Orbex Market Group

T-CC...6903

N/A

Earthood Services LTD

N/A

Carbon Capture,Sequestration

One-time

D-MRV / Methodology

Public network NFT

As Produced

Triangle

The proposed methodology will create a market incentive that encourages the removal of U.S. thermal coal from the global commodities marketplace. This proposed project activity is the first such coal incentive, and the advantages of this methodology are numerous. The following are five key methodology attributes: • The coal is owned by entities and individuals in the U.S. other than the U.S. Government. The nonfederally owned minerals not only allow for quick action but also provide accountability and enforceability. • The methodology is scalable, with the ability to remove significant amounts of thermal coal in an expedient timeframe as the U.S. has the world’s largest coal reserves, of which nearly 67% are owned by individuals, corporations, and others outside the U.S. Government. • Institutional risks are minimized, as the coal volume calculations follow the U.S. Securities Exchange Commission reporting guidelines for public entities. • Reducing risks further, the base datasets in calculating the GHG emission mitigations, leakage, and functional equivalence all originate from well-respected third-party sources (e.g., Energy Information Agency (“EIA”), The Intergovernmental Panel on Climate Change (“IPCC”), and others) and International Monetary Fund (IMF). • Publicizing the successful execution of coal removal projects at scale using this methodology will have a future negative economic impact on those who are currently dependent on and/or plan to be dependent on inexpensive, high-quality coal availability. As this methodology is implemented at scale, the negative economics will lead to shifts in strategic direction away from long-term thermal coal usage.

CRR ORBEX.PROTOCOL 01 US COAL

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Tons of sequestered coal x IPCC ratio of tCO2 produced per ton of bituminous coal

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N/A

Live

N/A

80321896

80321896

80321896

1

80321896.0000

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N/A

N/A

N/A

N/A

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United States, KY

83.173889 W

37.97111 N

EST

Carbon Reduction Resources LLC

N/A

N/A

N/A

N/A

N/A

N/A

We2Sure

N/A

N/A

Sequestration of coal reserves at Lennox and Elk Fork Coal Mine in Kentucky

Located in Kentucky, USA, the project involves the closure of the Elk Fork coal mine and the long-term sequestration of approximately 34.5 million baseline, 27.5 million net, US short tons of coal for the 2025 vintage. As part of the carbon project activities, mineral rights were purchased from twelve previous owners in early 2025. Following site reclamation, the mineral rights will be transferred into a conservation easement designed to ensure at least 99 years of coal non-extraction. The project has forward-credited 80,640,517 million credits in 2025 for avoided combustion emissions that the project asserts would otherwise occur over the next 17 years. Credits were issued under a new Orbex methodology, which requires reinvesting a portion of revenues into low-carbon initiatives.

N/A

ZeroSix LLC

T-CC...6827

BeZero

Ryder Scott

Carbon Credit

Oil and Gas Well Capping,Avoidance

One-time

D-MRV / Methodology

Public network NFT

As Produced

Triangle

Proven oil and gas reserves (calculated as per the U.S. Securities and Exchange Commission Final Rule regulations for publicly traded oil and gas companies) abandoned permanently (with wells plugged) measured in barrels of oil and cubic feed of gas. The CO2 equivalent emissions avoided result by calculating the total amount of GHG emissions (CH2, NO2, CO2 and others) that would result from exploiting (burning) these proven reserves. The permanence requirements reflect current regulations of carbon sequestration, including the California Air Resources Board’s (CARB) Carbon Capture and Storage (CCS) protocol and the United States Environmental Protection Agency (EPA) Class VI permit requirements

v1.0

Oil Reserves (bbl), Oil API Gravity (API degrees), Gas Reserves (Mcf), Gas Heating factor (MMBtu/Mcf), NGL Reserves (bbl), NGL composition (Mole %)

Carbon-content quantification of reserves begins with fluid characterization at a specified reference point in the production flow-chain. The reference point is a defined location within a petroleum extraction and processing operation where the produced quantities are measured. This is typically the point of sale or where custody is transferred to the midstream or downstream operations. This point is envisaged to correspond with the point at which combustion of the product and emission of the associated GHGs by the end users occurs. Hence avoided emissions of the reserves will be determined in terms of quantities that would be crossing this point over the period of economic producibility under the defined operating assumptions. It is important to have a good understanding of how historical production quantities were reported. Sales quantities are equal to raw production less non-sales quantities (those quantities produced at the wellhead but not available for sales). Non-sales quantities include petroleum consumed as fuel, flared, or lost in processing; these would also be credited for avoided conversion following a successful permanent abandonment of the designated production. The full sum of avoided emissions is the aggregation of non-sale volumes and sales. Sales quantities may need to be adjusted to exclude components added in processing but not derived directly from project well production. Total well production measurements are necessary and form the foundation of many engineering calculations (e.g., material balance and production performance analysis) based on total reservoir voidage. Additives to the production stream for various reasons, such as diluents to enhance flow properties, are excluded from avoided emissions resources. Consumed in operations (CiO) and flared volumes are typically not included in standard reserve reports but need to be included in the avoided emissions calculation; this is generally encompassed in the gas shrinkage volume and is added back into volume determination. Carbon Emissions Intensity Once the remaining technically and economically recoverable volumes have been established for oil, gas, and natural gas liquids (NGLs), their respective volumetric carbon intensity is established. The carbon intensity is determined by the chemical composition of each fluid and is directly calibrated by standard fluid property field measurements. Gas phase carbon content is determined using the emissions constant for methane, 52.91 kg CO2/MMBtu, which constitutes the majority of the gas phase following the well site phase separation process.19 The emissions factor is adjusted by the gas heating value (GHV); for pure methane it is 1.00 MMBtu/Mscf and, in some cases it may be adjusted upward to account for the presence of heavier gas components such as ethane, propane, butane, and pentane+. The factor can also be lower if there are non-reactive contaminants such as nitrogen or CO2 present. The heating factor is to be submitted by the project owner and verified by submission of a recent gas analysis report from a third party gas analysis laboratory. The NGL emission factor is also verified from the gas analysis report, where the molecular weight percentage of ethane, propane, butane, and pentane+ is reported. The liquid fractions and the corresponding component emission constants as reported in the 2022 EPA Fuel Emission-Factors document can be used to determine the total emissions per barrel of natural gas liquids from the proposed project, as shown in Table 2.19 The CO2 emissions factor for oils is variable due to the unique composition of hydrocarbons. The variability reflects organic geochemistry, depositional environment, and subsequent thermal history which could markedly impact temporal kerogen maturation. The API gravity (a measure of the density) of the oil phase is correlated with the length of its component carbon chains, the longer the carbon chains, the heavier the oil, and the larger the CO2 emissions factor upon refining and use. The best-fit line with a strong R factor of 0.9828 is the relationship used to calculate CO2 emissions and equitable issued carbon credits for the oil phase based on API. This measurement is verified by a submission of recent oil sale receipts issued by a third party offtake operator which has the API gravity of the oil clearly visible. The CO2 equivalent mass of avoided emissions is determined by combining the proved developed recoverable volumes of each production phase and the associated carbon content described in this section. The prevented scope 3 emissions represent the early retirement of reserves which prevents downstream combustion by end users. Downstream Scope 3 Emissions Avoidance In addition to the avoided emissions from combustion of the produced oil, there are fuel cycle emissions originating from the oil and gas transportation and processing. By not bringing these resources to market as final refined products, additional emissions avoidance is captured. Many of the fuel-cycle emissions have a high degree of variability based on the technical nature of the specific projects and the geographic location of the operations, which may significantly impact the associated energy and emissions of the production operations and transportation to market. In comparison, direct emissions from refining crude oil into specific products (summarized in Figure 6), are of more significance. Brandt, et.al. propose a linear relationship between crude oil gravity and refining GHG emissions, which is here utilized to provide the basis for associated credits.21 The emissions are accounted for in the crediting calculation since they are parameterised by a standardized property of the crude oil, rather than project specific variables. Because of the high degree of confidence of these scope 3 emissions, their inclusion is merited and therefore credited to the project owner upon successful project execution. Scope 1 Fugitive Methane Emissions In addition to the scope 3 CO2 emissions eliminated by preventing the combustion of gas reserves, there is also an associated abatement of methane release from production systems and/or leaks during transportation to the downstream market. The published results of the Environmental Defence Fund (EDF 2012-2018) study concluded that the industry supply chain rate of fugitive methane emissions is 2.3% of total domestic production.22 The research engaged 140 independent experts, from 40 different research institutions, across 16 rigorously executed projects, with support from 50 companies. The abated methane leakage from operations and transport of produced gas are credited to the project owner on a CO2 equivalent basis, using the 100-year GWP. The credit for these abated emissions is included, applying the average 2.3% of the verified remaining gas reserves. The early retirement of older, marginally economic wells mainly targeted by the incentives of this methodology cumulatively only account for 6% of US domestic production, but account for approximately 50% of fugitive methane emissions. This translates to a normalized loss rate of ~10%.23 Typical sources of operation methane leaks include: ● Fugitive equipment leaks ● Process venting ● Evaporation losses ● Disposal of waste gas stream (i.e., venting or flaring) ● Accidents and equipment failures Due to the greater impact of methane on global warming, upon the successful abatement of these scope 1 emissions, the 2.3% of verified gas reserves shall be credited on a CO2 equivalent basis. According to the latest IPCC AR6 report, the CO2 equivalent global warming potential (GWP) of methane on a 100 year basis is 27.9 times greater than that of CO2, thus for purposes of carbon credits, the fugitive methane emissions as a percentage of gas reserves is evaluated at 1,476.19 kg CO2 equivalent/Mscf.24

None

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Live

None

2023

Monthly historical production as reported to state regulator.

Decline Curve Analysis

2

303494.3473

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N/A

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Protocol V1 - Version of the protocol used for verifying the specific project

Well API Number - API number of the well to which carbon credits correspond to

Additionality The additionality test is intended to ensure that carbon offsets are an addition to reductions and/or removals that would have occurred in the absence of the project activity and without carbon market incentives. To be considered “additional,” the project must demonstrate that the GHG emissions reductions and removals associated with an offset project are above and beyond the “business as usual” scenario. Relative to alternative carbon emission offset projects, the proposal for retiring existing and future reserves must satisfy these 3 criteria. A compliant project demonstrates that it exceeds the 1) Regulatory Test: the proposed activity exceeds currently effective regulations, 2) Common Practice Test; goes beyond common practices in the oil and gas industry sector in the geographic region of operations, and 3) Implementation Barrier Test; faces one or more implementation barriers.13 Regulatory Test 1. Emission reductions achieved by foregoing expected production volumes must exceed those required by any applicable federal, Tribal, state, or local laws; regulations; ordinances; consent decrees; legal arrangements; or other legally binding mandates. 2. The project operator must have an active and valid operating license in the jurisdiction of the proposed project. 3. Legally binding mandates may include, but are not limited to, existing moratoriums on production from project land leases or mineral rights. 4. The legal requirements are satisfied if: a. Project activities are not legally required at the time of offset project commencement. b. Modeling of the project’s baseline carbon stocks reflects all legal constraints and regulatory guidelines as required by SEC reserves reporting guidelines. c. Avoided production projects submit o cial documentation demonstrating that the type of operation activity proposed by the project is legally permissible, through valid activity permits. Common Practice Test The project must demonstrably depart or exceed common practice. Retirement of remaining economic production and reserves is not common practice and, therefore, with the proof of economically viable production, projects submitted under this protocol are deemed to have passed the common practice test. Implementation Barriers Test The proposed carbon offset project must fulfill at least one of three implementation barriers: (a) Financial - Continued extraction of oil and gas volumes is deemed an economic venture, thus permanent retirement of these economic reserves faces strong financial barriers without the compensation through carbon credits or other means. The economic viability of targeted reserves is established through SEC reserves reporting standards, which must be adhered to in the quantification of carbon emission avoidance in this protocol (see Chapter 3). (b) Technological - There are no new technological barriers to implementing the ZeroSix solution, which bolsters the case for broad industry implementation and rapid adoption. However, the value of the innovative ZeroSix blockchain enabled platform for the purpose of creating transparency and auditability of carbon emission abatement quantification and execution, is a new concept for the oil and gas sector. There is currently limited market penetration for this technology, but its relevance is the material reduction of GHG emissions. (c) Institutional - Institutional barriers exist in the novelty of this approach and buy-in from regulators, mineral owners, and non-operating partners must be secured. Compensation through carbon credit values provides a strong incentive for project non-originating royalty owners to support the abandonment of productive reserves, rather than selling them for the purposes of refining and combustion, resulting in an ever-increasing global carbon debt.

Permanence Projects must demonstrate permanence of avoided carbon emissions. The project owner/operator must submit a descriptive report prepared by a recognized professional organization that includes a compilation of project data (wireline logs, well tests, and structural/stratigraphic maps). In addition to the geologic permanence assessment, the project owner will need to secure legally binding contractual or legal protections against the future production of the retired resources. These protections, in addition to the digital platform mechanics, will provide assurance of: 1. Geologic Permanence: Through determination of target P&A candidate well drainage area calculations through geology, pressure transient analysis, reservoir modeling, material balance, or well interference case studies, and justification for the associated reserves remaining unproduced upon execution of the project. 2. Legal Permanence: Through proof of contractual amendment of ownership with permanent retirement of mineral extraction rights, through executed Declarations of Restrictive Covenants or equally binding legal protection against future extraction. 3. Operational Permanence: Through ongoing post-execution automated monitoring by the ZeroSix platform of state regulators for any new development permits being issued in proximity of project area. 4. Long Term Validity of Issued Credits: Through contribution to the ZeroSix buffer account funded through credit withholding to offset any detected reversals of reserve volumes claimed for the project credits The case for geologic permanence must be made from a technical perspective and will vary based on the type of resource operation of the submitted project. There are several broad cases of hydrocarbon extraction that are distinct in the properties of fluids, subsurface conditions, and/or development mechanics, which justify different approaches in determining permanence. 2.7.1. Conventional Resources Conventional resources exist in porous and permeable rock under pressure equilibrium. The PIIP is trapped in discrete accumulations defined by a local geological structure, feature, and/or stratigraphic conditions. Each conventional accumulation is typically bounded by a down dip water contact, as its position is typically controlled by buoyancy of oil in water. The oil/gas is recovered through wellbores and typically requires minimal processing before transportation to market. The technical behavior of these systems is constrained with reasonable certainty and permanence can be achieved through the simultaneous abandonment of all wellbores produced from a discrete accumulation. 2.7.2. Unconventional Resources Unconventional resources exist as petroleum accumulations that usually have a significant regional extent. They are not significantly affected by hydrodynamic influences (also referred to as a “continuous-type deposit”). Commonly, these accumulations are not defined structurally. Examples include coalbed methane (CBM), basin-centered gas (low permeability), tight gas and tight oil (low permeability), gas hydrates, natural bitumen (very high viscosity oil), and oil shale (kerogen) deposits. Note that shale gas/oil are subtypes of tight gas/oil, where the lithologies are predominantly shales or siltstones. These accumulations lack the primary connected permeability of conventional reservoirs and require subsurface stimulation to achieve economic viability. Typically, such accumulations require specialized extraction technology (e.g., dewatering of CBM, hydraulic fracturing stimulation for tight gas and tight oil, steam and/or solvents to mobilize natural bitumen for in-situ recovery, and in some cases, surface mining of oil sands). Moreover, the extracted petroleum may require significant processing before sale (e.g., bitumen upgraders). The establishment of permanence of unconventional resources will vary based on the subsurface flow and extraction mechanisms involved. Coalbed methane (CBM) – CBM gas is generated within coal seams and gas is stored via adsorption, meaning it is tied to the coal at a chemical level and does not flow freely. There are natural fracture networks in the coal formations called cleats, which may contain free gas, but may also contain water. The development of these resources generally involves induced fracking. This type of production is exemplified by an early period of high-water production as the coal formation dewaters, and the gas rate increases, ultimately stabilizing once the dewatering of the stimulated formation and fracture network is complete. The gas rates are characterized by a shallow rate decline for extended periods of production. Reserves are extracted at a slow and steady pace of gas desorption from each producing well’s fracture network in the target coal bed. It is this fracture network which conveys liberated gas molecules to the wellbore and subsequently to the surface. The range of reserves’ extraction is controlled by the extent of the fracture network and the disequilibrium between conditions in the fracture versus the coalbed. This disequilibrium can be influenced by a variety of factors including pressure differentials, partial pressures of gasses from concentration differences, and the percentage of water content. To establish permanence, it must be demonstrated that the target fracture network is not connected to and being produced by any offset fracture networks from nearby wells. This can be done via fluid property analysis, pressure tests in offset wells designed to determine wellbore interference to provide additional support for permanence models. Basin-centered Gas, Tight Gas, and Tight Oil (e.g., Shale) – These resources exist in low permeability deposits and are extracted through stimulation by hydraulic fracturing. To establish permanence for induced fracture flow pathways, no pressure communication must exist with adjacent wellbores producing from the same target formation. This determination may be assessed regionally showing the largest distance of observed pressure communication between offset production wells. Only volumes outside this determined radius can be classified as permanent carbon emission avoidance. Natural Bitumen (very high viscosity oil) and Oil Shale (kerogen) – Bitumen or heavy oil does not migrate without additional subsurface treatment, such as steam flooding to reduce viscosity and increase mobility; large volume water flooding; or through mechanical mining. Due to the fluid properties of this resource, permanence can be assured by discontinuing the enhanced recovery extraction activities (e.g., steam flooding or mining). 2.7.3. Technical Documentation The following permanence guidelines are not exhaustive but will inform operators how to generate a credible permanence case for specific projects based on the technical details of production. The case for permanence must be documented in a comprehensive report, which will include the relevant information and data necessary to verify the credibility of the permanence of the credited reserves. The analogue of the EPA Class VI carbon dioxide injection permit requirements is used in the drafting of these requirements.7 As the requirements for establishing permanence for an active injection plume at high pressures are significantly greater than establishing permanence for a static reservoir generally under low pressures, only requirements necessary to establish static permanence are used for validation of reserve retirement. The submitted permanence report will include information on the geologic structure, hydrogeologic properties of the project reservoir, and past interventions through development. The report should also include a brief synopsis of the geologic history of the project site, and include the names, lithologies, and depths of the abandoned formation(s) and confining zone(s). The comprehensive exhibits must consist of the following: 1. The location, orientation, and properties of known or suspected faults and fractures that may act as reservoir boundaries or transect the confining zone(s) in the project area and a determination that they would not facilitate fluid migration; 2. Data on the depth, areal extent, thickness, including geology/facies changes based on field data which may include geologic cores, outcrop data, seismic surveys, well logs, and names and lithologic descriptions; 3. Information on the seismicity history, including the presence and depth of seismic focal depths and a determination that the seismicity would not interfere with an at minimum 50-year containment; and 4. Geologic data, including surface/depth-structure maps and cross-sections illustrating regional geology, hydrogeology, and the geologic structure of the local area showing the presence and trends of folds, and whether the proposed storage site will be bounded by faults or other compartment features. (a) Map A map of the project area showing the number or name, and location of all injection wells, producing wells, abandoned wells, plugged wells or dry holes, deep stratigraphic boreholes, state- or EPA-approved subsurface clean-up sites, and deep subsurface mines. The map should also show faults, if known or suspected.7 1. Geological base-map (including geodetic projection parameters) that details the following: a. Lease boundaries. b. Project boundaries. c. Locations of all wells within project boundaries (XY or Lat/long format). d. If wells are horizontal or deviated, show lateral trajectory. e. Legend that designates status of all wells. i. Producing from project formation. ii. Producing from different formation. iii. Shut in and completed in project formation. iv. Shut in and completed in other formation. v. Plugged and abandoned. vi. Other wellbores penetrating project reservoir – but not P&A’d. f. Major (sealing) and minor (non-sealing) faults designated accordingly, transmissibility barriers and stratigraphic discontinuities. i. Above features that control project boundaries should be designated as such. 2. Isopach (thickness) map of the project formation with the same information listed above. a. Limits of isopach maps (pay termination) that define project boundaries should be marked as such. (b) History Matching and Dynamic Data Analysis of historical production and pressure data from the project formation showing any communication through faults, other adjacent formations, or with wells outside the project boundaries. Demonstrate and place into context for the dominant reservoir drive mechanism if such could either threaten the permanence of the sequestered reserves or could augment the case for permanence. (c) Project Area Wellbore Inventory A tabulation of all wells within the project area which penetrate the target reservoir(s). Such data must include a description of each well type, construction, date drilled, location, total depth, and record of plugging and/ or completion. (d) Cross Sections A combined structural/stratigraphic well-log cross section from as many wellbores as necessary to provide a representative illustration of structural trends relevant to the target reservoir. All wells should highlight the completed interval(s), designating the status of those completion intervals, e.g., open to production, shut-in, isolated, or plugged. The representative cross-sections should also show sealing faults that highlight pressure isolation. (e) Wellbore Schematics Wellbore schematics showing completion intervals of all wells, history of all mechanical events (workovers, recompletions, fish in hole, etc.), all perforations and status of perforations (e.g., open to production, shut-in, isolated, or plugged), and a schematic of proposed abandoned condition of wells in the project. (f) Other Pertinent Information Present any other tests, such as cement bond logs, interference tests, fluid analysis, well production tests, water salinity, tracer surveys, drainage radius calculations, material balance calculations, numerical simulation modeling, etc., that are pertinent to the establishment of the project as an isolated formation and area. (g) Minimum Information Criteria 1. All analyses and tests to support the demonstration of permanence must be accurate, reproducible, and performed in accordance with established industry quality assurance standards. 2. Estimation techniques must be appropriate for each specific project operating environment as designated by industry best practices and EPA-certified test protocols must be used where available. 3. Any models must be appropriate for the specific project operation and tailored to the site conditions and fluid compositions. 4. Predictive models must be calibrated using existing information where su cient data are available. 5. Probabilistic values and modeling assumptions must be used and disclosed whenever values are estimated based on known, historical information instead of site-specific measurements.

Types of Activities This protocol applies to oil and gas production offset projects preventing the conversion of in-situ reserves into marketable commodities. This is achieved by executing the permanent abandonment of wellbores. The controlled mineral rights are then dedicated to protected non-recoverable resources through a legally binding declaration of restrictive covenants signed by the mineral owners, or an equally binding legal agreement. These actions prevent the future extraction of the designated resources, which are to be claimed for carbon credits.

Quantification Fossil fuels are the single largest source of GHG emissions. The lifecycle emissions from hydrocarbon production and use can be divided into three broad categories: 1. Upstream emissions: Emissions that occur during the production and extraction of hydrocarbons, including exploration, drilling, and transportation of oil and gas to the refinery or processing facility. Upstream emissions can include emissions from the use of fuels to power drilling equipment, as well as from the flaring or venting of natural gas. 2. Refining emissions: Emissions that occur during the refining of crude oils into usable products that include gasoline, diesel, and jet fuel. Refining emissions can include direct emissions from the refining process, as well as indirect emissions from the energy used to power the refineries. 3. Downstream emissions: Emissions that occur during the use of fossil fuel-based products, including the combustion of gasoline and diesel in vehicles, as well as the use of fossil fuel products for heating and electricity generation. Figure 2: ZeroSix crediting boundaries. The relative magnitude of these categories is shown in Table 1. These can be further categorized according to Scope 1, 2, or 3 relative to the party responsible for producing the hydrocarbon volumes. 1. Scope 1: Direct emissions that occur from sources owned or controlled by the operator, such as emissions from combustion of fossil fuels during production operations and emissions from flaring, venting, or fugitive leaks of methane gas. 2. Scope 2: These are indirect emissions that occur from the generation of purchased electricity, heating, and cooling that the operator consumes. 3. Scope 3: These are indirect emissions that occur from sources that are not owned or controlled by the operator, but that are associated with the produced fluid value chain. These include emissions from the combustion of the produced fluids by end-users. The protocol enables project owners to recognize where the greatest reduction in emissions potentially resides. By targeting and crediting the largest contributing emission categories in the hydrocarbon fuel cycle, see Figure 2, project owners can implement the most effective emission reduction strategies. In order of magnitude, these are Scope 3: end use of produced oil, gas, and NGL reserves, Scope 3: refining of produced oil, and Scope 1: flaring, venting, and fugitive methane emissions. Reserve Qualification The US Securities and Exchange Commission (SEC) has established guidelines for regulating the calculation of hydrocarbon reserves. These are used by companies for their annual reporting obligations and to comply with investor and market transparency standards. The following have been established to ensure consistent definitions for both investors and market actors.3,4,5 Project owners must engage a third party engineer qualified to prepare reserve reports according to SEC reserve quantification standards. From SEC requirements, the qualified person shall5: 1. Be a licensed professional engineer or a registered geologist with at least five years of relevant experience in the type of reservoir being evaluated. 2. Have experience in preparing reserve estimates or evaluating reserves that are relevant to the type of reservoir being evaluated. 3. Have familiarity with the geological and engineering principles and practices used in the industry for evaluating reserves. 4. Have a reasonable understanding of the legal and regulatory framework governing oil and gas operations. 5. Be independent of the company for which the report is being prepared, meaning that they have no direct financial interest in the company and are not an employee or o cer of the company. 6. Be qualified to make engineering or geologic evaluations of the type of reserves being reported. 3.1.1. Eligible Volume Classification Reserves are quantities of hydrocarbons anticipated to be economically recoverable in the future (as of an effective date). The criteria for project reserves are 1) they are discovered, 2) recoverable, 3) economic, and 4) remaining within the reservoir as of the evaluation date.18 A further refinement (specific to a project’s additionality criteria) is that only volumes designated as proved-developed reserves qualify as candidate volumes that currently satisfy additionality criteria according to this protocol. Standards of proved developed reserve volumes include two categories, developed producing and developed non-producing volumes. Proved developed producing (PDP) reserves, are volumes expected to be recovered from wellbore intervals that are producing at the time of abatement project commencement.3,4,5 They are also determined to be economically recoverable under existing technical and commercial conditions with reasonable certainty using geoscience and engineering analysis. Developed non-producing (PDNP) reserves, include potential volumes in shut-in wells or behind wellbore casing pipe of currently producing wells. These volumes can be economically returned to production with minor capital costs with a reasonable certainty.3,4,5 A minor capital cost is defined as a lower expenditure than the cost of drilling and completing a new well. The quantity of incremental volumes must be supported by technical evidence with a high degree of confidence required for proved reserves categorization. The incremental reserves associated with future workovers, treatments (including hydraulic fracturing stimulation), re-treatment, changes to existing equipment, or other mechanical procedures may be classified as developed reserves if such projects have routinely been successful in analogous reservoirs or offset operations, and it meets the criteria of a minor cost. In addition, reduction in backpressure from the surface gas gathering system through compression can increase the portion of in-place gas that can be economically produced and, thus, included in resource estimates. If the eventual installation of compression meets commercial maturity requirements, the incremental recovery may be included in developed reserves. To receive this designation, the cost to implement compression must meet the low-cost criteria. Alternatively, there must be a reasonable expectation that compression would be implemented by a third party. If the non-producing reserves meet the conditions above, they can be considered for carbon credits based on the consistent standards as the producing volumes. Reserves from potential enhanced oil recovery (EOR) projects are not covered by the ZeroSix protocol. These projects do not meet the minor-cost criteria and increase the deterministic uncertainty associated with quantifying the volume of avoided emissions. 3.1.2. Recoverable Reserve Volumes The performance-based analytical procedure for estimating recoverable quantities shall be applied for PDP reserves, however, high confidence volumetrically determined reserves can be used for PDNP where historical performance data may not be available. This approach can include material balance, history matched simulation, decline-curve analysis, and/or rate-transient analysis. The confidence in results increases when the estimates are supported by more than one analytical procedure. The two most widely used are the a) material balance and b) production performance analysis methods. a) Material Balance Material balance methods used to estimate recoverable quantities involve the analysis of pressure depletion as reservoir fluid is withdrawn. In ideal situations — such as depletion-drive gas reservoirs in homogeneous, high-permeability reservoir rocks, and where su cient and high-quality pressure data are available — material balance may provide highly reliable estimates of ultimate recovery at various abandonment pressures. In complex situations —such as those involving aquifer water influx, compartmentalization, multiphase behavior, and multi-layered or low-permeability reservoirs, shales or Coalbed Methane (CBM) — material balance estimates alone may provide inconclusive results. Project evaluation must accommodate the complexity of the reservoir and its pressure response to depletion in developing uncertainty profiles for the applied recovery project. Reservoir simulation can be considered a more rigorous form of material balance analysis. While such modeling can be a reliable predictor of reservoir behavior, the origin and therefore credibility of input data including rock properties, reservoir geometry, relative permeability functions, fluid properties are critical. Predictive models are most reliable in estimating recoverable quantities when there is su cient production history to validate the model through history matching. b) Production Performance Analysis Oil and gas production rates decline over time. Analysis of this change in combination with produced fluid ratios versus time and cumulative production as reservoir fluids are withdrawn, provide useful information to predict ultimate recoverable volumes. Prior to the full production rate decline profile becoming apparent in well history, trends in performance indicators such as gas/oil ratio, water/oil ratio, condensate/gas ratio, and bottomhole or flowing pressures, in combination with knowledge of the reservoir drive mechanism, can be extrapolated to the economic limit to estimate reserves. Decline curve analysis (DCA) is a graphical procedure used for analyzing production decline rates and forecasting future performance of oil and gas wells, including remaining technically recoverable volumes. Reliable results require a su cient period of stable operating conditions after wells in a reservoir have established drainage areas. In estimating recoverable quantities, evaluators must consider additional factors affecting production performance behavior, such as variable reservoir and fluid properties, transient versus stabilized flow regimes, changes in operating conditions, interference effects from offset wells, and depletion mechanisms. In early stages of depletion, there may be significant uncertainty in both the ultimate performance profile and the other factors (e.g., operational, regulatory, contractual) that impact the abandonment rate. Such uncertainties should be reflected in the reserve’s quantification. In very low-permeability reservoirs (e.g., unconventional reservoirs), care should be taken in the production performance analyses because the lengthy period of transient flow and complex production physics can make analyses quite di cult. 3.1.3. Uncertainty Uncertainty and risk are inherent with quantification of subsurface volumes. These can be summarized into three categories: 1. The total hydrocarbon and associated resulting emissions remaining within the accumulation. 2. The technical uncertainty in the portion of the total hydrocarbons that can be recovered by the project proposed for emission avoidance considering the technology applied. 3. Known variations in the commercial terms that may impact the recoverable volumes which can be delivered to market and result in emissions (e.g., market availability; contractual changes, such as production rate tiers or product quality specifications) as part of the project scope. Late-life PDP reserve volumes with a well established operational history are typically estimated deterministically, while PDP volumes with a history of erratic production and PDNP volumes can be better addressed through a probabilistic estimate; the probabilistic approach can manage the range of uncertainty . In such a case, volumes are calculated with a 90%confidence of exceedance and translate to volumes expected to be recovered (applicable for carbon credit through avoidance) that will equal or surpass the stated P90 estimate. The deterministic approach for volume calculation can be more subjective, but by incorporating the qualitative expression “reasonable certainty,” it is intended to convey a degree of confidence that the quantities will be recovered. Project reserves will be estimated using the above uncertainty evaluation methods, which incorporate subsurface analyses together with technical constraints related to the operation of wells and facilities. Additional commercial criteria would then be applied to the technically recoverable reserve volume forecasts to estimate the true volume of additional abated emissions. These commercial criteria may include but are not limited to operating expenses, future commodity price, realized price differentials, royalty structure, tax burden, and lease or license duration. 3.1.4. Price Determination Proved reserves must be economic in order to meet operational business requirements. In addition, proved reserves must satisfy the economic threshold to comply with additionality criteria to be considered for carbon credits as part of an emissions abatement program. The key metric for profitability assessment is the future looking commodity price over the expected life of the asset, which can be a significant variable. To establish a common evaluation, the SEC has standardized the reserve price forecasting methodology by using an average 12-month historical price on a go-forward basis. This standard is to be applied to all reserve determinations for the purposes of claiming emissions avoidance carbon credits. The 12-month period starting from the most recent practical month prior to the issuance of the applicable reserve report shall be applied using an unweighted arithmetic average of the first day-of-the-month price for each month within such period. For example, the relevant 12-month period for a reserve report issued on December 31 would span from the first day of January through the first day of December of that year.3,4,5 3.1.5. Assessment of Economic Viability Economic assessments are conducted on a project basis and are based on the operator's view of future conditions. Economic conditions include, but are not limited to, assumptions of general financial conditions (e.g., costs, prices, fiscal terms, taxes); organization capabilities; and marketing, legal, environmental, social, and governmental factors.3,4,5 Project economic viability may be assessed based on cash flow analysis. Factors that may influence long-term viability and, hence, additionality of the avoided carbon emissions, such as contractual or political risks, should be recognized and addressed in the project reserve report. (a) Net-Cash Flow Evaluation Project reserve economics are based on estimates of future production and net-cash flow (as of an effective date), as reported in a third-party reserve report. This documentation will be uploaded to the ZeroSix platform in support of the retired carbon volume. The third-party reserve reports are industry standardized documents, prepared by state licensed engineers. Project owners provide the following data in the third-party reserves report lease operating statement (LOS) and financial model support document: 1. Historical and forecast prices for produced gas ($/MMBTU), oil ($/BBL), and condensate ($/BBL), as well as a description of any existing sales contracts. 2. Any cost or price escalation schedules and rates if stipulated in existing contracts, otherwise they are not considered under SEC standards. 3. Historical and forecast operating expenses and supporting cost model including fixed and variable costs, fuel and gas shrinkage volumes, and any plans for cost reduction. 4. Lease and operating expense (LOE) statements, including water disposal and transportation costs. 5. Ad valorem tax rates and/or other tax application-regimes as well as any special production tax exemptions. 6. Transportation, processing & handling fees. 7. Planned capital expenditures for development or workovers associated with PDNP reserves, as well as abandonment, decommissioning, and restoration (ADR) liability for all project wells. 8. Ownership interest data, including working interest, net revenue interest, reversion interest, and pay-out balances at the effective date. 9. Contract, lease, or concession expiration dates. (b) Economic Criteria The forecast project-production volumes are deemed economic when the revenue attributable to the project owner’s interest from production exceeds the cost of operation. The abandonment, decommissioning, and restoration costs are excluded from the economically producible determination. Economic viability is tested by evaluating cash flow estimates based on the forecast economic conditions including operating costs, product price schedules, realized price differentials, and other relevant market factors. The forecast should reflect life-cycle assumptions applicable throughout the duration of the production operation. Inflation, deflation, or market escalations may be made to forecast costs and revenues. Forecasts should be based on current economic conditions and are estimated using an average of prices and costs over the preceding 12-month period, as per SEC guidelines. If a significant departure has occurred within this time, the use of a shorter timeframe that reflects the step change must be documented. All costs are included in the project economic analysis unless specifically excluded by contractual terms. Figure 3 illustrates a net cash flow profile for a project. The project’s economic production is truncated at the economic limit when the maximum cumulative net cash flow is achieved, before consideration of abandonment, decommissioning and reclamation (ADR). (c) Economic Limit The economic limit is defined as the production rate at the time when the maximum cumulative net-cash flow occurs for a project. The production volumes credited toward avoided emissions, are truncated at the end of the month in which either the technical, license, or economic limit is reached, whichever occurs first. In this evaluation, operating costs should include only those costs that are incremental to the project for which the economic limit is being calculated (i.e., only those costs that will be eliminated if project production ceases). Operating costs should include fixed property-specific overhead charges if these are incremental costs attributable to the project, as well as any production and property taxes. The calculation of the economic limit should exclude depreciation, ADR costs, income tax, and any overhead not required to operate the property. Interim negative project net cash flows may be accommodated in periods of low product prices or significant operational adjustments provided that the longer-term cumulative net cash flow forecast determined from the effective date exceeds the cumulative net cash flow during periods of negative economic operation. These periods of negative cash flow will qualify as reserves if the following positive periods more than offset the negative. No sub-economic production beyond maximum future cumulative net income can be considered as reserves for the purposes of crediting avoided emissions. 3.1.6. Production Facilities Each project must satisfy the basic needs for facilities required to maintain economic production for the foreseeable future, with no expectation of major expenditures or upgrades for at least 12 months. There must be su cient facility infrastructure to allow for reliable export to market or disposal of all production components from project wells, consistent with the forecasted volume profile of the proved reserves. 3.1.7. Reserves Volume Documentation The project owner must submit the following three documents to the ZeroSix platform with the hydrocarbon volume information consistent with the third-party reserves report. Once these documents are accepted by the third-party verifier for consistency with the claimed carbon credit amount, they will be immutably stored on the IPFS as a permanent record validating the amount of emissions abated and removed by the project. Project Reserves Report - Field Monthly Forecast providing the monthly amount of hydrocarbons forecasted to be produced by all the project wells combined, abiding by all the rules and regulations specified in this protocol. Project Reserves Report - Well Level Volumes providing total recoverable volume as a single value per well for each credited stream of hydrocarbons or other emissions. The project owner must submit third party reserves report historical production and forecast plots in a pdf document for the purpose of verifying well forecasts and remaining recoverable volumes against historical trends, clearly showing: 1. Rate time plots for all production streams submitted for carbon offsets under this protocol at the well level. 2. Enough production history on a monthly basis to clearly justify the forecasted trend, but not less than 12 months. 3. Forecast must be shown from the project as of date, through to the economic limit of each well plus one year. 4. Decline parameters, including initial rate, b-factor, initial and terminal decline rates, and cut off rate for every forecast segment.

Project Eligibility For a project to be protocol compliant the operator must satisfy the following minimum requirements with documentary validation: 1. A submission of operator license issued by the respective state regulator, and confirmation of an operating record without pending investigations or inquiries. 2. Economically validated hydrocarbon volumes, (those reserves that would be produced and sold without the benefit of the carbon credits mechanism). This will be verified by an accredited engineer working under the third-party auditor, and who will certify the reserves report. This report will validate all claimed economic volumes based on standard regulatory parameters, and thus can be reasonably expected to be produced, and are considered additional emissions avoided due to the granting of carbon credits. 3. A copy of the documents outlining the legal framework, designating target reserves as off limits for production for a minimum, 50 years. This contract will be tied to the mineral ownership title, thus the current and any future mineral owner forgoes the right to extract the targeted resources in exchange for just compensation proportional to their royalty claim or other compensation as negotiated with the project operator. This will legally bind the permanence of the avoided emissions by preventing future targeted development of the impacted resources. 4. A submission of documentation validating the project owner’s best technical justification that oil and gas volumes claimed for carbon credit issuance will remain in the reservoir. These volumes will not migrate to any offset wells or to the surface through any open flow conduits. This claim will be validated through submission of a comprehensive technical report corroborating such a claim, and will be independently verified by a licensed third-party technical body.

Execution The execution of the abandonment and reclamation activity will be specific to each project and must conform to the regulatory guidelines of the jurisdiction. The process flow is described, relative to regulatory obligations and verification submission requirements. The platform also requires documented proof of appropriate notification and provision of information to such state, local, and Tribal authorities that have authority over drilling activities. This enables such authorities to impose appropriate restrictions on subsequent drilling activities that may penetrate the injection and confining zone(s). 5.1. Plugging and Abandonment (P&A) Regulatory Process  The plugging and abandonment process varies by state and is specified by the respective resource governance organizations. The correct execution of this procedure is independently verified by the state oil and gas regulatory bodies. As part of the project submission process, the project operator is required to submit a P&A permit issued by the state regulator for each well intended to be abandoned according to the project permanence documentation. The general process to plug and abandon a wellbore is described: 1. Make decision to P&A well. 2. Identify water strata and hydrocarbon production horizons to ensure cement plugs are set to isolate each. 3. Notify surface landowners. 4. File a P&A plan with the state (e.g., Colorado Oil and Gas Conservation Commission –COGCC in Colorado) regulatory agencies. 5. Agencies may provide feedback and edits, and ultimately grant approval and plan permits for a specific period. 6. Find a state approved cementer. 7. Secure cement supply and rig for a specific date within the valid permit period. 8. Upon scheduling the operation for a specific date, inform regulatory agencies at least 48 hours prior to start of operations; they will engage an observer to witness plugging execution. 9. Project owner should follow all operations and requirements set forth by the regulator for all conditions to safely and permanently abandon the wellbore according to the approved and permitted execution plan. 10. State or federal observers witnessing the plan execution certifies the P&A if all criteria are attained. 

Monitoring The project owner must submit a monitoring plan designed to validate the proper reclamation of the project area and the permanence of the reserves. The primary means of determining the permanence of the claimed reserves is to monitor any new activity for potential development after verifying that all extraction activity has been abandoned per the project plan. Minimum monitoring requirements: 1. Observation of production and development activity from offset operators that might be targeting or impact credited reserve volumes (see Section 6.1). 2. Progress of land reclamation (see Section 6.2). Activity Monitoring of Project Area The project owner shall monitor the absence of new extraction activity in the project area for the duration consistent with requirements for land reclamation by the state regulator. It shall also validate that no new permits for resource extraction within project boundaries, by project operator, landowner, or any other operator have been submitted. Lack of activity can be proven by submitting a list of permit filings for the project county from the state oil and gas regulator, with no new submissions on any leases within the project boundary. Should the county list show permitting activity for any project lease, the project must answer the following three questions: 1. Is the permit still active and valid? 2. Is the permit location inside the specific project boundary? 3. Will the activity, if permitted, have any tangible interaction with the subsurface zones targeted by the project (i.e., proposed development or drill through zones produced by the retired project wells)? Should any of the answers be Yes, then a report must be submitted detailing why the permit(s), if approved, will not have a material impact on the credited reserves.

Verification All the elements and provided information about the offsetting project are independently verified based on the source and nature of information. 7.1. Third-Party Verification of Project An independent, state-accredited organization will verify the claimed emission volume abatement and credibility of the geologic permanence documentation of the project in a verifier report and certification statement submitted through the ZeroSix platform. At minimum, the specific engineers working within these organizations will hold a current state engineering license in a relevant engineering discipline. The third-party verifier will review all submitted documents pertaining to geologic permanence, carbon content, and reserve volumes. Each relevant document will be verified independently through the ZeroSix platform. If the verifier has any questions or concerns about the quality of the claims or documentation they can revert back to the project owner to provide additional documentation or a revision of the project. Once all documents are consistent and meet the requirements laid out in this protocol the final certification can be issued.

Reporting 8.1. Initial Project Execution The following list of documentation will be submitted to the digital solution and will be publicly available through the decentralized InterPlanetary File System (IPFS): Table 4: Documentation requirements and issuing entity. The submission and verification of the necessary documentation, and successful execution of the digital signature will constitute all initial reporting requirements.

United States, CA, Southern California, 00000

N/A

ZeroSix LLC

NA

Yes. To be provided once NDA is in place with prospective buyer

Yes

ZeroSix LLC

ZeroSix

Post P&A Leak Test and Measurement - Huntington Beach Oil Code Section 15.32.090.3.2: gas test equipment shall be calibrated within the previous 12 months, methane levels at the top plate shall not exceed site specific background levels. Methodology follows industry best practices.

Available upon request

Digital Asset & Fraud Insurance available upon request

N/A

Permanent Oil and Gas reserves containment of of 2 permanently abandoned and sealed oil and gas wells in Southern California

A publicly traded oil and gas company has abandoned and sealed (plugged) in two (2) oil and gas wells in the Fort Apache area in Huntington Beach, CA, resulting in the abatement of 303,494 metric tons of CO2 emissions (with a 1% buffer). The emission abatement uses the ZeroSix Production Reserves Offset Protocol v.1.0, resulting in proven reserves of 561,000 barrels of oil and 189 million cubic ft. of gas. The reserve volume calculations follow the long established SEC Final Rule regulations for publicly traded oil and gas companies. The permanence requirements reflect current regulations of carbon sequestration, including the California Air Resources Board’s (CARB) Carbon Capture and Storage (CCS) protocol and the United States Environmental Protection Agency (EPA) Class VI permit requirements. The plugging and abandonment of the wells is certified the Geologic Energy Management Division (CalGEM) of the State of California Conservations Department. The project and reserves are also independently verified by Ryder Scott, an independent third-party oil and gas engineering company, and carbon credits resulting from this project are in the process of being rated by BeZero.

N/A

Alberta Quantification Protocol for Conservation Cropping (CCP) (Version 1.0.)

T-CC...6865

N/A

GHD Limited

Carbon Credit

No-till

One-time

External registry

Private network NFT (Triangle)

As Produced

CSA Clean Projects Registry

The protocol specifically quantifies greenhouse gas emissions reductions from the following three activities: New carbon stored annually in agricultural soil; Lower nitrous oxide emissions from soils under no till management; and Associated emission reductions from reduced fossil fuel use from fewer passes per farm field. Shifting from any type of fallow (chemfallow, tilled fallow or a combination of chemfallow and tilled fallow) to continuous cropping also increases carbon stored in the soil, further reducing the greenhouse gas emissions footprint of the farm. This quantification protocol is written for project developers and farm operators implementing conservation cropping offset projects in the Dry Prairie and Parkland ecozones. Familiarity with and general understanding of conservation cropping farming practices required. The Farmers Edge Smart Carbon Soil Carbon Program, which applies the CCP protocol, creates soil sequestration in the form of Soil Organic Carbon by encouraging the continued use of no-till farm practices. The Digital-Measurement, Reporting & Verification system for capturing the records and evidence required for the Conservation Cropping Protocol used are collected within the Farmers Edge FarmCommand platform and associated MRV. FarmCommand is a GIS-based agronomic services and logistics management platform originally designed with grower (farmer) data collection for better agronomic decision making. This includes digital field borders, crop productions records, farm machinery telematics and crop harvest to storage and delivery tracking. The MRV portion adds protocol specific GHG calculations, "big data" storage and flexible reporting for users and independent verification companies.

CCP Version 1.0

Quantification of the reductions, removals and reversals of relevant sources and sinks for the GHGs will be completed using the methodologies outlined in the Alberta CCP protocol. This project will not consider the summer fallow reduction flexibility mechanism for any participating farms. The emission reduction quantification and calculation methodology for this project is described in detail. Emission reduction quantification formula used for this project according to the CCP, referring to Section 4.1, (page 30) of the Alberta CCP Protocol, the quantification approach is outlined below.

Emission Reduction = Emissions Baseline – Emissions Project Emissions Baseline = Emissions Energy Use + (Emissions Carbon Sequestration X Reserve Discount Factor) + Emissions Nitrogen Emissions Project = Emission Reduction = Emissions Baseline – Emissions Project Emissions Baseline = Emissions Energy Use + (Emissions Carbon Sequestration X Reserve Discount Factor) + Emissions Nitrogen Emissions Project = 0 WHERE: Emissions Baseline = sum of the emissions under the baseline condition • Emissions Energy Use = component of emissions change under source/sink B9 Herbicide Production to source sink P9; and emissions change under source/sink B14 to P14 for Field Operations (Table 8 below) • Emissions Carbon Sequestration = carbon component of emissions change under source/sink B13 Soil Carbon Dynamics to P13 Soil Carbon Dynamics (see Table 8 in link below) • Sequestered Carbon Reserve discount factor = Factor to account for reversals of carbon sequestration due to tillage events. • Emissions Nitrogen = component of emissions change under source/sink B13 Soil Nitrogen Dynamics to P13 Soil Nitrogen Dynamics (see Table 8 in link below) Table * found in: https://open.alberta.ca/dataset/b99725e1-5d2a-4427-baa8-14b9ec6c6a24/resource/db11dd55-ce34-4472-9b8b-cb3b30214803/download/6744004-2012-quantification-protocol-conservation-cropping-april-2012-version-1.0-2012-04-02.pdf

N/A

N/A

Live

None

2018 to 2021

706.48

See Above

183 growers

129286.0000

N/A

N/A

N/A

N/A

N/A

Farmers Edge

The performance standard baseline establishes net coefficients implementing the project activities in the protocol region, adjusted by the level of adoption of No Till and Full Till in the region. This approach addresses the ISO 14064-2 principle of additionality (on a proportional basis), conservativeness and minimizes leakage. The NET coefficients have been calculated according to Section 2.5 of the Environment Canada and Agriculture-Agri Food Canada seed document from 2006 called the Tillage System Default Coefficient Protocol (Haak, 2006). Given that the Conservation Cropping Protocol and its predecessors, the Tillage System Management protocol in Alberta and the Technical Seed Document in the federal protocol development process (circa 2006), the performance standard baseline has had multiple reviews by technical experts, stakeholders, government and public input, a barriers assessment on alternatives is not warranted. The approach to additionality applied in the Alberta government approved protocols (i.e., CCP) is an accepted approach in many circles – called ‘proportional or regional’ additionality. This performance standard baseline allows project developers (Farmers Edge) to use this protocol to quantify annual emissions reductions based on annual, incremental increases in soil carbon adjusted (discounted) for 2006 sector level adoption. This discounting approach allows all farm operators practicing conservation tillage farming to participate in conservation cropping offset projects, irrespective of the adoption date of the practice change. It assumes all carbon stored prior to 2001 is discounted from 2006 levels and only the new, incrementally stored carbon is eligible for offset credits. As adoption levels of no till increase, the potential for new carbon sequestration is reduced; the associated emission reduction coefficients and the resulting offset credit opportunities are also reduced. Additional information on adoption levels, emission factor coefficients and corresponding adjustment factors is available in the Technical Seed Document for Conservation Cropping (Version 1). Alberta reviewed the Clean Development Mechanism’s (CDM) barriers assessment tool, which was used to assess additionality on a project-by-project basis. Alberta adopted similar tools but has chosen to assess additionality at a sector level evaluated during protocol development. Section 3.1 of the Technical Guidance for Offset Protocol Developers (January 2011) explained additionality requirements for offset protocols being used in Alberta. Protocol development must demonstrate the project has one or more technical, social, or financial barriers that limit adoption of the project. New, innovative projects and activities may face more barriers and score higher on a barriers assessment than well-developed technologies. If it is determined that barriers do exist, the protocol developer must assess sector level adoption to assess business as usual practices. Notionally, business as usual is defined as approximately 40 per cent adoption. If 40% or more of the sector have adopted the activity, the perceived barriers identified initially are project specific, but the activity in general does not need incentive through the offset program to advance. Protocols will generally not be developed for activities with greater than 40 per cent adoption unless specific situations exist as deemed acceptable by Alberta. Through its tillage system management, and new conservation cropping protocol, Alberta recognized the benefit of maintaining and increasing soil carbon sequestration by incenting conservation tillage farming practices such as no till. Science demonstrates that no till practices must be maintained for a period of 20 years for soils to reach saturation and move to a steady state. Equilibrium is the point where soils no longer absorb new, incremental carbon.

To address permanence, the project tracks a pool of emissions allocated to a Buffer Reserve Pool. A buffer reserve discount factor is applied to every tonne of sequestered carbon calculated under this protocol to account for known rates of reversals based on historical trends and expert opinion. These tonnes are held by the Project Developer to drawdown in the event of a reversal. The reserve discount factor accounts for the average risk of reversal across all farms within a given protocol region and ensures conservativeness in crediting.

Shifting from conventional farming to conservation cropping increases carbon sequestered in the soil in the Parkland (Black and Dark Gray Chernozemics, and Gray and Dark Gray Luvisols) and Dry Prairie (Brown and Dark Brown Chernozemics) regions of western Canada. Conservation tillage (no till and reduced till) increases soil carbon accumulation and results in reduced lower nitrous oxide (N2O) emissions from less soil disturbance. In the case of no till, fewer tillage passes over a farm field also reduce fossil fuel emissions from farm equipment, further lowering the greenhouse gas footprint for the farm. Baseline: Under a baseline scenario, the conventional farming practice is the full till farming operation. As mentioned, mechanical disturbances release soil carbon into the atmosphere. Project: Under this project, the project condition for the tillage system management is the use of no till systems as defined in Table 1 of the CCP protocol, which results in reduced disturbance of the soil, reduced soil organic carbon decomposition and loss of terrestrial carbon stores relative to conventional tillage systems (i.e.: the baseline condition). No till systems also result in a reduction in the fossil fuel emissions from fuel consumed in conventional, full till farming operations. In the case of the drier soils (i.e., Dry Prairie soils), there is also a reduction in nitrous oxide emissions from agricultural soils under no till relative to full till farming, which have been included in the coefficients provided in this protocol.

Sequestered carbon is a reversible activity. Tillage and other types of soil disturbances can cause previously sequestered carbon to be re-released to the atmosphere. This protocol manages the risk of reversal through a reserve discount factor (sequestered carbon reserve) applied to sequestered carbon to account for known rates of reversal occurring at a regional scale. This reserve factor discounts sequestered carbon by 7.5 to 12.5 per cent for the Dry Prairie and Parkland regions respectively according to the likelihood of reversals on a sector wide basis. Reversal events affecting less than 10 per cent of a total field area are considered to be a normal part of farm operations. Examples of these reversals include discretionary tilling to fix ruts or to manage weeds. Reversals under 10 per cent must be documented in the offset project report, but do not affect greenhouse gas emission reduction calculations. Reversal events that affect more than 10 per cent of a field area are considered beyond business-as-usual activities for farm operations. Reversals over 10 per cent must be documented in the offset project report, and affect fields must be removed from the project condition for the vintage year affected by the reversal. Examples of reversals may include re-seeding events and manure incorporation. Greenhouse gas emission reductions quantified using this reserve discount are considered permanently retired against future liabilities. Discounting for future liability ensures that offset credits quantified under this protocol are given to permanently sequestered carbon and not to carbon that may be released to the atmosphere as part of normal farm operations (e.g.: discretionary tillage for weed management). Alberta Environment and Water will do a periodic assessment of reversals against permanent reductions in the sequestered carbon reserve account. More information on the sequestered carbon reserve is available in Section 5.0 of the technical seed document

Protocol: Annual, incremental carbon sequestered in the soil through no till farming practices is eligible to generate offset credits starting, January 1, 2012 ending December 31, 2021. Project Report: Conservation Cropping practices such as no till are not required in any jurisdiction included in this project. The lands included in this project do not have any relevant legislative, technical, economic, sectoral, social, environmental, geographic, or site-specific requirements to adopt this activity. Project Report: This GHG emission reduction assertion was quantified using a quantification methodology considered to be industry best practice; • The project is based on an Alberta government approved quantification methodology, the Alberta CCP protocol, developed following the ISO 14064-2:2006, as required by the CSA CleanProjects Registry; • The GHG assertion has been verified by an independent third-party; • There are no regulations requiring the practice or prohibiting the use of the practice in the included jurisdictions. • The project is not currently subject to any climate change or emissions management legislation Provincially or Federally in Canada; • GHG emission reductions generated by this project are not listed on any other GHG reduction registry in Canada or internationally; • The project has not received any public funds in exchange for GHG emission reductions (e.g., offsets) resulting from this project; and • All environmental attributes generated by the project, including any GHG emission reduction benefits, are owned solely by Farmers Edge.

N/A

The Monitoring Plan for Farmers Edge Smart Carbon Soil Carbon Project 2 integrates very well with Farmers Edge regular customer procedures for agronomic consulting and services. Data collection for monitoring purposes follows Farmers Edge processes and data systems already available (Please refer to Smart Carbon Program Standard Operating Procedure documents for details). Customer facing staff ensure data collection processes are executed and tracked in Farmers Edge data systems, FarmCommand, as well as SharePoint system and CRM system. Figure 6 below outlines the Farmers Edge project Data Flow. Field staff who work directly with customers, which includes Solution Sales Specialist, Precision Agronomists, Precision Technicians, Client Success Managers and Administrators, each has a unique, secure login to the FarmCommand system. All additions and changes to data in the FarmCommand are logged by person so all data and documents can be tracked back to the person who last handled it. Also, many Farmers Edge Agronomists, Precision Agronomists and Solution Sales Specialists are certified CCAs and/or Professional Agrologists (P.Ag.). Designations are noted in system for review purposes. Customer farm data is input into the FarmCommand system at two levels, Farm or Field. Farm level documents such as signed emissions contracts and Customer Service Agreements are collected during customer sign-up or renewal process, captured as a DocuSigned pdf, or scanned to pdf format, and uploaded to the CRM system. Our agronomic services contracts last four or five years. Then, each year, technical field staff work with the grower to help develop the annual crop plan for each field, which then forms the core of the agronomic data gathering system that is FarmCommand. Field level data is mostly passively collected and gets monitored by the Precision Technicians and Precision Agronomists and any system issues are corrected. Field specific details not available electronically such as crop insurance and irrigation receipts are collected by the Tech’s and Agronomists. Most Field level data is “monitored” or collected electronically using a Farmers Edge proprietary system, the CanPlug. The CanPlug system is a telematics-based data gathering device supplied for customer’s tractors, combines and sprayers. The CanPlugs monitor the machinery data systems, harvest the GPS encoded data from the in-cab and attached machinery controllers (computers) and sends the data over cell networks to our cloud database. This data is processed and becomes available information in the FarmCommand system. As a backup to this system, controller data is collected by our Precision Agronomists & Technicians from the in- cab controllers and then uploaded to FarmCommand. The electronically collected data includes much of the crucial information for detailed agronomic consulting and CCP GHG calculations. Information tracked includes tillage activity from As Applied seeding and/or fertilizing application dates, the machinery involved and the location of each event in all zones of every field. Monitoring for CCP specifically happens through our consulting process with farm customers: • The initial crop plan is prepared in consultation with the farmer. • Agronomists prepare fertility recommendations before fertilizing and seeding events. • As Applied activity is gathered electronically during seeding by CanPlug and directly immediately post-seeding by the Precision Agronomists and Technicians. • After spring seeding the crop plan is reviewed by an Agronomist at the Field Level. Any discrepancies or missing information is addressed with the Farmer. Any electronic gathering or processing issues are addressed with the data management development team and field staff. • It should be noted that pre-seeding and pre-harvest farm visits are done by Precision Technicians and/or Agronomists to supply the machinery ready data files for fertility and other prescriptions and to ensure the CanPlugs and other machine data systems are operational. Once operational, prescriptions can also be sent to the seeding unit controller via CanPlug. • A final post-harvest review is done by an Agronomist at Field & Farm Level to ensure each Field will qualify for CCP inclusion and that all Field & Farm Level documentation is in place for the GHG calculation and eventual assertion.

Farmers Edge Inc. (Farmers Edge) retained GHD Limited (GHD) to undertake a verification of the Greenhouse Gas (GHG) emission reductions (Offset) for the Farmers Edge Smart Carbon Soil Carbon Project #3 (Project), located in various locations across Manitoba, Saskatchewan, and Alberta for the period from January 1, 2018 to December 31, 2021. The Project is registered with the CleanProjects® Registry (Registry). The verification will be conducted in accordance with the ISO 14064. The project is defined by the implementation of a direct seeding regime. The quantification of reductions is based on a protocol approved for use under Alberta’s Regulatory system – the Conservation Cropping Protocol (CCP) – which quantifies reductions associated with a change from conventional tillage to no-till farming. This protocol is used to form the basis of quantification. It is supported with additional modelling completed during an Ontario Protocol Development Process – which took the existing CCP and developed factors for other jurisdictions across Canada. No till adoption levels are based on 2006 Census of Agriculture tillage adoption rates, as per the Alberta CCP. GHD has prepared this Verification Report for Farmer’s Edge and the Registry. Farmer’s Edge was responsible for the preparation and fair presentation of the GHG Assertion in accordance with the criteria and engaging with a qualified third-party verifier to verify the GHG Assertion. GHD's objective and responsibility was to provide an opinion regarding whether the Project’s 2018-2021 GHG Assertion was free of material misstatement and that the information reported is a fair and accurate representation of the operations for the reporting period accurate and consistent with the requirements of the protocol and the registry, and associated criteria. The criteria used by GHD for the verification of the GHG Assertion is detailed in Section 2. GHD completed the verification of the GHG Emissions Report in accordance with ISO 14064-3:2006. GHD completed the verification to a reasonable level of assurance. Farmer’s Edge reported 117,645 .5 tonnes CO2e as the total attributable emissions for 2018-2021 for the Project. This includes the GHG emissions resulting from operating conditions from January 1, 2018 through December 31, 2021 (reporting period). The quantitative aggregated magnitude of errors, omissions, and misstatements is detailed in Section 3.2. Based on verification procedures undertaken to a reasonable level of assurance, it is GHD’s opinion that the GHG Assertion is materially correct and is a fair and accurate representation of the Project’s total attributable emissions for the reporting period; and that the GHG Assertion was prepared, and emissions were quantified in accordance with the requirement of Protocol and the Registry. Information in the GHG Assertion which was not reported or quantified in accordance with the Protocol but was corrected during the verification process includes: - The farming area used to calculate offset credits were updated to be equal or less than land title area - Update project report to include coefficients up to 4 decimal places

Initial project execution was in 2021 and 2022 based on farmer field-by-field activities from January 1, 2018 to December 31, 2021.

1341 Dugald Road, Canada, MB, Winnipeg, R2J 0H3

-97.05855772731057

49.88636458211731

N/A

Farmers Edge

N/A

See Verifier Report (attached)

Yes

Farmers Edge

Farmers Edge Smart Carbon Program Standard Operating Procedure

Farmers Edge Smart Carbon Program Standard Operating Procedure

N/A

N/A

N/A

Farmers Edge Smart Carbon Soil Carbon Project 3 (Project Identifier: 3587-1296)

The project is defined by the implementation of a direct seeding regime. The quantification of reductions is based on a protocol approved for use under Alberta’s Regulatory system – the Conservation Cropping Protocol (CCP) – which quantifies reductions associated with a change from conventional tillage to no-till farming. This protocol is used to form the basis of quantification. It is supported with additional modelling completed during an Ontario Protocol Development Process which took the existing CCP and developed factors for other jurisdictions across Canada. No till adoption levels are based on 2006 Census of Agriculture tillage adoption rates, as per the Alberta CCP. This is an aggregated CCP project. All sub-project farmlands are located across Western Canada (BC, Alberta, Saskatchewan, and Manitoba)The Project is comprised of 183 growers, and includes 1,215,280 acres of land in Alberta, Saskatchewan, and Manitoba. A total of 117,644 tons of carbon offsets have been verified and a total of 11,642 tons have been quantified and are held in a Reserve Pool by the Project Developer. The Project was developed under the the Alberta Conservation Cropping Technical Seed Document. This is the Tillage System Default Coefficient protocol which quantifies the greenhouse gas emissions offsets associated with a change from conventional (full) tillage to reduced tillage or no tillage in Canadian agricultural soils. It is used in the Alberta Conservation cropping protocol to develop the net coefficients for use in Alberta. In this project, this calculation is used to adapt for the inclusion of regions across the Prairies. This project is quantified according to the CCP protocol - a robust and transparently developed methodology based on ISO 14064-2 and approved for use in Alberta’s Offset Emissions System. The methodology relies on Canada’s National Emissions Inventory methodology for soil organic carbon change for No-Till projects. The CCP lays out all the Sinks, Sources and Reservoirs (SSRs) as well as the data and methodologies required to be eligible under the protocol. Farmers Edge has chosen the CCP protocol over other methodologies because the CCP protocol has undergone technical, stakeholder and public review as part of its development, with the first iteration in 2007 under the No-Till protocol, and then multiple improvements over time since then (at least 7 revisions to improve implementation in the Alberta Offset System). The CCP protocol has been used by many project developers to quantify reductions associated with CCP projects (almost 17 million tons to date on the AEOR). The technical seed document for the original Alberta No-Till protocol was developed under a Federal-Provincial-Territorial working group in 2006 for all of Canada, following the ISO 14064 Part 2 process-based standard. In late 2006-2007, the first iteration of the Tillage System Management protocol was approved for use as a compliance protocol by the Government of Alberta, under the Alberta Offset System protocol development process. The protocol development process included a multi-step stakeholder review process consisting of a technical expert review, a broader stakeholder review process and a public posting period, all of which were managed by the Government of Alberta. The protocol is a well-established quantification protocol applicable to soil conservation projects in Canada and was therefore considered to be the best available quantification protocol to apply for this Project. To ensure broader applicability of this protocol across Canada, the project is quantified according to the approved methodology in the CCP. but with a couple modifications to the existing methodology. These modifications enable a broader geographic scope while ensuring all reductions and removals are quantified in accordance with the CCP and ISO principles, and Canada’s National Emissions Inventory methodology. Modifications to the quantification methodology outlined in the CCP are discussed in Section 2.8 of the attached project report. Sources, Sinks and Reservoirs (SSRs) considered to be relevant and included for quantification under the Protocol are defined in Section 4 of the attached project report, including justification for the exclusion of SSRs identified in the life cycle elements of the project and baseline conditions. SSRs for the project condition are summarized later in this document

3587-1296

BCarbon Registry

T-CC...6898

N/A

Trace Pro LLC

Carbon Credit

Oil and Gas Well Capping,Avoidance

One-time

D-MRV / Methodology

Private network NFT (Triangle)

As Produced

Triangle

This Protocol issues carbon credits for plugging eligible wells using historical production decline curve analysis combined with a leak estimation model.

Version 2.0

The carbon credit calculation parameters in the BCarbon Methane Capture and Reclamation Protocol are designed to ensure conservative, transparent, and scientifically grounded estimates of avoided emissions. The process begins with establishing baseline emissions, defined as the methane that would have leaked from wells in the absence of the project, using production decline curve analysis and a leak probability model. Reservoir content and leak estimates are then translated into carbon dioxide equivalent (tCO2e) using the latest IPCC global warming potential values. Pre-plugging emissions set the business-as-usual benchmark, while post-plugging emissions are assumed negligible if wells are sealed correctly and verified by regulatory authorities. At the same time, project emissions (from materials, fuel use, and plugging activities) are deducted from gross reductions to arrive at net climate benefits. An uncertainty discount of 5% is applied as a safeguard against plug failures. The resulting net emissions reduction forms the basis for credit issuance, with 80% of credits released after project completion and validation, and the remaining 20% contingent on successful verification one year late

The protocol calculates carbon credits by comparing baseline emissions (methane that would have leaked without intervention) to project emissions (from plugging activities). First, methane available to leak (MAvail) is estimated using decline curve and leak probability models. This is converted to CO₂ equivalent (Est_tCO₂e) with density and GWP20 factors. Baseline emissions (BE) are capped at 63,000 tCO₂e per well. Post-plugging emissions are assumed negligible. Project emissions (TPE) from materials, fuel, and operations are deducted, and an uncertainty discount (5%) is applied. The net emissions reduction is: N = (G – TPE) × (1 – D) where G = gross avoided emissions (BE), TPE = project emissions, and D = 0.05. Issued credits equal N

None

N/A

Live

None

he baseline emissions measurement cycle is defined as the projected methane emissions that would occur from a well if it were not plugged. This baseline is established before plugging and covers both current leaks and potential future leaks. To calculate it, developers must: Estimate the reservoir methane available to leak using production decline curve analysis (minimum 36 months of production history, smoothed with statistical adjustments). Apply a leak probability model that forecasts emissions over time under different leak states (large leak, restricted leak, or no leak). Convert the methane volume (MAvail) into tCO₂e using methane density and the 20-year Global Warming Potential (GWP20, currently 84). Cap baseline emissions at 63,000 tCO₂e per well, unless BCarbon approves a higher figure case by case. This cycle essentially represents a business-as-usual trajectory of well emissions over a 20-year crediting horizon, against which the project’s avoided emissions are measured.

N = (G – TPE) × (1 – D) where G = gross avoided emissions (BE), TPE = project emissions, and D = 0.05. Issued credits equal N

N = (G – TPE) × (1 – D) where G = gross avoided emissions (BE), TPE = project emissions, and D = 0.05. Issued credits equal N

17

321068.0000

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N/A

N/A

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N/A

N/A

A well is Additional if, at the time of plugging, no person or entity has a firm, non-extendable legal obligation to plug it either (a) by law, regulation, statute, court order or other government requirement, or (b) by private contract (e.g., pursuant to a lease, service, or other agreement with a third party). No credits will be granted for a well that is included in a project registered under another carbon crediting protocol, whether with BCarbon or another carbon registry.

The purpose of the Protocol is to incentivize the permanent capture of methane present in hydrocarbon reservoirs associated with leaking abandoned oil and gas wells and the reclamation of related surface sites.

Accepted well types: a) On-land or onshore wells (over freshwater) registered with the appropriate Local Regulator as oil or natural gas producing wells; and b) Only Regulatory Compliant wells are accepted under this protocol – see section 3.5 below

The baseline reference case is a scenario where the methane being emitted from target wells into the atmosphere is not restricted by the Project. The baseline compared against the post-plugging calculation is established by the predicted emissions that would have been released without the Project Developer’s implementation of the MCR Project. Pre-plugging reservoir estimation is required to obtain an estimate of the well’s business-as-usual, Baseline Emissions. Pre-plugging reservoir estimates shall approximate current active leaks as well as future potential leaks by estimating how much methane is in the well’s reservoir, and how much methane will leak out over time. The method required for estimating reservoir contents is the standard industry decline curve analysis, supplemented with additional gas composition sampling, if needed. The method required for estimating leaks over time is the leak probability model. For wells without a documented history of natural gas production, BCarbon may entertain alternative methods of estimating reservoir contents and future leak rates. Project Developers with such Projects should present alternative methods to BCarbon for eligibility consideration.

Process of Validation, Approval, Development, and Issuance of Carbon Credits: 1. Developer submits Provisional Project Plan to BCarbon 2. BCarbon reviews Provisional Project Plan for completeness 3. BCarbon notifies Project Developer of application completeness 4. BCarbon selects and contracts with a third-party validator to review the Provisional Project Plan. Project Developer is responsible for such validation costs and will be notified of the estimated costs of validation prior to an agreement. Validator reviews and returns a sealed Validation Certificate to BCarbon, 5. BCarbon issues carbon credits for Project, subject to final Total Project Emissions figures, such carbon credits to be held on the BCarbon Registry within a Lock-Box Account to be released to the appropriate Project Developer account upon BCarbon receiving the Final Project Plan with final Total Project Emissions figures 6. Project Developer submits Final Project Plan to BCarbon 7. BCarbon receives Final Project Plan and reviews it with a third-party validator, following the same contracting process as outlined for the Provisional Project Plan. Once the Final Project Plan is approved by BCarbon and the validator, BCarbon automatically releases eighty percent (80%) of the carbon credits from the Lock-Box Account to the appropriate Project Developer’s account. The remaining twenty percent (20%) of the credits will be released subject to the Second Post-Plugging Test confirming that the well remains plugged and that fugitive methane emissions are not present.

The carbon emissions accounted for during the production activities of a Project, measured in tons of Carbon Dioxide Equivalent (tCO2e), to be offset against the prevented emissions resulting from Project execution.

The protocol issues credits for a 20-year period, but only measure at year 0 and year 1. After that, neither BCarbon nor the Project Developer are required to verify if emissions are still zero. As an alternative, an official notice/certificate confirming that that a well has been effectively plugged and not leaking from the state in which the oil wells are located should be available.

BCarbon receives Final Project Plan and reviews it with a third-party validator, following the same contracting process as outlined for the Provisional Project Plan. Once the Final Project Plan is approved by BCarbon and the validator, BCarbon automatically releases eighty percent (80%) of the carbon credits from the Lock-Box Account to the appropriate Project Developer’s account. The remaining twenty percent (20%) of the credits will be released subject to the Second Post-Plugging Test confirming that the well remains plugged and that fugitive methane emissions are not present.

The Protocol is designed to operate within a digital measurement, reporting, and verification (“digital MRV” or “d-MRV”) framework enabling automated, real-time data onboarding and data processing, quantification, and verifications. The BCarbon d-MRV framework is integrated with a registry that tracks the complete lifecycle of certified projects from project approvals, and issuance, serialization, transferring, and retirement of credits.

4633 FM RD 717 N, Breckenridge, TX, East Gate Entrance, United States, TX, Stephens, 76424

-98.9028663

32.7621614

N/A

Water Energy Forward

N/A

See attached verification report

None

N/A

N/A

N/A

N/A

N/A

N/A

N/A

The Walker Ranch (BCarbon Methane Capture and Reclamation CBX-001-17) Project is a targeted methane mitigation initiative focused on permanently eliminating emissions from neglected and abandoned oil and gas wells. The project involves the plugging and reclamation of 17 methane-leaking wells, ensuring the complete cessation of emissions and the ecological restoration of the surrounding land (project co-benefits).

CBX-001-17

Verra Verified Carbon Standard

T-CC...6891

N/A

Available under NDA

Carbon Credit

N/A

Recurring

External registry

N/A

As Produced

Northern Trust - Custodian

The VM0044 methodology quantifies the carbon dioxide removals resulting from the conversion of waste biomass into biochar at new biochar production facilities. Eligible soil and non-soil applications include crop and grasslands, and emerging products such as biochar-amended concrete and building materials. This methodology is applicable globally. The project also applies the Verra VCS VM0042 Improved Agricultural Land Management, v2.1 protocol for additional CO2 reductions. This methodology quantifies the greenhouse gas (GHG) emission reductions and soil organic carbon (SOC) removals resulting from the adoption of improved agricultural land management (ALM) practices. Such practices include, but are not limited to, reduced tillage and improvements in fertilizer application, biomass residue and water management, cash and cover crop planting and harvesting practices, and grazing practices.

VM0044

The Dynamic Carbon Credits (DCC) project deploys a proprietary, multi-pathway biological Direct Air Capture (DAC) system that integrates advanced biotechnology, microbial soil enhancement, and biochar-based carbon storage. The base formula is: Total C sequestration = Direct Plant Sequestration + Biochar C + Bacterial Enhancement + GHG Reductions.

DCC uses IPCC international panel of climate change, 2021 AR6 version. This converts CH4 Methane to eCO2 mTonnes at a 29.8:1 ratio and N2O to eCO2 mTonnes at 273:1 ratio as stated in the Life Cycle Analysis verified by Dr. Majid Hussain and VVB from Enviance.

None

N/A

Live

None

Daily measurements taken using a sample probe during the 16-20 week growing cycle

(3) Emission: CO2, CH4, NOx (4) Non-Emissions measured in the soil: Moisture, PH (acidity), Root Activity, Temperature

Tons CO2, CH4, NOx (then CH4 is converted to equivalent metric tonnes COs aka eCO2 at a 29.8:1 ratio, N2O is converted to equivalent metric tonnes CO2 aka eCO2 at a 273:1 ratio) per IPCC Int'l Panel Climate Change ARC in 2021CY

Bannister Township, MI (361 acres)

2988442.0000

N/A

N/A

N/A

N/A

The associated measurement parameters in the Dynamic Carbon Credits project are structured to ensure accuracy, transparency, and verifiability of carbon removals across soil, biomass, and atmospheric monitoring systems. Parameters include soil organic carbon (SOC) levels measured annually to 60 ft depth via dry combustion; GHG fluxes (CO₂, CH₄, N₂O) monitored weekly during the growing season using Picarro G2508 analyzers; and biomass yield measured per harvest through calibrated scales and laboratory-verified carbon content (47% of dry mass). Biochar application is recorded twice per cycle with weight tickets, while daily soil conditions (temperature, moisture, pH) are captured via IoT sensors. Supporting factors such as biochar carbon content (70–80%), stability (85%), bacterial enhancement rate (90 tCO₂e/acre/lifecycle), and baseline SOC (1.2% ±0.15%) are validated through ISO-accredited laboratories. These parameters collectively underpin the project’s MRV framework, ensuring robust credit issuance and third-party verification

The Dynamic Carbon Credits project implements a hybrid carbon removal method that combines nature-based and engineered solutions under ISO 14064 and Verra methodologies. The approach integrates high-biomass perennial crop cultivation to capture atmospheric CO₂, enhanced by a proprietary bacterial soil inoculation that boosts root biomass and stabilizes soil carbon. Harvested biomass is processed into biochar, with an 85% permanence factor, applied twice per growth cycle to lock carbon in soils and improve fertility. Additional removals arise from N₂O and CH₄ emission reductions, quantified through direct flux monitoring. The methodology applies a cradle-to-cradle life cycle boundary covering upstream, midstream, and downstream processes, ensuring leakage prevention, permanence assurance via a 15% buffer pool, and verification through accredited VVB audits. This integrated method enables large-scale, durable carbon sequestration with both immediate and long-term climate benefits

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

United States, MI, St. John, 48616

43.0011

84.5592

Eastern Standard Time

Dynamic Carbon Credits LLC

The Dynamic Carbon Credits project establishes parameter values through validated field trials and accredited laboratory analysis to ensure conservative and reliable crediting. Biochar applied in the project has a carbon content of 70–80% with a stability factor of 85%, supporting long-term storage. Soil organic carbon (SOC) at baseline is 1.2% ±0.15%, with verified annual increases under project activities. The proprietary bacterial inoculation demonstrates an enhancement rate of 90 tCO₂e per acre per lifecycle, while plant germination rates average 94%. Global Warming Potential (GWP) factors applied include CH₄ at 29.8 and N₂O at 273 (100-year values from IPCC AR6). These parameter values, together with calibrated biomass yields and direct gas flux monitoring, provide the quantifiable basis for calculating net removals and issuing verified carbon units (VCUs)

Following a thorough review of all project information, procedures, calculations based on the results from the LCA report, and supporting documentation, Enviance Services Private Limited verifies that the Dynamic Carbon Credits quantification procedures asserted by the Project Proponent are precise and align consistently with the ISO requirements. Enviance Services Private Limited further confirms that the carbon sequestration project has been executed in accordance with the submitted project description document submitted for each year for the six-year tenure of 2019 to 2024. The GHG assertion provided by the Project Proponent and verified by Enviance has resulted in the total carbon sequestration of 2,998,422 tons of Carbon per life cycle during the six-year tenure from 2019 to 2024 as reported below: Year Area Of Land tons of Carbon per life cycle 2019 355.6 acres 494,728.5 2020 355.6 acres 494,728.5 2021 361 acres 502,241.25 2022 361 acres 502,241.25 2023 361 acres 502,241.25 2024 361 acres 502,241.25 Total 2,998,422.00 An average sequestration rate of 1391.25 tons of carbon per acre per life cycle exists for each year during the six-year tenure of 2019 to 2024. The DCC proprietary plant demonstrates an innovative carbon sequestration approach, integrating biochar application, soil management, and microbial enhancement. On behalf of Enviance Services Private Limited Mr. Pankaj Kumar Mr. Vipul Jain

Yes

Available under NDA

Life Cycle Analysis using ISO 14040-14044 Standards

ISO 14040, 14041, 14042, 14043

N/A

N/A

N/A

Dynamic Carbon Credits (DCC) is pioneering large-scale carbon removal through a proprietary Direct Air Capture process that utilizes nature-based solutions. The company holds land rights to over 1,000,000 acres in the United States, which are dedicated to growing highly efficient, carbon-absorbing crops. These crops capture atmospheric CO₂ at a rate significantly higher than trees—up to eight times more. After harvesting, the biomass is processed to permanently sequester the captured CO₂, enabling the generation of verified carbon credits. These credits are registered and tracked via ISO-certified blockchain technology, ensuring transparency and traceability from capture to credit retirement. The system meets or exceeds EPA standards and qualifies for the IRS 45Q $180/ton incentive, further enhancing economic and environmental value. DCC’s approach addresses climate change by removing CO₂ at scale, offering a net-negative emissions solution that aligns with both corporate sustainability goals and national decarbonization targets.

The Dynamic Carbon Credits Project is designed to generate measurable and verifiable greenhouse gas (GHG) removals by deploying a combination of nature-based and engineered carbon removal activities across up to 1,000,000 acres of secured land rights in the United States. The project integrates high-biomass perennial crop cultivation, soil carbon enhancement, phytoremediation of degraded lands. Primary project activities include: a) High-Biomass Crop Cultivation for Carbon Sequestration - Establishment of high-biomass, fast-growing perennial species capable of rapid CO₂ uptake. - Harvesting of above-ground biomass for processing into long-lived carbon storage products (e.g. biochar, durable composites). - Retention of root biomass in situ to build soil organic carbon (SOC) levels over time. b) Phytoremediation and Land Restoration - Utilization of plant species with deep rooting systems to remediate contaminated soils and restore degraded lands. - Improvement of soil health, biodiversity, and water retention to enhance long-term sequestration potential. c) Integration of Direct Air Capture (DAC) Plant and Biochar Technology - Permanent storage of captured CO₂, CH4, and N2O via geological sequestration or incorporation into durable biochar carbon-containing materials. d) Advanced Monitoring, Reporting, and Third-Party Verification (MRV) - Deployment of IoT-enabled sensors to track biomass growth, soil organic carbon (SOC) changes, and DAC performance. - Blockchain-enabled registry for transparent, immutable tracking of carbon credit issuance. - Annual verification by accredited VVB (e.g., Enviance Services) -ISO 14040-14044 LCA updates every 5 years -Continuous improvement based on monitoring data -Transparent reporting through project registry We currently have 2,988,422 tons of credit inventory from 2019-2024. For 2025 forward credits we have capacity for 1,145,736,721.00 tons.

N/A

Alberta Quantification Protocol for Conservation Cropping (CCP) (Version 1.0.)

T-CC...6869

N/A

GHD Limited

Carbon Credit

No-till

Recurring

External registry

Public network NFT

As Produced

CSA Clean Projects Registry

The protocol specifically quantifies greenhouse gas emissions reductions from the following three activities: New carbon stored annually in agricultural soil; Lower nitrous oxide emissions from soils under no till management; and Associated emission reductions from reduced fossil fuel use from fewer passes per farm field. Shifting from any type of fallow (chemfallow, tilled fallow or a combination of chemfallow and tilled fallow) to continuous cropping also increases carbon stored in the soil, further reducing the greenhouse gas emissions footprint of the farm. This quantification protocol is written for project developers and farm operators implementing conservation cropping offset projects in the Dry Prairie and Parkland ecozones. Familiarity with and general understanding of conservation cropping farming practices required. The Farmers Edge Smart Carbon Soil Carbon Program, which applies the CCP protocol, creates soil sequestration in the form of Soil Organic Carbon by encouraging the continued use of no-till farm practices. The Digital-Measurement, Reporting & Verification system for capturing the records and evidence required for the Conservation Cropping Protocol used are collected within the Farmers Edge FarmCommand platform and associated MRV. FarmCommand is a GIS-based agronomic services and logistics management platform originally designed with grower (farmer) data collection for better agronomic decision making. This includes digital field borders, crop productions records, farm machinery telematics and crop harvest to storage and delivery tracking. The MRV portion adds protocol specific GHG calculations, "big data" storage and flexible reporting for users and independent verification companies.

CCP Version 1.0

Quantification of the reductions, removals and reversals of relevant sources and sinks for the GHGs will be completed using the methodologies outlined in the Alberta CCP protocol. This project will not consider the summer fallow reduction flexibility mechanism for any participating farms. The emission reduction quantification and calculation methodology for this project is described in detail. Emission reduction quantification formula used for this project according to the CCP, referring to Section 4.1, (page 30) of the Alberta CCP Protocol, the quantification approach is outlined below.

Emission Reduction = Emissions Baseline – Emissions Project Emissions Baseline = Emissions Energy Use + (Emissions Carbon Sequestration X Reserve Discount Factor) + Emissions Nitrogen Emissions Project = Emission Reduction = Emissions Baseline – Emissions Project Emissions Baseline = Emissions Energy Use + (Emissions Carbon Sequestration X Reserve Discount Factor) + Emissions Nitrogen Emissions Project = 0 WHERE: Emissions Baseline = sum of the emissions under the baseline condition • Emissions Energy Use = component of emissions change under source/sink B9 Herbicide Production to source sink P9; and emissions change under source/sink B14 to P14 for Field Operations (Table 8 below) • Emissions Carbon Sequestration = carbon component of emissions change under source/sink B13 Soil Carbon Dynamics to P13 Soil Carbon Dynamics (see Table 8 in link below) • Sequestered Carbon Reserve discount factor = Factor to account for reversals of carbon sequestration due to tillage events. • Emissions Nitrogen = component of emissions change under source/sink B13 Soil Nitrogen Dynamics to P13 Soil Nitrogen Dynamics (see Table 8 in link below) Table * found in: https://open.alberta.ca/dataset/b99725e1-5d2a-4427-baa8-14b9ec6c6a24/resource/db11dd55-ce34-4472-9b8b-cb3b30214803/download/6744004-2012-quantification-protocol-conservation-cropping-april-2012-version-1.0-2012-04-02.pdf

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N/A

Live

None

2018 to 2021

See Above

982.55

345 growers

338981.0000

N/A

N/A

N/A

N/A

N/A

Farmers Edge

The performance standard baseline establishes net coefficients implementing the project activities in the protocol region, adjusted by the level of adoption of No Till and Full Till in the region. This approach addresses the ISO 14064-2 principle of additionality (on a proportional basis), conservativeness and minimizes leakage. The NET coefficients have been calculated according to Section 2.5 of the Environment Canada and Agriculture-Agri Food Canada seed document from 2006 called the Tillage System Default Coefficient Protocol (Haak, 2006). Given that the Conservation Cropping Protocol and its predecessors, the Tillage System Management protocol in Alberta and the Technical Seed Document in the federal protocol development process (circa 2006), the performance standard baseline has had multiple reviews by technical experts, stakeholders, government and public input, a barriers assessment on alternatives is not warranted. The approach to additionality applied in the Alberta government approved protocols (i.e., CCP) is an accepted approach in many circles – called ‘proportional or regional’ additionality. This performance standard baseline allows project developers (Farmers Edge) to use this protocol to quantify annual emissions reductions based on annual, incremental increases in soil carbon adjusted (discounted) for 2006 sector level adoption. This discounting approach allows all farm operators practicing conservation tillage farming to participate in conservation cropping offset projects, irrespective of the adoption date of the practice change. It assumes all carbon stored prior to 2001 is discounted from 2006 levels and only the new, incrementally stored carbon is eligible for offset credits. As adoption levels of no till increase, the potential for new carbon sequestration is reduced; the associated emission reduction coefficients and the resulting offset credit opportunities are also reduced. Additional information on adoption levels, emission factor coefficients and corresponding adjustment factors is available in the Technical Seed Document for Conservation Cropping (Version 1). Alberta reviewed the Clean Development Mechanism’s (CDM) barriers assessment tool, which was used to assess additionality on a project-by-project basis. Alberta adopted similar tools but has chosen to assess additionality at a sector level evaluated during protocol development. Section 3.1 of the Technical Guidance for Offset Protocol Developers (January 2011) explained additionality requirements for offset protocols being used in Alberta. Protocol development must demonstrate the project has one or more technical, social, or financial barriers that limit adoption of the project. New, innovative projects and activities may face more barriers and score higher on a barriers assessment than well-developed technologies. If it is determined that barriers do exist, the protocol developer must assess sector level adoption to assess business as usual practices. Notionally, business as usual is defined as approximately 40 per cent adoption. If 40% or more of the sector have adopted the activity, the perceived barriers identified initially are project specific, but the activity in general does not need incentive through the offset program to advance. Protocols will generally not be developed for activities with greater than 40 per cent adoption unless specific situations exist as deemed acceptable by Alberta. Through its tillage system management, and new conservation cropping protocol, Alberta recognized the benefit of maintaining and increasing soil carbon sequestration by incenting conservation tillage farming practices such as no till. Science demonstrates that no till practices must be maintained for a period of 20 years for soils to reach saturation and move to a steady state. Equilibrium is the point where soils no longer absorb new, incremental carbon.

To address permanence, the project tracks a pool of emissions allocated to a Buffer Reserve Pool. A buffer reserve discount factor is applied to every tonne of sequestered carbon calculated under this protocol to account for known rates of reversals based on historical trends and expert opinion. These tonnes are held by the Project Developer to drawdown in the event of a reversal. The reserve discount factor accounts for the average risk of reversal across all farms within a given protocol region and ensures conservativeness in crediting.

Shifting from conventional farming to conservation cropping increases carbon sequestered in the soil in the Parkland (Black and Dark Gray Chernozemics, and Gray and Dark Gray Luvisols) and Dry Prairie (Brown and Dark Brown Chernozemics) regions of western Canada. Conservation tillage (no till and reduced till) increases soil carbon accumulation and results in reduced lower nitrous oxide (N2O) emissions from less soil disturbance. In the case of no till, fewer tillage passes over a farm field also reduce fossil fuel emissions from farm equipment, further lowering the greenhouse gas footprint for the farm. Baseline: Under a baseline scenario, the conventional farming practice is the full till farming operation. As mentioned, mechanical disturbances release soil carbon into the atmosphere. Project: Under this project, the project condition for the tillage system management is the use of no till systems as defined in Table 1 of the CCP protocol, which results in reduced disturbance of the soil, reduced soil organic carbon decomposition and loss of terrestrial carbon stores relative to conventional tillage systems (i.e.: the baseline condition). No till systems also result in a reduction in the fossil fuel emissions from fuel consumed in conventional, full till farming operations. In the case of the drier soils (i.e., Dry Prairie soils), there is also a reduction in nitrous oxide emissions from agricultural soils under no till relative to full till farming, which have been included in the coefficients provided in this protocol.

Sequestered carbon is a reversible activity. Tillage and other types of soil disturbances can cause previously sequestered carbon to be re-released to the atmosphere. This protocol manages the risk of reversal through a reserve discount factor (sequestered carbon reserve) applied to sequestered carbon to account for known rates of reversal occurring at a regional scale. This reserve factor discounts sequestered carbon by 7.5 to 12.5 per cent for the Dry Prairie and Parkland regions respectively according to the likelihood of reversals on a sector wide basis. Reversal events affecting less than 10 per cent of a total field area are considered to be a normal part of farm operations. Examples of these reversals include discretionary tilling to fix ruts or to manage weeds. Reversals under 10 per cent must be documented in the offset project report, but do not affect greenhouse gas emission reduction calculations. Reversal events that affect more than 10 per cent of a field area are considered beyond business-as-usual activities for farm operations. Reversals over 10 per cent must be documented in the offset project report, and affect fields must be removed from the project condition for the vintage year affected by the reversal. Examples of reversals may include re-seeding events and manure incorporation. Greenhouse gas emission reductions quantified using this reserve discount are considered permanently retired against future liabilities. Discounting for future liability ensures that offset credits quantified under this protocol are given to permanently sequestered carbon and not to carbon that may be released to the atmosphere as part of normal farm operations (e.g.: discretionary tillage for weed management). Alberta Environment and Water will do a periodic assessment of reversals against permanent reductions in the sequestered carbon reserve account. More information on the sequestered carbon reserve is available in Section 5.0 of the technical seed document

Protocol: Annual, incremental carbon sequestered in the soil through no till farming practices is eligible to generate offset credits starting, January 1, 2012 ending December 31, 2021. Project Report: Conservation Cropping practices such as no till are not required in any jurisdiction included in this project. The lands included in this project do not have any relevant legislative, technical, economic, sectoral, social, environmental, geographic, or site-specific requirements to adopt this activity. Project Report: This GHG emission reduction assertion was quantified using a quantification methodology considered to be industry best practice; • The project is based on an Alberta government approved quantification methodology, the Alberta CCP protocol, developed following the ISO 14064-2:2006, as required by the CSA CleanProjects Registry; • The GHG assertion has been verified by an independent third-party; • There are no regulations requiring the practice or prohibiting the use of the practice in the included jurisdictions. • The project is not currently subject to any climate change or emissions management legislation Provincially or Federally in Canada; • GHG emission reductions generated by this project are not listed on any other GHG reduction registry in Canada or internationally; • The project has not received any public funds in exchange for GHG emission reductions (e.g., offsets) resulting from this project; and • All environmental attributes generated by the project, including any GHG emission reduction benefits, are owned solely by Farmers Edge.

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The Monitoring Plan for Farmers Edge Smart Carbon Soil Carbon Project 2 integrates very well with Farmers Edge regular customer procedures for agronomic consulting and services. Data collection for monitoring purposes follows Farmers Edge processes and data systems already available (Please refer to Smart Carbon Program Standard Operating Procedure documents for details). Customer facing staff ensure data collection processes are executed and tracked in Farmers Edge data systems, FarmCommand, as well as SharePoint system and CRM system. Figure 6 below outlines the Farmers Edge project Data Flow. Field staff who work directly with customers, which includes Solution Sales Specialist, Precision Agronomists, Precision Technicians, Client Success Managers and Administrators, each has a unique, secure login to the FarmCommand system. All additions and changes to data in the FarmCommand are logged by person so all data and documents can be tracked back to the person who last handled it. Also, many Farmers Edge Agronomists, Precision Agronomists and Solution Sales Specialists are certified CCAs and/or Professional Agrologists (P.Ag.). Designations are noted in system for review purposes. Customer farm data is input into the FarmCommand system at two levels, Farm or Field. Farm level documents such as signed emissions contracts and Customer Service Agreements are collected during customer sign-up or renewal process, captured as a DocuSigned pdf, or scanned to pdf format, and uploaded to the CRM system. Our agronomic services contracts last four or five years. Then, each year, technical field staff work with the grower to help develop the annual crop plan for each field, which then forms the core of the agronomic data gathering system that is FarmCommand. Field level data is mostly passively collected and gets monitored by the Precision Technicians and Precision Agronomists and any system issues are corrected. Field specific details not available electronically such as crop insurance and irrigation receipts are collected by the Tech’s and Agronomists. Most Field level data is “monitored” or collected electronically using a Farmers Edge proprietary system, the CanPlug. The CanPlug system is a telematics-based data gathering device supplied for customer’s tractors, combines and sprayers. The CanPlugs monitor the machinery data systems, harvest the GPS encoded data from the in-cab and attached machinery controllers (computers) and sends the data over cell networks to our cloud database. This data is processed and becomes available information in the FarmCommand system. As a backup to this system, controller data is collected by our Precision Agronomists & Technicians from the in- cab controllers and then uploaded to FarmCommand. The electronically collected data includes much of the crucial information for detailed agronomic consulting and CCP GHG calculations. Information tracked includes tillage activity from As Applied seeding and/or fertilizing application dates, the machinery involved and the location of each event in all zones of every field. Monitoring for CCP specifically happens through our consulting process with farm customers: • The initial crop plan is prepared in consultation with the farmer. • Agronomists prepare fertility recommendations before fertilizing and seeding events. • As Applied activity is gathered electronically during seeding by CanPlug and directly immediately post-seeding by the Precision Agronomists and Technicians. • After spring seeding the crop plan is reviewed by an Agronomist at the Field Level. Any discrepancies or missing information is addressed with the Farmer. Any electronic gathering or processing issues are addressed with the data management development team and field staff. • It should be noted that pre-seeding and pre-harvest farm visits are done by Precision Technicians and/or Agronomists to supply the machinery ready data files for fertility and other prescriptions and to ensure the CanPlugs and other machine data systems are operational. Once operational, prescriptions can also be sent to the seeding unit controller via CanPlug. • A final post-harvest review is done by an Agronomist at Field & Farm Level to ensure each Field will qualify for CCP inclusion and that all Field & Farm Level documentation is in place for the GHG calculation and eventual assertion.

Farmers Edge Inc. (Farmers Edge) retained GHD Limited (GHD) to undertake a verification of the Greenhouse Gas (GHG) emission reductions (Offset) for the Farmers Edge Smart Carbon Soil Carbon Project #3 (Project), located in various locations across Manitoba, Saskatchewan, and Alberta for the period from January 1, 2018 to December 31, 2021. The Project is registered with the CleanProjects® Registry (Registry). The verification will be conducted in accordance with the ISO 14064. The project is defined by the implementation of a direct seeding regime. The quantification of reductions is based on a protocol approved for use under Alberta’s Regulatory system – the Conservation Cropping Protocol (CCP) – which quantifies reductions associated with a change from conventional tillage to no-till farming. This protocol is used to form the basis of quantification. It is supported with additional modelling completed during an Ontario Protocol Development Process – which took the existing CCP and developed factors for other jurisdictions across Canada. No till adoption levels are based on 2006 Census of Agriculture tillage adoption rates, as per the Alberta CCP. GHD has prepared this Verification Report for Farmer’s Edge and the Registry. Farmer’s Edge was responsible for the preparation and fair presentation of the GHG Assertion in accordance with the criteria and engaging with a qualified third-party verifier to verify the GHG Assertion. GHD's objective and responsibility was to provide an opinion regarding whether the Project’s 2018-2021 GHG Assertion was free of material misstatement and that the information reported is a fair and accurate representation of the operations for the reporting period accurate and consistent with the requirements of the protocol and the registry, and associated criteria. The criteria used by GHD for the verification of the GHG Assertion is detailed in Section 2. GHD completed the verification of the GHG Emissions Report in accordance with ISO 14064-3:2006. GHD completed the verification to a reasonable level of assurance. Farmer’s Edge reported 117,645 .5 tonnes CO2e as the total attributable emissions for 2018-2021 for the Project. This includes the GHG emissions resulting from operating conditions from January 1, 2018 through December 31, 2021 (reporting period). The quantitative aggregated magnitude of errors, omissions, and misstatements is detailed in Section 3.2. Based on verification procedures undertaken to a reasonable level of assurance, it is GHD’s opinion that the GHG Assertion is materially correct and is a fair and accurate representation of the Project’s total attributable emissions for the reporting period; and that the GHG Assertion was prepared, and emissions were quantified in accordance with the requirement of Protocol and the Registry. Information in the GHG Assertion which was not reported or quantified in accordance with the Protocol but was corrected during the verification process includes: - The farming area used to calculate offset credits were updated to be equal or less than land title area - Update project report to include coefficients up to 4 decimal places

Initial project execution was in 2021 and 2022 based on farmer field-by-field activities from January 1, 2018 to December 31, 2021.

1341 Dugald Road, Canada, MB, Winnipeg, R2J 0H3

-97.05855772731057

49.88636458211731

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Farmers Edge

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Verifier's Opinion (see attached verification report): GHD has prepared this Verification Report for Farmers Edge and the Registry. Farmers Edge was responsible for the preparation and fair presentation of the GHG Assertion in accordance with the criteria and engaging with a qualified third-party verifier to verify the GHG Assertion. GHD's objective and responsibility was to provide an opinion regarding whether the Project’s 2018-2021 GHG Assertion was free of material misstatement and that the information reported is a fair and accurate representation of the operations for the reporting period accurate and consistent with the requirements of the protocol and the registry, and associated criteria. The criteria used by GHD for the verification of the GHG Assertion is detailed in Section 2. GHD completed the verification of the GHG Emissions Report in accordance with ISO 14064-3:2006. GHD completed the verification to a reasonable level of assurance. Farmers Edge reported 309,823 tons CO2e as the total attributable emissions for 2018-2021 for the Project. This includes the GHG emissions resulting from operating conditions from January 1, 2018, through December 31, 2021 (reporting period). The quantitative aggregated magnitude of errors, omissions, and misstatements is detailed in Section 3.2. Based on verification procedures undertaken to a reasonable level of assurance, it is GHD’s opinion that the GHG Assertion is materially correct and is a fair and accurate representation of the Project’s total attributable emissions for the reporting period; and that the GHG Assertion was prepared, and emissions were quantified in accordance with the requirement of Protocol and the Registry. Information in the GHG Assertion which was not reported or quantified in accordance with the Protocol but was corrected during the verification process includes: - Provide sufficient back up data to support the percentage of soil disturbance for two farms, according to protocol requirements

Yes

Farmers Edge

Farmers Edge Smart Carbon Program Standard Operating Procedure

Farmers Edge Smart Carbon Program Standard Operating Procedure

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Farmers Edge Smart Carbon Soil Carbon Project 4 (Project Identifier: 5593-2852)

The protocol used for this project is the Alberta Quantification Protocol for Conservation Cropping (CCP) (Version 1.0) April 2012, which was developed following ISO 14064-2:2006 guidelines. The project is voluntary in a non-regulated sector. Tillage practices are not regulated within the jurisdictions. The project involves the Greenhouse Gas (GHG) reductions calculated with tillage management changes from full tillage to no tillage, based on the soil disturbance and passes made on each parcel of land and includes the sequestration of carbon in the soil, along with reduced fossil CO2 emissions and Nitrogen (N) fertilizer emissions (according to ISO 14064-2:2006), because of such management practices (Note -there are no N management activities associated with this protocol). The CCP is directly relevant to this project because it lays out the No-Till definition of soil disturbance that all the tillage implements must meet, that are used by the farms involved (sub-projects). The protocol also defines the records that must be collected and retained to prove the No-Till status required for offset creation. The summer fallow reduction flexibility mechanism is not used in this project. The Project is comprised of 345 growers and includes 3,546,642 acres of land in Alberta, Saskatchewan, and Manitoba. A total of 309,991 tons of carbon offsets have been verified and a total of 29,175 tons have been quantified and are held in a Reserve Pool by the Project Developer.

5593-2852

Low Carbon Technologies LLC

T-CC...6807

N/A

N/A

Carbon Credit

Solar PV Avoidance,Avoidance

Recurring

D-MRV / Methodology

Private network NFT (Triangle)

As Produced

Triangle

LCT has created comprehensive life cycle assessments (LCA) models to quantify C emissions from beef and dairy production. The models were developed using ISO 14040 and 14044 (2006 and 2017), IPCC (2019), and IDF (2022) standards and are part of our patented approach to evaluating GHG emissions from livestock (US Patent 11209419B2; Beal, 2021). The model for beef cattle production is based on conventional beef production practices in the U.S. (Figure 1), where calves are born on a farm or ranch, are weaned approximately 6 months later, next raised in a backgrounding or stocker operation and grown to 700 to 800 lb. body weights, and then transported to a feedlot for finishing at slaughter weights of 1400 to 1600 lbs. Alternative pathways for direct entry to feedlot after weaning, grass fed herds, and beef-on-dairy are also modelled. All major upstream and within system greenhouse gas emissions are captured in the C footprint and include all CH4 and NO2 emissions and CO2 from fossil fuel use and non-renewable electric generation. Biogenic CO2 from photosynthesis and animal respiration is not included. The reduced emissions associated with mitigation strategies are compared to the baseline of conventional beef production to quantify the impact of the C reductions. The model is comprehensive, covering all emissions occurring in the animal’s lifetime from conception to slaughter, i.e. it’s cradle to grave. Emissions associated with upstream inputs like feed, fertilizer, fuel, electricity, and purchased animals are included. Outputs include meat from harvested animals, animals sold to other farms and ranches, and exported manure.

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Based on the grid power generated from heavy crude oil, the solar panels capture the difference between the heavy crude carbon footprint and the footprint derived from solar panels.

1. The EIA reports 0.08 gallons of liquid petroleum is used to produce 1 kilowatt-hour (kWh) of electricity – that's ~12.69 kWh per gallon of petroleum 2. Heavy Oil Calculations / gallon: CO2 (kg): 11.27 CH4 (g): 0.42 N2O (g): 0.08 equals 11.399 CO2e (kg) 3. Based on 122,005,563 kWh of power * EIA ratio (0.08) equals 9,760,445.04 gallons of Heavy Oil 4. 9,760,445 gallons * 11.399 (CO2e kg) = 111.257 MT CO2e

None

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Live

None

Power generated by Belco

Heavy Oil Calculations / gallon: CO2 (kg): 11.27 CH4 (g): 0.42 N2O (g): 0.08 equals 11.399 CO2e (kg)

Based on 122,005,563 kWh of power * EIA ratio (0.08) equals 9,760,445.04 gallons of Heavy Oil

1

111.257 MT CO2e

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As per Clean Development Mechanism methodology AMD ID v18, accepted by validated and accepted by the Verra registry.

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Daily inverter measurement

TBD

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25 Pomander Rd, Bermuda, PAG, Paget Parish, PG 05

-64.77411

32.2911606

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Royal Hamilton Amateur Dinghy Club

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Yes

Enphase

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Enphase Inverter

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PV Solar Panels on Roof

Installation of PV Solar Panels on Roof (186 Panels x 360 Watts/1000=66.96kW) on 3,357sq. ft.

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