	West Cat Canyon & Orcutt Fields (From CA Summary of Operations, Vol.40, 1954)	26
Figure 18.	Analogous Structural Setting of West Cat Canyon to Presidents Area	27
Figure 19.	North-South Cross-Section through North Part of West Cat Canyon (Source: CA Summary of Operations, Vol.40, 1954)	28
Figure 20.	West Cat Canyon, Monterey Fm (Los Flores Pool) Development on 10-acre Spacing (From: CA Summary of Operations, Vol.40, 1954)	29
Figure 21.	NuTech Log Analysis Over Tested Sandholdt/Blue in BM 2-2	32
Figure 22.	NuTech Log Analysis Over Tested Blue Intervals in BM 2-2	33
Figure 23.	Permeability, Net Thickness & Porosity Distributions for Monterey Blue Probabilistic Model	34
Figure 24.	Oil Forecasts & Parameters for P90-P50-P10 Yellow Model	39
Figure 25.	Oil Forecasts & Parameters for P90-P50-P10 Monterey Blue Model	40
Figure 26.	Oil, Water & GOR Forecasts for Monterey Yellow Well	41
Figure 27.	Oil, Water & GOR Forecasts for Monterey Blue Well	42
Figure 28.	Vaqueros P10 Model & Input for Multi-Well Numerical Model	43
Figure 29.	Vaqueros Sand P10 Oil, Water, GOR Forecasts	44
Figure 30.	Phase 1 & Phase 2 Well Locations	47
Figure 31.	Well Naming Convention & Location on 10 Acre Grid	48
Figure 32.	Production Forecasts of PROBABLE  & PROB+POSS (3P) Reserves	54

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1 Location and Geologic Setting

The South Salinas Project is located in the Salinas Basin (geologic basin) in Monterey County, California (FIGURE 1, FIGURE 2, FIGURE 3). There is a deep depocenter in the basin in the Project Area as shown in FIGURE 1. The top of Granitic basement in the depocenter is as deep as approximately -13,000’ tvdss, whereas top of basement is at approximately -2,000’ tvdss four miles to the north at giant San Ardo Field in T24S-R10E that to-date has produced a cumulative approximate 500 million barrels of oil. Oilfields in the basin are shown in FIGURE 1.

Major faults in the Project Area include the Rinconada Fault System and the King City (or Los Lobos) Fault. (FIGURE 1). There are many subsidiary faults, some of which can be quite significant, in the Project Area. These faults are generally considered to be right-lateral strike-slip faults and are associated with both transpressional and transtensional deformation.

Trio owns a modern, 30 square-mile 3D seismic survey in South Salinas (FIGURE 2) and has license to an extensive grid of 2D seismic lines. Trio has mineral leases covering approximately 8,600 acres at the Project. Approximately 90 percent of the surface lands at the Project are owned by the Porter Ranch, which fully supports the Project. FIGURE 3 shows the composite estimated productive area of the target reservoirs in South Salinas.

Figure 1. Regional Setting of South Salinas Project (Source: Trio)

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Figure 2. Subregional Location Map of South Salinas (Source: Trio)

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Figure 3. Humpback and Presidents Areas with Estimated Productive Area

The schematic cross-section in FIGURE 4, the type-log in FIGURE 5, and the stratigraphic cross-section in FIGURE 6 provide an overview of stratigraphy in the Project Area. Major stratigraphic units above granitic basement include, from the base upwards, the Miocene Vaqueros Sand, Miocene Monterey Formation, Miocene Santa Margarita Sand, and the Pliocene-Pleistocene Pancho Rico Shale, Pancho Rico Sand and Paso Robles Formation. The Vaqueros Sand is up to about 500’ thick in the Project Area. It is laterally extensive along depositional strike along the long axis of the Salinas Basin, and onlaps basement and pinches-out along the north margin of the Project Area. The Vaqueros Sand is generally considered to be shallow-marine coastal in depositional origin. The overlying Sandholdt Member, which is the basal most stratal unit of the marine Monterey Formation, appears to represent a basin-opening (i.e., deepening) event and records transition from shallow-marine coastal deposition (e.g., Vaqueros Sand) to deep sea deposition (e.g., the Blue Zone) for the remainder of the overlying Monterey Formation. There are four well-developed, major oil-bearing ‘cherty’ zones in the Monterey Formation in the Project Area that are designated, from the base upwards, as the Blue, Green, Brown, and Yellow zones. For the purposes of reservoir unit designation in this report, the Yellow and Brown zones are combined and referred to as the Yellow Zone. Similarly, the Green and Blue zones are combined and referred to as the Blue Zone. Although varying across the Project area, the Yellow and Brown zones combined are roughly 900-1200 feet thick and the Green and Blue zones combined roughly 1100-1400 feet thick. The intervening (stratigraphically between the Brown and Green zones) Mid-Monterey Clay is approximately 2500-3000 feet thick.

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Figure 4. Monterey Shelf-to-Basin Stratigraphic Cross-Section

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Figure 5. Type Log from Sohio HV 1-34 Well (Source: Trio)

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Figure 6. Stratigraphic Cross-Section NW-SE Across South Salinas Project Area

FIGURE 7 is a ‘Summarized Well Log’ constructed by Sohio Petroleum for the Bradley Minerals 1-2, which was drilled in 1984 to the Vaqueros Sand. The Monterey interval from 2298 feet (1650 TVD) to the top of the Vaqueros Sand at 10,440 (9742 TVD) has a total thickness of 8142 feet (8092 feet vertical thickness). TD appears to still be in the Vaqueros Sand at 10,895 ft, so the Vaqueros Sand is at least 450 feet thick. Sohio described the Monterey as being dominated by siliceous lithologies including porcelanite, chert and siliceous shales. The interval from 3400 ft to 4000 ft is considered transition zone from porcelanite (opal-CT dominant) to chert (quartz being the dominant silica phase). Sohio’s ‘Supplementary Data Log’ refers to intervals described as porcelanite, shale, mudstone, limestone and dolostone to about 3900 feet, whereas intervals below are described as glassy chert, claystone, shale, siliceous claystone and dolostone. Below about 6000 feet these rock types persist but brown shale and siltstone are frequently described, and below about 7800 feet shale, sandstone, argillaceous chert (dark brown to red brown), siltstone and dolostone dominate the descriptions. The Vaqueros Sand is described as white to gray sandstones with some interbedded gray-brown shales. The sandstone is fine to coarse and moderately calcareous with angular to subangular, poorly sorted grains. Sohio acquired nine sidewall core samples from 10,310 ft to 10,800 feet and indicate porosities of 8.4 to 17.7 percent.

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Figure 7.Summarized Well Log from Sohio BM 1-2

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FIGURE 8 is a structure map on top of the Monterey Blue Zone, showing the interval plunging east-to-west into the depocenter. Also indicated on FIGURE 8 is Trio’s interpretation of the productive area of the Monterey Blue Zone based on the results of drilling and completion activities of the control wells described below.

Figure 8. Top of Monterey Blue Zone w/ Estimated Productive Area (Source: Trio)

FIGURE 9 is a structure map on top of the Monterey Yellow Zone in the Presidents area showing a major northwest-plunging, faulted anticlinal-nose, and two down-plunge four-way closed anticlines (it should be noted that the Yellow Zone structure map has since been expanded to the south, beyond the extent of the 3D seismic data, to include interpretations at the Texaco 1-15 and 2-15 wells). Also indicated in FIGURE 9 is Trio’s interpretation of the productive area of the Monterey Yellow Zone based on the results of drilling and completion activities of the control wells described below.

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Figure 9. Top of Monterey Yellow Zone w/ Estimated Productive Areas (Source: Trio)

FIGURE 10 is a structure map on top of the Vaqueros Sand, showing the interval plunging east-to-west into the depocenter, and also showing numerous faults that may compartmentalize oil/gas accumulations that may occur within the Vaqueros Sand (it should be noted that the Vaqueros Sand structure map has since been expanded to the south, beyond the extent of the 3D seismic data, to include interpretations at the Texaco 1-15 and 2-15 wells). Many of the faults that are observed in 3D seismic data at top of Vaqueros Sand die-out upward within the Blue Zone and are not evident at top of Blue Zone.

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Figure 10. Top of Vaqueros Sand w/ Estimated Productive Areas (Source: Trio)

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2 Development History

Twelve (12) wells are of particular significance to the Project. These ‘key’ or ‘control’ wells include the following:

HV 1-15

HV 2-15

HV 1-34

BM 1-2

BM 1-2-RD1

BM 2-2

BM 201

HV 1-35

HV 1-35-RD1

BM 2-6

HV 3-6

HV-3A

HV-1

The Trio HV-3A, the discovery-well at Presidents Field, was drilled through the Yellow Zone to the base of the Brown Zone. The Sohio HV 1-34 and the Venoco HV 2-6 reached granitic basement. Six key-wells reached the Vaqueros Sand, the HV 1-34, HV 2-6, BM 1-2, BM 2-2, HV 1-15 and HV 2-15, the latter two demonstrating the downdip presence of oil-bearing Blue Zone and Sandholdt at the southwestern boundary of the Project. The remaining four key-wells, the BM 1-2-RD1, HV 3-6, HV 1-35 and HV 1-35 RD, reached either the Blue Zone or Sandholdt member of the Monterey Formation.

The key wells demonstrating that the Monterey Blue Zone interval can produce commercial quantities of oil are the BM 1-2 and BM 2-2 (FIGURE 11). The initial completion testing in these two wells indicates that an effective completion would likely produce consistent with the P50 Blue model described below, which exhibits a stabilized initial production of about 100 BOPD and produces 416,000 STB oil. The Texaco 1-15 and 2-15 drilled downdip and outside the leasehold to the southwest also indicate the Blue interval is commercially productive over the larger Project Area. The key well for the Yellow interval is the HV-3A, which demonstrated that stabilized production of 10-30 BOPD can be achieved from a suboptimal completion. The remaining control wells have some encouraging tests of the Blue and Green cherts but were not completed so as to demonstrate commercial productivity. However, they do indicate that the Monterey Blue and to a lesser extent the Monterey Yellow are oil bearing over the Project Area and support the productive areas mapped by Trio.

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Figure 11. Significant Oil Tests in South Salinas (Source: Modified from Venoco)

Following is a brief chronological overview and summary of testing and production of the control wells that have been drilled in South Salinas.

2.1 Texaco HV 1-15

The HV 1-15 was drilled in November 1981 and reached TD in the Vaqueros Sand. A completion test of the Sandholdt (OA perfs 10,970-11,230 ft) after acidizing 3/21/1982 flowed oil into a test separator with a flowing tubing pressure of 80-300 psi. The well flowed 407 barrels of oil with 102 barrels of water in a 24-hour period (3/24/1982). In five subsequent days of testing the well flowed 292 BOPD/73 BWPD, declining to 166 BOPD/34 BWPD when shut-in for a BHP survey. The reported oil gravity was 38 degrees API. During the next two months the Sandholdt was re-perforated and re-acidized, resulting in less oil and more water. Several additional Sandholdt and Blue Chert intervals were perforated, acidized, and tested over the ensuing two months. The flow/swab test results produced oil at about 20-100 BOPD with water cuts of 90%+. It is believed that the HV 1-15 completion became compromised because of a leak at the liner hanger that could not be repaired. Total reported oil production was 2865 bbls when the well was P&A’d January 1984.

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2.2 Texaco HV 2-15

The HV 2-15 was spud 1/5/1983 and experienced a significant amount of hole problems requiring extensive remediation including fishing and casing repair until completion activities began in mid-May. The Sandholdt was perforated at 11,520 to 11,596 and after squeezing split casing and fishing, was acidized. Over 10 days it produced at flow/swab daily rates of about 200-400 BFPD with 75-90 percent water cuts. Perforations were added at 10,820-11,020 and following acidizing tested at swab/flow rates of 150-500 BFPD, 30-90 percent water cuts. The Blue Chert was perforated 10,588-10,788 and frac’d, and after 5 days of flowback was producing at 62 BFPD, 50-75 percent water cut with 0-50 psi FTP. The same interval was reperforated and acidized and put on pump at an IP rate of 79 BOPD, 28 BWPD. Over the next 26 days the rate declined to 13 BOPD, 2 BWPD (reported gas rates indicated GORs of about 1000 SCF/STB). The Blue Chert at 10,165-10,485 was perforated and put on pump without stimulation. During a 12-day test it produced at 5-44 BOPD with water cuts of 26-72 percent; the final day of the test was 17 BOPD, 43 BWPD. The Upper Monterey was perforated at 8036-8300 (10/28/1983) and was put on pump (unstimulated) for a 30-day test. The well began producing at 50 BOPD with a 75% water cut and on the last day of test was producing 328 BWPD with no oil. Total reported oil production was 1369 bbls when the well was P&A’d January 1984.

2.3 Sohio HV 1-34

The HV 1-34 was drilled in April 1985. After losing a bit in the hole the well was sidetracked at 8317 ft and TD’d in Basement at 10,500 ft. Seven DSTs were conducted, with small amounts of oil recovered from the Green Chert, Blue Chert and Sandholdt. DST #3 recovered 2-1/2 barrels of 33-degree API oil and 11 barrels of gas cut oily water from the Green Chert. This was significant given that the test was conducted with 6350 ft of water cushion (nearly 2900 psi of back pressure). High oil shows and notes of free oil on the shakers were noted in a Blue Chert interval that was not DST’d.

2.4 Sohio BM 1-2

The BM 1-2 spud 7/26/1984 and reached TD in September 1984 in the Vaqueros Sand at 10,895 ft. Cased hole DSTs were conducted in the following intervals:

Ø	Perf: 10,322-10,362’ (Sandholdt), 10/19/1984, GTS at 38 Mcfd, reverse out 29 BO, 42° API, 14 bbls mud after ~1 day; Set packer at 10,288’.
Ø	Perf: 10,050-10,150’ (Sandholdt), 10/24/1984, GTS at 150 Mcfd declining to 50 Mcfd; reverse out 16 BO, 40° API after ~1 day; Set retainer at 10,000 ft.
Ø	Perf: 9,630-9,690’ (Blue Chert) with 2800 psi N2 cushion 10/27/1984, SI and fluid rises to 100 ft., recover 30-degree API oil – volume not reported after ~ 1 day. Set retainer at 9590 ft.
Ø	Perf: 9,410-9,490’ (Blue Chert) 10/30/1984; SI, open for 1 hour then SI for PBU. Recover small amount of 26-29° API oil in ~1 day. Set retainer at 9402 ft.
Ø	Perf: 9,270-9,360’ (Blue Chert) under 2700 psig N2 cushion 11/3/1984; reverse out 27 BO, 31° API, 0 BW in ~1 day; breakdown formation at 2500 psig with KCl water across perfs & circulate 48 barrels 7% HCL; displace with KCl and N2. Bleed off well and flow-back; on 3rd day of N2 lift, recover at ~ 13 BOPD (28-degree API oil) and 2 BWPD. Acidize with 2900 gal 15% HCl, 6000 gal 7% HCl at average 3 bbls/min at 4500 psig. N2 lift for ~2 days, recover 7 bbls oil, 15% water cut. Set retainer at 9258 ft.

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Ø	Perf: 9,100-9,220’ (Blue Chert) under 2700 psig N2 cushion 11/14/1984; flow to surface 37 BO (34° API) WHP 300 psig on 15/64 in choke, gas rate ~500 SCF/BO; continue flow & recover 121 BO, 2% water cut with FTP 275 psi to 235 psi; SI 1 day and then N2 lift from 7500 feet 2 days at average 127 BOPD, 12-22% water cut; Set packer at 9,070’.
Ø	Perf: 8,920-9,010’ (Blue Chert) 11/22/1984; SI, bleed off N2 cushion and flow 4 hours, SI overnight, recover 0.5 BO, 23° API, 2 bbls load; Retrieve packer at 9,070’ and set retainer at 8,880’.
Ø	Perf: 8,290-8,390’ in 9-5/8” casing (Hames Sand, Green Chert) 11/26/1984 (7” liner lap at 8408 ft); SI & bleed off N2 cushion (likely ~ 4 hours) & SI overnight for 2nd PBU; recover 1.7 BO, 22° API, 0.6 bbls load; Squeeze cement behind tie-back and into open perfs; Drill out cement and retainer at 8,880’.
Ø	Continued activities include testing, encountering obstructions, fishing; OA perfs open 8920-9220, which tested at 3-4 bbls/hr oil with 5% water cut 12/20-27/1984. Acidized 12/28/1984 with little subsequent testing until operations suspended 1/23/1985.
Ø	Preparing to put on pump 3/8/1986; reported SITP 840 psi when opened well to flow and recovered 94 bbls oil w/no water in 6 hours. Encountered 3 weeks of fishing, milling, etc. Perf 9100-9220 and frac; recover 156 BO and 842 BW w/ 238 BWLTR.
Ø	POP 4/12/1986 and produce at ~ 30-70 BOPD for 4 weeks, 40-60% water cut.
Ø	The well’s Final Report was 5/15/1986 and noted ‘Completed Oil Producer’. According to monthly DOGR production records, production in May was 608 BO/1139 BW, and in July was 374 BO/319 BW. The well was P&A’d October 9, 1986.

2.5 Trio BM 1-2-RD1

Trio re-entered the BM 1-2 in October 2004, milling a window in the original hole in the 9-5/8” casing from 7,860-7,894’. It then drilled an 8-1/2” hole to 11,198’ at a bottom-hole location approximately 2230 ft southeast of the original BM 1-2. It was completed with a horizontal lateral having a total of 1,864’ of 5-1/2” slotted production liner at 9,147-10,283’ MD (1,136’ of slotted liner) and 10,467-11,195’ MD (728’ of slotted liner) (FIGURE 12). Venoco summarized the BM 1-2 RD as exhibiting strong oil and gas shows on the mudlog and noted that the drilling azimuth was not optimal for encountering fractures. It characterized the completion as problematic because Trio was unable to clean out the liner, and the pumps were routinely plugging with grey water and mud. The BM 1-2 RD was produced for about nine months at about 5-20 BOPD with a water cut of about 95 percent. The well was idled in December 2005 after producing 955 barrels of oil.

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Figure 12.N-S X-Section Showing BM 1-2 & 1-2-RD1 Placement in Monterey

2.6 Venoco BM 2-2

The BM 2-2 was drilled in September 2007 to a TD in the Vaqueros Sand at 10,434 feet MD (9292 ft TVD). The bottomhole location is approximately 4,500’ northeast of the surface location. The following intervals were completed and tested (FIGURE 13):

Ø	Perf: 10,110-10,150’, 10,157-10,230’ (Sandholdt) 1/2/2008; Swab 46 BO, 23 BW/ 7 days.
Ø	Perf: 9,960-10,090’ (Sandholdt) 1/14/2008; Swab: 44 BO, 25 BW in 3 days.
Ø	Perf: 10,090-10,110’ (Sandholdt) 1/29/2008; Swab: 37 BO (43-degree API), 29 BW in 2 days.
Ø	Acidized 9,960-10,230’, 2/5/2008 with 3,000 gals 7.5% HCl; Flow/Swab: 240 BO, 66 BW in 8 days; rod pump 487 BO, 193 BW in 8 days and pumped off. Set Composite BP at 9,800’, 5/14/2008.
Ø	Perf: 9,210-9,260’ (Blue Chert) 5/16/2008; Swab: 188 BO, 12 BW in 4 days; shut-in 3 days, then Swab/Flow: 94 BO, 6 BW in 2 days; produced 1810 BO, 175 BW on rod pump in 26 days (IP 200 BOPD, rate at 30 days was 55 BOPD, 31-degree API oil).
Ø	Found Bridge Plug at 10,051’ and set Cast Iron BP at 9,800’, 6/26/2008
Ø	Frac 9,210-9,260’, 6/28/2008 w/ 3,650 bbls 35# Hybor, 4% KCl; resulted in 185,000 lbs 40/70 sand in zone & ~15,000 lbs left in wellbore; 5-1/2” casing failure at 1,700’ during frac; bleed off 98 BO/1 day; Patch to repair casing (13 days), then rod pump 1,251 BO, 1,908 BW in 23 days (approx. 1742 BWLTR).
Ø	Perf: 9,260-9,330’, 9,365-9,425’ (Blue Chert) 12/18/2008; Swab: 12 BW in 2 days, then rod pump 618 BO, 1,548 BW in 28 days.

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Trio re-entered the BM 2-2 in March 2016, pulled the rods, pump and tubing and ran in with a sand pump (tubing bailer) to 10,315 and come out hole. Run in hole with tubing, rods and pump and test for two days at ~100 BFPD, 99.9 percent water, with solids running 6-10 percent (fine powder gray in color; continue testing for about two weeks and then shut-in due to high water cut and water disposal costs. Trio intends to re-enter, adding perforations to test the Vaqueros Sand before recompleting the Monterey Blue Zone.

Figure 13. Bradley Minerals (BM) 2-2 Completion Summary (Source: Trio)

2.7 Seneca BM 201

The BM 201 was drilled in November 1989 and TD’d in the Vaqueros Sand at 9860 feet MD (9168 feet TVD). Completion attempts in the Blue Chert/Sandholdt were inconclusive due to poor cement bond and unsuccessful attempt to cement squeeze. The Green Chert yielded a small amount of oil with a 99 percent water cut. The well has been P&A’d.

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2.8 Veneco HV 1-35

The HV 1-35 was spud 12/20/2010. The bottomhole location at 10,050 ft MD (8686 ft TVD) in the Sandholdt is approximately 3,450’ southwest of the surface location. Venoco summarized the results as 1) Blue Chert is a primary target in this area, 2) moderate fracture density is indicated on the FMI, 3) fractures correlating to oil shows present on the mud log, 4) NuTech’s log analysis indicated oil saturations of 50%. The completion history is complicated by unclear reporting. There is 9-5/8” casing at 5216, 7” at 4732 to 9057, and 4-1/2” at 8812-11366. Completion activities began 2/22/2011. Perforating history is not clear in daily reports, but numerous tool problems and fishing activities are noted. On 4/5/2011 coiled tubing perforating hole cuts were alternated with fracs 10180-11200 overall (?). Daily testing on pump circa 4/30-5/15/2011 exhibited rates of 5-20 BOPD, 40-70 BWPD, GOR~800, 28 deg API. On 5/30/2011, performed 3-stage foamed low pressure acid job; reported perfs 9060-9110, 9550-9650, 9,775—10,100. Put on pump 6/6/2011 and, following cleanup, producing 37 BOPD, 200 BWPD (6/11/2011) declining to 5-10 BOPD, 47 BWPD (6/23/2011). Shut-in July 2011 after producing 771 BO. The well was plugged-back and sidetracked as the HV 1-35-RD1 (HV 1-35 called HV 1-35-Pilot in FIGURE 14).

2.9 Venoco HV 1-35-RD1

This well was directionally drilled to a bottomhole location approximately 5,000’ southwest of the surface location. TD was in the Blue Zone at 11,371’ MD. It was perforated, acidized and/or frac’d in several Blue Zone intervals over 9,060 to 11,200 feet (FIGURE 14). A three-week test on pump of the interval 10,360-11,200 exhibited an initial rate of 30 BOPD which declined to about 5 BOPD, 35 BWPD. A two-week test on pump of the interval 9,060-10,100 exhibited an initial rate of 65 BOPD, which declined to about 10 BOPD, 50 BWPD. Total reported production has been 513 BO. The well is currently idle.

Figure 14. Trio NW-SE Cross Section Showing Completed Intervals in HV 1-35 (RD)

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2.10 Venoco BM 2-6

The BM 2-6 was drilled in January 2010 to Basement at 6,774 feet MD (6768 ft TVD). The completion tests can be summarized as follows:

Ø	Perf: 5,574-5,725’ (Green Chert) 3/3/2010, Swab 15 BW, very little inflow in 1 day (injection test of 0.5 bpm at 1350 psi).
Ø	Perf: 5,393-5,479’ (Green Chert) 3/6/2010; Swab 21 BW with very little inflow in two 2 days; acidize 3/12/2010 with 8,600 gals 17% HCl, 8,600 gals 12/3 HCl/HF; Flow/Swab: 911 bbls in 4 days; Pump 199 BO, 2,842 BW in 9 days, 17° API oil; Set cement plug across open perfs.
Ø	Perf: 4,872-4,890’ (Purple Chert), 4/10/2010; Swab 1 BO, 5 BW, little inflow in 1 day.
Ø	Perf: 4,851-4,872’, 4,890-4,911’ (Purple Chert), 4/13/2010; Swab: Small amount of oil in 2 days, 12° API oil; acidize 4,851-4,911’ (4/16/2010) with 6,000 gallons 17% HCl; Swab 95-98% water over two days; rod pump 64 BO, 188 BW in 8 days, 8° API oil, pumped off, set composite BP at 4,800’ 5/5/2010
Ø	Perf: 3,212-3,228’, 3,278-3,294’, 3,588-3,600’, 3,684-3,710’ (Yellow/Brown), 5/6/2010, pump 64 BW in 2 days, Pumped off.
Ø	The well was temporarily abandoned.

2.11 Venoco HV 3-6

The HV 3-6 was drilled in March 2011 as a deviated well that ended up with lateral sections through the Blue Zone and Vaqueros Sand of about 1800 feet and 1200 feet, respectively. The well TD’d in the Vaqueros Sand at a measured depth of 12,165 feet (8,586 feet TVD). The bottomhole location is nearly 6500 feet west of the surface location. The well was completed with 5-1/2-inch liner that was pre-perforated (every other joint) from 8926 to 12,158 feet. Tests of the Blue Chert and Sandholdt produced only water. Venoco’s post-mortem noted that it was unable to run swell packers for annular isolation, and it was unable to clean mud out of the liner with foam or N2 and coiled tubing. Operations were suspended.

2.12 Trio HV-3A

The HV-3A was spud 11-28-2018 and reached TD in the upper part of the Mid-Monterey Clay on 12-7-2018 at a measured depth of 5720 feet (5174 feet TVD) at a bottomhole location 1966 feet north of the surface location. Openhole logs were not run due to cost constraints. Trio ran 7-inch casing with slotted liner from 4450-4950 feet and 4996-5126 feet with a swell packer in between the slotted liner sections. During cementing operations, the DV tool sheared, and cement ended up behind the slotted liner. Swabbing operations in December 2018 yielded about 100 BFPD with one (1) percent oil cut. Completion operations resumed in April 2019 when perforations were added at 4550-4800 after which 14 bbls oil (22 degrees API) and 56 bbls water were swabbed in two days. After setting a bridge plug at 4350 feet, additional perforations were added at 3750-3875 feet and 4090-4215 feet Trio swabbed 35 bbls fluid with 75 percent water cut. The well was put on pump in early May 2019 producing about 40 BOPD, 90 BWPD which gradually declined to about 10 BOPD, 90 BWPD after 3 weeks of production. The well was then shut-in because of water disposal (trucking) costs. FIGURE 15 illustrates the completed and targeted intervals in HV-3A. The Company recently determined that existing permits allow production testing to continue at the HV-3A well at Presidents Field and, consequently, testing operations have been restarted. A pumping unit, tanks and other equipment were moved to the HV-3A site during the second week of March, 2024, and the restart of production at the HV-3A well occurred on March 22, 2024. The well was then produced for a relatively short period time with generally favorable oil-water ratio and then shutin, pending the addition of perforations and acidizing for borehole cleanup in the third quarter of 2024. Trio intends to resume operations and add up to 625 feet of perforations over the interval of about 3540-4560 with the thesis that the high resistivity intervals should be targeted for completion.

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Figure 15. HV-3A Initial, Subsequent & Planned Perforations (Source: Trio)

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2.13 Trio HV-1

The HV-1 spud May 5, 2023, and was completed at its total depth (“TD”) of about 6,641 feet (measured depth) on May 15, 2023. It is located about two miles northwest of the HV-3A discovery well and for this reason it is considered a “confirmation well” intended to help confirm the lateral extent of the field. The well was directionally drilled approximately 2,600 feet toward the southeast. The Yellow Zone, Brown Zone and Mid-Monterey Clay (MMC) were encountered in the HV-1 well largely as predicted including with respect to depth, thickness, lithology, wireline-log characteristics and oil and gas shows including free oil in cuttings and in the mud pit. Of particular interest was a swab test of the Mid-Monterey Clay Zone, which has not previously been assigned any value to the South Salinas asset. During nine days of swab testing the MMC exhibited fluid recovery as high as 500 barrels of fluid per day with a 25 percent oil cut (125 BOPD). Fluid recovery rates and oil cuts decreased over the nine-day test period, but they provide evidence that the MMC may additionally contribute oil and reserves at up structure locations. Perforations were added to Brown and Yellow interval and oil and gas were recovered from swab testing albeit associated with high water cuts. As a result of the HV-1 production tests, the Yellow Zone limiting lines of commercial productivity were contracted with the placement of the oil-water-contact at about the base of the Brown Zone in the HV-3A, which is approximately coincident with a synclinal saddle between the HV-3A and HV-1. As of the effective date of this report, Trio considers it premature to deem HV-1 either a dry development well or a net productive well. Additional operations, including possibly deepening or sidetracking, and additional testing, are feasible at HV-1.

Venoco summarized the tests that have been conducted in the target intervals of South Salinas (FIGURE 16). Two corrections should be noted to FIGURE 16. First, Trio’s interpretation of the Vaqueros Sand top in the BM 2-2 places it below the interval referred to by Venoco as Vaqueros Sand, so the test was actually in the Sandholdt. Secondly, the HV-3A and HV-1 are not included because they were drilled after the date of this Venoco presentation.

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Figure 16. Summary of Tests by Target Interval (Source: Venoco)

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3 Reserves Assessment

Because production histories of wells drilled in South Salinas are limited to short periods of testing or production, analogs and probabilistic methods were used to estimate reserves for the development of South Salinas. The analog fields that produce from the Monterey are very similar to South Salinas in depth, geology, reservoir characteristics, and oil properties. And in the case of the primary analog the structural setting is particularly analogous. The analog fields were developed largely in the time frame 1935 to 1955, and production was minimal after 1977, the date after which digital production is available from the California Division of Oil and Gas. Securing the hard copy monthly production records and breaking out the individual well performance from the lease reports was not within the scope and timing of this report. However, there are credible production records from California Summary of Operations literature that provide cumulative oil production from Monterey wells along with oil rates and number of producing wells at a date certain which allow estimates of ultimate recovery.

The completion histories for several of the wells drilled in South Salinas demonstrate commercial oil productivity over significant portions of the Monterey, but these histories also record problems with poor cement jobs, liner hanger leaks, and downhole mechanical failures that have hindered operators in establishing sustained production. There is also evidence, not recorded in the well histories, that cyclical drops in oil prices or inadequate capitalization influenced operator decisions to not complete necessary remediation work and establish the requisite facilities for long term production. So, while decline curve and even type well analysis could not be adequately used for this reserve assessment, there is sufficient information available from open hole log analysis, core and completion tests that allow key parameter distributions to be developed. These distributions can be used in numerical models to calculate probabilistic forecasts of production and derive estimates of ultimate recovery. This will be described in some detail in the Discussion below.

3.1 Analog Fields

Analogs are widely used in reserves estimating, particularly in the early development stages when direct measurement information (production history) is limited. As described in the Society of Petroleum Engineers’ Petroleum Resource Management System (PRMS Section 4.1.1) “The methodology assumes that the analogous reservoir is comparable to the subject reservoir regarding reservoir description, fluid properties, and most likely recovery mechanism(s) applied to the project that control the ultimate recovery of petroleum. By selecting appropriate analogs, where performance data of comparable development plans are available, a similar production profile may be forecast. Analogs are frequently applied in aiding in the assessment of economic producibility, production decline characteristics, drainage area, and recovery factor.”

While the Monterey shale intervals present in South Salinas produce from many fields in the California Basins (FIGURE 17), two fields were identified by Trio as being particularly analogous to the project area, the West Cat Canyon Field, and the Orcutt Field, located about 100 miles southeast of South Salinas in the Santa Maria Basin. Both fields produced from the Monterey Formation having similar depth, thickness, oil gravity and reservoir character. West Cat Canyon in particular exhibits similar structural fold and form to the South Salinas Presidents area (FIGURE 18). Both West Cat Canyon and Presidents have a NW-SE orientation, structural apex to the southeast, and downdip four-way closure to the northwest.

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Figure 17.West Cat Canyon & Orcutt Fields (From CA Summary of Operations, Vol.40, 1954)

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Figure 18.Analogous Structural Setting of West Cat Canyon to Presidents Area

The discovery and development of West Cat Canyon is documented in a 1954 article published in the California Division of Oil Gas Summary of Operations, Volume 40, July-December 1954, No. 2. The West Cat Canyon field was discovered in 1908, producing oil from Pliocene (Sisquoc) sands at about 3200 feet. The Monterey Formation was discovered in 1918 with a well drilled to a depth of 4905 feet. It was completed and produced its first month at 80 BOPD, 26 degrees API, with 4 BWPD. The well only produced for one year and was then abandoned as uneconomic in January 1920. It was not until 1938 that development was resumed following the discovery of a deeper Monterey pool at about 5500 to 6500 feet, which produced from one of the earliest development wells at 716 BOPD of 14.9-degree API gravity oil and a one percent water cut for its first 16 days of production.

This analogous Monterey Formation was designated the ‘Los Flores’ pool at West Cat Canyon and consists of fractured Monterey cherty shale and chert having significant sandy intervals over an interval thickness of about 1500-1800 feet (FIGURE 19). It is productive throughout the area with oil ranging from 11 to 26 degrees API. Most of the is oil believed to have been produced from the intensely fractured chert in the lower part of zone, known as the “heavy chert” or “buff and brown”, a description commonly used by Texaco, Sohio and Venoco to describe the Monterey Blue (including Sandholdt) section in South Salinas.

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Figure 19. North-South Cross-Section through North Part of West Cat Canyon (Source: CA Summary of Operations, Vol.40, 1954)

At the end of 1953, 168 wells averaging 6000 feet in depth were producing from the Los Flores (Monterey) Pool at an average daily rate of 77 BOPD, with a 51 percent water cut and a GOR of 564 SCF/STB. The cumulative production from the Monterey pool was 40,128,000 barrels of oil and 8,416,000 Mcf of gas. (The total field cumulative oil production including the shallower zones was 65,811,000 STB.) This represents an average cumulative production of 238,900 STB per Monterey well on what appears to be 10-acre spacing (FIGURE 20). If it is assumed that the average well continued to produce with an annual decline of 20%, it would produce an additional 130,000 STB giving a total estimated ultimate recovery (EUR) of about 370,000 STB of oil. If it is further assumed that development occurred on 40-acre spacing rather than 10-acre spacing, an average well might produce as much as 1,480 MSTB. As a ‘sense check’, this EUR supports the Monterey Yellow and Blue model probabilistic P10 reserves of 1,173 MSTB and 1,259 MSTB, respectively, and which assume development on 40-acre spacing.

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Figure 20.West Cat Canyon, Monterey Fm (Los Flores Pool) Development on 10-acre Spacing (From: CA Summary of Operations, Vol.40, 1954)

Since most of the West Cat Canyon production occurred prior to 1977, the California Division of Oil and Gas does not have monthly production by well available in digital format. And while hard copy records of monthly production can be downloaded from the CA DOGR, the time required to digitize this information and perform a more detailed type-well analysis was outside the scope of this report. KLSP had discussions with investigators who have worked with digital production from pre-1977 and they indicated that in some areas there can be significant differences in production from well-to-well, and this is attributed to faulting and natural fracturing in the Monterey. Also, the drive mechanism appears to be predominately solution gas drive with possibly some gravity segregation. Gravity segregation would allow gas that is released below the bubble point but not produced at the wellbore to migrate up structure, creating secondary gas cap-like pressure support and facilitating the concurrent down dip flow of oil. The pre-1977 production also reportedly shows water cuts that can vary well-to-well and may or may not increase with time. So, it does not appear that there is a significant water drive, but rather that faulting and natural fracturing may facilitate the movement of localized water from an ‘oil-water contact’ downdip.

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The Los Flores 2 81-28 is an example of the type of completion that was common. The well was initially drilled in 1953 to 3995 feet in the Alexander Zone (Sisquoc sands). However, the well was then deepened to 6751 feet into the Los Flores Pool (Monterey) and subsequently completed with an uncemented perforated 7” liner from 5095 to 6530 feet. It was placed on production October 28, 1953, and during the month of December 1953 it averaged 114 BOPD of 14.4-degree API oil, with 93 BWPD (45% water cut). This completion was consistent with that reported in the Summary of Operations article, wherein “an 11-inch hole is drilled through the objective zone and 7-inch combination string is landed on bottom. The 7-inch casing is cemented through ports above the objective zone with sufficient cement to reach above the Sisquoc sands and into the upper Sisquoc shale. After testing for water shut-off, the 7-inch casing is cleaned out and the perforations are washed with salt water.”

The Orcutt Field, just west of West Cat Canyon is also a Monterey analog to South Salinas. Orcutt began producing from the Monterey in 1937 from depths averaging 5,020 feet. Cumulative oil production from the Monterey alone was not found, but Tennyson (Santa Maria Basin 1995 Assessment) reported that the Orcutt Field would produce about 180 MMSTB oil. In the early 1980’s two wells on the north end of the field, about 2000 feet apart, were drilled and completed in the Monterey from an overall depth of about 9200 to 10,000 feet. The wells exhibited initial stabilized production rates of 50-100 BOPD with water cuts of 40-60 percent. Oil rates declined to about 20-30 BOPD within 5-8 years with increasing water cuts. Cumulative oil production from the Union-Getty Rice Ranch 1, when shut-in in 1995, was 126,342 STB. The cumulative water cut and GOR were 56 percent and 1760 SCF/STB, respectively. The Union-Getty Hobbs 23X produced from 1982 to 1986 (when oil prices collapsed), and then resumed production in 2015. Cumulative oil production as of early 2021 is 116,819 STB and cumulative water cuts and GOR are 85 percent and 815 SCF/STB. The performance of these two wells is what may have been expected from several of the South Salinas control wells had they remained on production following completions that were not optimum. When calibrating the Monterey Yellow and Blue probabilistic models, the P90 reserves of 167 MSTB and 134 MSTB, respectively, are consistent with what appears to be the poorer quality wells in West Cat Canyon and Orcutt.

3.2 Average Reservoir and Fluid Properties

For purposes of developing type wells, a structural mid-point was selected for each reservoir unit. For example, the depth of the Monterey Blue reservoir ranges from approximately 6000 feet to 10,000 feet, and for purposes of representing average reservoir properties a depth of 8000 feet was selected to determine appropriate pressure and temperature. For the Monterey Yellow an average depth of 4500 feet was selected, while for the Vaqueros Sand an average depth of 8800 feet was used to represent reservoir pressure and temperature, and to determine reservoir fluid properties. TABLE 1 summarizes the reservoir and fluid properties for each of the reservoirs at the average depths.

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Table 1.Summary of Reservoir & Oil Properties for Targeted Reservoirs

The probabilistic analysis incorporated the physics-based numerical simulation model available in the IHS Harmony Enterprise software. The model input requires an estimate of the range and distribution type for porosity, permeability, net thickness, and water saturation. The range of porosity and water saturations was based on examination of the analyzed logs that are available for five of the control wells, while the permeability ranges were based on core data, production tests in South Salinas wells, and the performance histories of wells in analog fields. The analyzed logs were available in the Venoco well files now in the possession of Trio. Venoco had NuTech process the log suites of several wells using its “NuLook Advanced Petrophysical Evaluation”. While a rigorous examination of the porosity, water saturation and multi-mineral models used in the analysis could not conducted with the limited information available in the NuLook headers, spot-checks of the results against hand calculated values and core data indicated the computerized log analysis was reasonable. Examples of the NuLook analysis results over BM 2-2 Sandholdt and Blue intervals (which were production tested) are shown in FIGURES 21 and 22. The porosity and water saturation tracks are of particular interest and show that much of the Blue Chert interval has effective porosities that vary from about 8 to 14 percent, and water saturations that are consistently in the range of 40 to 50 percent. The Sandholdt has somewhat higher porosities and similar water saturations.

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Figure 21.NuTech Log Analysis Over Tested Sandholdt/Blue in BM 2-2

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Figure 22. NuTech Log Analysis Over Tested Blue Intervals in BM 2-2

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FIGURE 23 shows the log-normal probability distributions used for permeability, porosity, and thickness in the Monterey Blue model. For all models a triangular distribution was used for water saturation with Min, Mode, Max values of 40, 45 and 50 percent, respectively. TABLE 2 provides the ranges and distributions of the parameters whose uncertainty was evaluated in the probabilistic analysis.

Figure 23. Permeability, Net Thickness & Porosity Distributions for Monterey Blue Probabilistic Model

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Table 2. Parameter Ranges & Distributions Used in Probabilistic Modeling

3.3 South Salinas Estimate of Oil & Gas In-Place

It is difficult to calculate reliable values of original-oi-in-place (OOIP) in fractured shale reservoirs such as the Monterey. However, there is sufficient information from logs, core and production tests to determine a range of OOIP that can contribute to oil and gas reserves, and it was appropriate and necessary to determine OOIP for the following reasons:

1.	The various Monterey lithologies can have reasonable porosities. And while there will be some component of ‘fracture’ porosity, it should be relatively small compared to the matrix porosities.
2.	There is evidence from open hole logs and core that significant portions of the Monterey interval have porosities of between about eight (8) and 20 percent.
3.	There has been no sustained oil production from South Salinas that would allow construction of a ‘type well’ for reserves forecasting.
4.	Most of the Monterey production from the West Cat Canyon and Orcutt analog fields occurred prior to the time for which production data was available in digital format, making it difficult to use these analogs for developing a ‘type well’.

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Therefore, it was decided to construct several numerical models that could evaluate the expected oil and gas production under an appropriate range of reservoir characteristics, and which would allow probabilistic estimates of reserves. These models required reservoir properties and, therefore, OOIP as input.

TABLE 3 shows the estimated number of productive acres within the Trio leasehold and the approximate number of well locations that would fully develop the leasehold if the Monterey were developed on 40-acre spacing and the Vaqueros on 160-acre spacing. The total number of wells under a ‘fully developed’ development plan is 156. Of this total number of wells, 139 wells are Monterey Blue or Yellow wells on 40-acre spacing, while 17 wells are Vaqueros Sand horizontal wells with lateral lengths of about 5000. If Trio determines that the development permit can be facilitated with the use of significantly fewer wells, it may be desirable to develop a plan to develop the Monterey with horizontal and multilateral wells.

Table 3. Number of Possible Wells w/ Full Development by Area & Reservoir

OOIP was estimated for the areas mapped as productive and which lie within the Trio leasehold by using the probabilistic values of OOIP that were requisite input for the reservoir models used to determine P90, P50 and P10 reserves. In this manner, corresponding estimates of Low (P90), Most Likely (P50), and High (P10) values of OOIP could be calculated for the Trio leasehold interest. This was done by multiplying the number of wells by the OOIP from the Yellow, Blue and Vaqueros models discussed below. TABLE 4 presents these estimates of OOIP by Project Area and reservoir. As indicated, the total ‘high’ (P10) estimate of OOIP and OGIP for the Trio leasehold interest in South Salinas is 2.178 billion STB of oil, and 1.308 TCF of gas.

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Table 4. Estimated South Salinas OOIP & OGIP within Leasehold

3.4 Probabilistic Modeling of Reserves

The Probabilistic method defines a distribution representing the full range of possible values for input parameters. This includes dependencies between parameters that are also defined and applied. These distributions are randomly sampled using Monte Carlo simulation to compute a full distribution of potential in-place and recoverable quantities of oil, gas, and water. Input distributions for porosity, permeability, water saturation and net productive thickness have been discussed above. In addition, pore volume compressibility was also described with a distribution because its range of uncertainty can impact reservoir pressure and therefore future productivity.

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SP Global’s Harmony Enterprise software was used to construct numerical models for the Monterey Yellow, Monterey Blue and Vaqueros Sand reservoir units. A ‘type well’ or calibration model was constructed for each reservoir using the average conditions and reservoir properties cited above. In addition, using the probabilistic distributions of porosity, net thickness, water saturation, permeability and pore volume compressibility, the reservoir model was run 500 times, each time the model selecting via Monte Carlo sampling the input parameters according to the ranges and distributions defined. Each simulation run results in a particular value of oil and gas recovery. The cumulative probabilities of the resulting forecasts of ultimate oil and gas recovery are used to identify the reserve values representing the P90, P50 and P10 cases. The model construction consisted of:

1.	Selecting the South Salinas well in the Harmony Enterprise database that would be used to model the Monterey Yellow, Blue and Vaqueros Sand reservoirs. A wellbore configuration having an appropriate completion depth for the particular reservoir was constructed.
2.	Fluid properties were established based on oil gravity, solution gas-oil-ratio, reservoir temperature, and initial reservoir pressure. Standing’s correlation was used for PVT correlations, and the Beggs and Robinson correlation was used for viscosity. A generalized Corey relationship was used for relative permeability, and the end points and exponents were tuned to achieve consistency of oil, gas and water rates with South Salinas test results and analogous reservoir production.
3.	A rectangular model size of 40 acres (1320 ft by 1320 ft) was used based on the desire to allow adequate reservoir drainage while minimizing well count.
4.	Forecasts were run for 25 years using producing bottomhole pressures that declined from 1000 psia to 250 psia over the life of the forecast.

FIGURE 24 and FIGURE 25 summarize the P90-P50-P10 model input parameters and results for the Yellow and Blue models, respectively, and show the oil production profile for the probabilistic forecasts. Using the P50 results and inspecting the recovery factors derived from the OOIP and estimated ultimate recovery, the recovery factors for the Yellow and Blue reservoirs are 8.3 and 6.7 percent, respectively. These are reasonable recovery factors for a naturally fractured reservoir having the porosity and permeabilities of the Monterey and undergoing solution gas drive recovery. FIGURE 26 and FIGURE 27 are plots showing oil, water, and gas-oil-ratio (GOR) forecasts for the Yellow and Blue models, respectively, with their P90-P50-P10 cases. The initial stabilized oil rates for the P50 cases are approximately 100 BOPD for the Yellow and Blue reservoirs, which decline very gradually to about 30 BOPD at the end of the 25-year forecast period. GOR’s remain at initial GOR for about five years before they begin to increase, reflecting the undersaturated nature of the crude oil and the modest oil rates associated with relatively large values of OOIP (resulting in small rates of pressure depletion).

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Figure 24. Oil Forecasts & Parameters for P90-P50-P10 Yellow Model

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Figure 25. Oil Forecasts & Parameters for P90-P50-P10 Monterey Blue Model

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Figure 26. Oil, Water & GOR Forecasts for Monterey Yellow Well

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Figure 27. Oil, Water & GOR Forecasts for Monterey Blue Well

The P10 forecast of reserves for the Vaqueros Sand was performed differently since the Vaqueros Sand has only P10 reserves and is developed with horizontal wells. The Monterey reservoirs are developed using vertical wells because of the long vertical sections that will be completed. Furthermore, it appears reasonable that laterally continuous, oil-saturated porosity development having matrix permeability that is supplemented with natural fractures can be adequately drained with 40-acre spacing. However, for the Vaqueros Sand one of the questions regarding drainage with horizontal wells is the placement of a lateral wellbore within the Vaqueros Sand to adequately drain the overall net thickness, given the likelihood of very low permeability sand layers impairing vertical movement of oil. To evaluate the impact this could have on oil recovery, a multi-well model using the P10 values of permeability, porosity, and water saturation, was constructed to evaluate lateral and vertical drainage. The P10 input parameters are shown in FIGURE 28 (as are the P90 and P50 values, which were not used). In the horizontal multi-well model three layers were used to describe the Vaqueros Sand (Upper, Middle, Lower) each having 80 or 100 feet of thickness (total Vaqueros Sand thickness was 280 feet). To evaluate the impact of wellbore placement within notional reservoir stratification, the Upper and Lower layers are assigned permeabilities (0.05 md) that are half of the Middle layer (0.1 md). The results of the simulation indicated that somewhat staggered wellbore placement can be used to optimize vertical and lateral drainage. And for purposes of P10 reserves assignment the forecast of the center well in the model, which was placed in the P10 perm (‘higher perm’) layer, was used for the Vaqueros Sand reserve forecast. FIGURE 29 is a plot of this forecast of oil, water and GOR for the Vaqueros P10 type well.

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Figure 28. Vaqueros P10 Model & Input for Multi-Well Numerical Model

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Figure 29. Vaqueros Sand P10 Oil, Water, GOR Forecasts

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4 Development Plan and Reserves Forecast

Based on production tests of wells within the leasehold, and analogy to other fields that have produced from the Monterey, particularly West Cat Canyon, it is believed the Monterey Blue will be productive through much of the leasehold as mapped by Trio in the both the Humpback and Presidents project areas. The Monterey Yellow has been shown productive in the Presidents area with the production test from the Hames Valley 3A and, while testing in the HV-1 resulted in contracting the mapped productive area by about 35%, the Mid Monterey Clay immediately below the Yellow Zone has demonstrated prospectivity that may likely be exploited elsewhere in South Salinas. Completion testing and short production periods of the BM 2-2, BM 1-2 and the HV-3A have demonstrated that P90 (Proved) oil and gas forecasts of the Monterey Blue and Monterey Yellow at these locations may produce oil at economic rates (economic in the sense that they produce a positive cumulative undiscounted cash flow). So, the economics associated with the Project use the Yellow and Blue production forecasts associated with the P50 (Probable) and P10 (Probable+Possible) probabilistic models. The Vaqueros Sand has produced in many California fields having similar stratigraphic and structural settings. And while it is highly prospective at South Salinas it has been reached by only six wells, none of which tested the interval exclusively. Two of these wells may have straddled the upper portion when testing the Sandholdt immediately above the Vaqueros and, as such, the associated oil recoveries evidenced Vaqueros prospectivity. For these reasons Possible reserves have been assigned to the Vaqueros Sand.

It appears unlikely that any well drilled in the mapped prospective (productive) areas would be a ‘dry hole’. However, there is uncertainty regarding the initial oil production rates, water cuts, and extended reservoir performance that may be achieved. The probabilistic modeling described above captures this uncertainty in accordance with the Petroleum Resources Management System guidelines for the assignment of reserves. The following development plan describes a Project that fully develops the oil and gas reserves in South Salinas as they are currently mapped and understood. The Project is composed of three phases and reflects the progression of capital deployment with successful efforts and the anticipated time frame associated with regulatory approvals.

Phase 1 uses already-permitted wells and existing wells that can be expeditiously re-entered upon approval of the Conditional Use Permits (CUPs) by Monterey County. Phase 1 confirms the productivity of the Monterey Blue Zone over the larger area, and it establishes cash flow to partially support on-going development. Within Phase 1, the HV-3A will be worked-over to enhance production from its existing completion in and above the Yellow Zone. The HV-2 and HV-4 will be drilled and completed in the Blue Zone of the Presidents Area. The existing HV-1 is re-entered and deepened through the Blue Zone, and three other existing wells (BM 2-2, HV 1-35-RD1, HV 3-6-RD1) will be re-entered and sidetracked through the Blue Zone in the Humpback Area. Although targeting a completion in the Blue Zone, it is likely that each of these re-entered wells will be drilled to the Vaqueros with the intention of gathering data and testing the Vaqueros to confirm it prospectivity as a horizontal well development. Phase 1 is scheduled to begin August 2024 with the HV-3A workover and, with receipt of the CUP on or about April 2025, conclude with the sidetrack drilling of the HV 3-6-RD1 in June 2025.

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Phase 2 of the South Salinas Project consists of a 12 well program. The first well is a sidetrack of an existing well (HV 2-6-RD1) through the Blue Zone in September 2025, followed by the drilling of a new well each month thereafter through August 2026. Phase 2 begins with receipt of the remaining (Full) Development Permits from Monterey County. Phase 2 also assumes that by September 2025 Trio should be experiencing the timely approval of drilling permits from CALGEM. Of the 12 Phase 2 wells, four wells will target the Yellow Zone, seven are planned for the Blue Zone, and one well is a horizontal well in the Vaqueros Zone.

Phase 3, also referred to as the Full Development Phase, begins October 2026 with the utilization of three rigs drilling continuously for about four years. Two of the rigs will be used to drill 101 Blue Zone wells, while the third rig will be used to drill 20 Yellow Zone wells and 16 horizontal Vaqueros wells. This phased Project development plan is shown in TABLE 5.

Table 5. Development Plan - Phases 1, 2 & 3 Wells and Targeted Reservoirs

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The well naming convention identifies the bottomhole placement of the completion and is in accordance with a commonly used (in California) grid of 10 acre spacing whereby the first of the two digit well name reflects the well position from west to east, and the second digit reflects the well position from north to south, as shown in the FIGURE 30 schematic. The second part of the well name is the section number of the well at its bottomhole location. FIGURE 31 shows the surface and bottomhole locations for Phase 1 and 2 wells. Note the existing wells that will be re-entered are designated by their current names rather than the naming convention describe above.

Figure 30. Phase 1 & Phase 2 Well Locations

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Figure 31. Well Naming Convention & Location on 10 Acre Grid

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5 Economic Analysis

The economic analysis used TRC Consultants’ PHDwin Version 3 economics software to schedule production and costs, incorporate interests, and calculate cash flows. The production forecasts used Arps decline curves derived from matching the respective P50 and P10 forecasts for the Monterey Yellow, Monterey Blue and Vaqueros Sand (FIGURES 26, 27 and 29). Wells are scheduled per the Development Plan in TABLE 5. For each well, drilling and completion costs were applied at spud month and year, and production started two months later. Drilling and completion costs were provided by Trio and are considered reasonable based on the costs to drill and complete similar wells in other California fields. The costs to P&A wells and cleanup surface locations are included for each of the existing and planned wells. These abandonment obligations were estimated to be $127,000 per well based on detailed cost estimates derived for existing wells. Other economic input is summarized in TABLE 6.

Table 6. South Salinas Economic Parameters

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The price deck was based on SEC guidance in its “Modernization of Oil and Gas Reporting” (Effective January 1, 2010) in which it specified use of “12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period.” The oil and gas prices derived in this manner are shown in TABLE 7. Oil prices are based on a Shell Trading contract that Trio indicated is applicable to its South Salinas production. It states that the price per barrel will be the average of the Chevron, Exxon, Shell and Union 76 postings for Midway Sunset crude oil having a benchmark API gravity of 13 degrees. Each of the posted values was adjusted for the API gravities of TABLE 1 using the applicable gravity adjustment cited in each of the buyer’s posting notifications. The average gravity adjustment was applied to the benchmark oil price for each of the three producing horizons. Shell Trading deducts $4.35 per barrel for transportation so the producing zone oil prices of TABLE 6 reflect the gravity adjustment and transportation charge Based on discussions with Trio it is anticipated that marketing the gas to the San Ardo field operator as an end user will be the optimum market for gas. The San Ardo Field area is at the southern end of a PG&E gas line from the Sacramento Valley that has limited capacity, so the local area is reportedly gas-supply constrained and Trio’s HV 1-35 pad may be within approximately one mile from a possible connection to an existing Aera pipeline. The benchmark price for gas sales was assumed to be Henry Hub with a 10 percent premium based on reported gas prices being received by producers in the Sacramento Valley north of South Salinas. Since it is unlikely that a gas sales contract can be executed until the Development Permit is acquired, the gas produced from the three permitted wells is assumed to be flared until gas sales begin in April 2025. The forecast gas production is not adjusted for normal shrinkage with separation, but this is offset from a value proposition by assuming that the associated gas will only have a BTU content of 1000 BTU per scf. Similarly, since a water disposal well may not be permitted until approval of the UIC application, the production from the HV-1, HV-2 and HV-4 was burdened with a water disposal cost of $4 per barrel until May 2025 (the water production rate is assumed equal to the oil production rate).

Table 7. First-of-Month Oil & Gas Benchmark Pricing

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There will continue to be expenses associated with regulatory and permitting work through early 2025. And as production increases with phased development there will be the need to expand water disposal, gas gathering and compression, and facilities to provide separation, testing and tankage. These costs are shown in TABLE 8 and are based on input from Trio.

Table 8. Estimated Capital for Permitting & Field Infrastructure

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6 Economic Results

The PHDwin economic runs were performed as follows:

1.	The Probable (P2) cases were run, all with associated CAPEX, OPEX, taxes, etc.
2.	The Probable + Possible (3P or P10) cases were run.
3.	The Possible (P3) economics are derived within PHDwin by subtracting the 2P case from the 3P case, so the incremental Possible reserves do not carry any of the CAPEX and OPEX cost. In other words, it is assumed that there are no incremental costs associated with a well producing the additional oil and gas attributed to the Possible reserves.
4.	The exception to number 3 above is the Vaqueros well that is drilled in Phase 2 and the Vaqueros wells associated with the Full Development phase. The Vaqueros has only been assigned Possible reserves, so its P3 case is burdened by the appropriate CAPEX and OPEX associated with that well.

TABLES 9 and 10 present a one-line summary of the oil and gas reserves, and cumulative net discounted cash flow for each well in Phases 1 and 2, respectively. TABLES 11 through 18 provide the detailed economic output for Phases 1, 2, 3 and the total Project Probable reserves, followed by Phases 1, 2, 3 and total Project Possible reserves, respectively. FIGURE 32 is a plot of oil and gas rates versus time, showing the summed forecasts for the 2P and 3P cases. TABLE 19 through TABLE 21 provide economic output for ‘typical’ wells, namely the HV-2 (Monterey Blue 2P case), HV 56-19 (Yellow P2 case_ and the HV 23-1-H (Vaqueros P10 case), respectively.

Table 9. One-Line Economic Summary for Phase 1 Wells

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Table 10. One-Line Economic Summary for Phase 2 Wells

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Figure 32. Production Forecasts of PROBABLE & PROB+POSS (3P) Reserves

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Table 11. Economic Output for Phase 1 Probable (P2) Reserves

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Table 12. Economic Output for Phase 2 Probable (P2) Reserves

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Table 13. Economic Output for Phase 3 Probable (P2) Reserves

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Table 14. Economic Output for Total South Salinas Probable Reserves

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Table 15. Economic Output for Phase 1 Possible (P3) Reserves

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Table 16. Economic Output for Phase 2 Possible Reserves

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Table 17. Economic Output for Phase 3 Possible (P3) Reserves

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Table 18. Economic Output for Total South Salinas Possible (P3) Reserves

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Table 19. Economic Output for Monterey Blue Well HV-2 Probable (P2) Reserves

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Table 20. Economics for Monterey Yellow Well HV 56-19 Probable (P2) Reserves

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Table 21. Economics for Vaqueros Well BM 23-1-H Possible (P10) Reserves

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Table 22. Glossary of Terms Used to Characterize Reserves & Projects

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