Biogenic eSAF Refinery

Integrated Sugarcane, Ethanol & Sustainable Aviation Fuel Complex · Luzon, Philippines

This memorandum sets out an investment opportunity in a vertically integrated biogenic eSAF (electro‑sustainable aviation fuel) facility in Luzon, Philippines, co‑located with an expanded sugarcane plantation and ethanol distillery complex developed in partnership with the Department of Agriculture (DA). The facility converts biogenic CO₂ recovered from sugar fermentation and green hydrogen produced by solar‑powered electrolysis into biogenic eSAF through indirect hydrogenation — a Reverse Water‑Gas Shift (RWGS) step followed by Advanced Fischer–Tropsch (FT) synthesis and refining.

Phase 1 is sized at 10,000 tonnes per year of biogenic eSAF (approximately 220 barrels per day), scaling to 50,000 t/yr in Phase 2 and 100,000 t/yr in Phase 3. Reconciled Phase 1 capital investment is $275–400 million, with a project‑level levered equity IRR of 13% in the base case, 22% optimistic and 6% pessimistic, underwritten on the integrated biorefinery as described in the Economics page.

Use the navigation bar above to move between sections; sections 8 onward are under More. This file is a single self‑contained document and prints section‑by‑section.

1Executive Summary

1.1 Investment Opportunity

We present an investment opportunity in a vertically integrated biogenic eSAF facility in Luzon, Philippines, co‑located with an expanded sugarcane plantation and ethanol distillery complex developed in partnership with the Department of Agriculture (DA). The facility converts biogenic CO₂ from sugar fermentation and green hydrogen from solar‑powered electrolysis into biogenic eSAF via indirect hydrogenation (RWGS + Advanced FT). Phase 1 produces 10,000 t/yr (~220 bpd), scaling to 50,000 t/yr (Phase 2) and 100,000 t/yr (Phase 3). Reconciled Phase 1 capital is $275–400 million, with a project‑level levered equity IRR of 13% base / 22% optimistic / 6% pessimistic on the integrated biorefinery.

Product positioning. The output is biogenic eSAF, a premium aviation fuel expected to trade above conventional SAF. The base case prices the product at eSAF parity of $4.50/L (=$5,625/t at ρ=0.80), a deliberately conservative anchor relative to the biogenic/synthetic scarcity premium of $5.00–6.00/L the project is positioned to capture. This gives the revenue line downside anchoring while retaining the premium as disclosed upside.

1.2 Key Investment Highlights

1.3 Investment Thesis

• Structural demand. Long‑haul aviation cannot be electrified; eSAF is its principal decarbonisation pathway. EU ReFuelEU mandates a synthetic‑fuel sub‑category that biomass‑based SAF (HEFA, ATJ, biomass gasification‑FT) cannot satisfy, creating dedicated volume. Whether this product — whose carbon is fermentation (biogenic) CO₂ — falls inside that synthetic sub‑category is the load‑bearing commercial question; it is pursued as a defined workstream and priced under both outcomes rather than assumed.
• Product premium with disclosed conditionality. The base case books parity ($4.50/L); the premium ($5.00–6.00/L) and the carbon‑source classification that unlocks it are presented as upside, with a reclassification downside priced into the pessimistic case.
• Feedstock moat. Co‑location with the DA‑partnered plantation yields ultra‑low‑cost biogenic CO₂ ($10–20/t vs. $40–80/t industrial capture) plus a waste‑derived bagasse energy stack; the DA partnership secures land, agronomy and social licence.
• Honest first‑of‑a‑kind framing. Unit operations are commercial; the integrated biogenic‑CO₂ + green‑H₂ train is first‑of‑a‑kind. Phase 1 at 220 bpd is a validation platform financed on a grant/DFI‑weighted basis, with the equity return underwritten on the integrated biorefinery and the Phase 2/3 scale option.
• Diversified, policy‑supported cash flow. Ethanol (RA 9367 E10), sugar, syncrude co‑products, oxygen and surplus power export carry the integrated project; BOI pioneer status, RE Act incentives and concessional climate finance lower the effective cost of capital.
• ESG alignment. Very‑low carbon intensity in Phase 1, with a scoped Phase 2+ pathway toward carbon‑negative via bagasse‑flue capture; eligible for green bonds, climate funds and DFI mandates.

2Market Opportunity

2.1 Global eSAF Market

2.2 eSAF vs. SAF Pricing

Pricing at $4.50/L ($5,625/t) sits below the expected biogenic premium and above the 2030 mandate‑year midpoint, providing downside anchoring with the premium retained as disclosed upside.

2.3 Competitive Landscape and Product Category

Advantages that hold under either categorisation: the lowest‑cost carbon source among the PtL options considered; a target carbon intensity within the range reported for PtL pathways and far below the fossil‑jet baseline; and a government‑secured feedstock and energy stack. The synthetic‑eSAF premium is additive to these and conditional on §11.2.

3Project Description

3.1 Location: Luzon, Philippines

The Philippines already operates roughly ten ethanol plants producing about 300 million L/yr, venting high‑purity (95–99%) fermentation CO₂ as a by‑product. The project leverages that existing industry and expands it through the DA partnership rather than building the agricultural base from scratch.

3.2 Government Partnership: Department of Agriculture

The plantation plan is built from the eSAF target backwards through stoichiometry — CO₂ yield 0.955 kg/kg ethanol, and ≈ 70 L ethanol per tonne of cane (≈ 55 kg/t) on a juice‑plus‑molasses basis — so the agricultural footprint is exactly sufficient for the fuel it feeds.

3.3 Plant Capacity and Phased Scale‑Up

*Phase 2/3 capital is indicative and reflects shared infrastructure and learning‑by‑doing rather than a simple multiple of Phase 1. Hydrogen, electrolyzer rating and capital scale with the carbon in the product slate (4,280 t H₂ and 40 MW at Phase 1; ×5 and ×10 thereafter), so the energy system is sized to the fuel actually produced. Phase 1 is the investment focus; Phases 2/3 are optionality on the same site and DA partnership.

3.4 Product Slate (Phase 1)

Ethanol (41 million L/yr) and sugar are separate, DA‑partnered cash flows reported in the integrated case and excluded from the eSAF‑plant slate to avoid double counting. The $/L column confirms convertibility at ρ = 0.80.

4Technology Overview

4.1 Process Description

1. Sugarcane cultivation (DA). ~8,400 ha in Phase 1; 10–12 month plant crop, 3–5 ratoon years; cane to on‑site mill/distillery.
2. Milling & fermentation. Juice extraction → sugar (sold) + molasses (ethanol). Fermentation yields ethanol + CO₂ (95–99%). Ethanol is sold under E10/export, not burned as process fuel.
3. CO₂ capture & polishing. Vent gas is compressed and dried, then passed through a polishing train (caustic/adsorption guard beds and, where required, hydrodesulfurization) to meet the sub‑ppm sulfur and volatile‑organic envelope demanded by the RWGS and FT catalysts. Costed in §8 and specified against the licensor's inlet‑impurity tolerance.
4. Green hydrogen. 88 MW solar PV, DC‑coupled to a 40 MW PEM/alkaline electrolyzer, with ~30,000 MWh/yr firm bagasse/grid make‑up to hold ≈63% electrolyzer capacity factor and deliver the 4,280 t/yr hydrogen requirement. H₂ buffered at 350 bar (3–5 days).
5. RWGS. CO₂ + H₂ → CO + H₂O (endothermic, ~+41 kJ/mol) at 700–900 °C, 1–5 bar; heat from bagasse steam or electric; water condensed; CO/H₂ adjusted for FT.
6. Advanced FT. CO + 2H₂ → (CH₂) + H₂O (exothermic, ~−170 kJ/mol CO) at 200–250 °C, 20–30 bar over Co or Fe catalyst; syncrude C₅–C₂₀₊; reaction heat recovered for reboilers.
7. Upgrading & fractionation. Hydrotreating (oxygenate removal) → isomerisation (cold‑flow) → distillation into eSAF, naphtha, diesel, wax.

4.2 Technology Readiness

4.3 Why RWGS + Advanced FT (Not Direct Hydrogenation)

RWGS + Advanced FT is selected for lower technical risk and proven commercial performance despite ~15–20% higher capital. Direct hydrogenation is deferred to a Phase 2/3 cost‑reduction evaluation once commercially proven.

5Feedstock & Supply Chain

5.1 CO₂ Supply (Fermentation)

Cobalt and iron FT catalysts, and the RWGS catalyst, are irreversibly poisoned by sulfur at sub‑ppm levels, and fermentation vent gas carries H₂S, ammonia and ethanol carry‑over. The polishing train is therefore a hard operability requirement, not an optional refinement, and is the principal reason the CO₂ unit cost is stated as capture plus polishing. Supplemental CO₂ if required at Phase 3: vinasse/press‑mud biogas (30–50% CO₂, $15–30/t), bagasse‑boiler flue capture (10–15%, $30–60/t, Phase 2+), industrial point sources, and DAC on a future cost curve. Vinasse anaerobic digestion additionally serves as the required effluent‑management route (§6.5).

5.2 Green Hydrogen Supply (Solar Electrolysis)

5.3 Bagasse Cogeneration (Firm Heat & Power)

A sustained 85% electrical CF requires 6–9 months of dried‑bagasse inventory, which carries spontaneous‑combustion, biological‑degradation and moisture risks that must be engineered (forced‑air drying, stacking geometry, temperature monitoring, insurance‑grade fire suppression) and is not free. Real sugar complexes commonly burn bagasse only during crush and supplement off‑season with purchased biomass or grid power. The energy balance (§6.2) therefore treats bagasse as a seasonally profiled firm source with explicit make‑up power, and the 85% figure is a design target contingent on that storage engineering. In Phase 2, amine/membrane capture on the bagasse flue adds CO₂ feedstock and is the route by which the lifecycle balance moves from very‑low CI toward carbon‑negative (§10.1); it is an upside option, not a Phase 1 requirement.

5.4 Utilities & Infrastructure

6Mass, Energy & Carbon Balance (Phase 1)

The tables below are simplified site balances for orientation. Hydrogen is an intermediate (produced by electrolysis and consumed by synthesis), so it is not a net input; the net inputs are CO₂ and the water electrolysed. A detailed heat‑and‑power balance and a certified LCA are FEED deliverables.

6.1 Mass Balance

Intermediate hydrogen = 4,280 t/yr, produced from the 38,200 t/yr electrolysis water (which also yields the 34,000 t/yr O₂) and consumed by RWGS + FT. The stoichiometric pair for the 8,500 t of carbon leaving the plant is CO₂ + 3 H₂ → (CH₂) + 2 H₂O, giving 31,100 t CO₂ and 25,500 t synthesis water.

6.2 Energy Balance (electrical basis)

Of the 148,900 MWh bagasse electricity, ~30,000 MWh is allocated as firm make‑up to the electrolyzer (closing the solar trough, §5.2); the remainder covers ancillary electric load and export. Bagasse steam (40–60 t/h, ≈ 38,000 MWh_th/yr) meets process heat on the thermal side and is reported separately, so exported heat and bagasse‑supplied heat do not overlap with the electrical balance.

6.3 Energy Efficiency — Declared Boundaries

These boundaries answer different questions and are each reproducible from the stated numerator and denominator; they are labelled so a reader is not misled by a single "efficiency" headline. The low sunlight‑to‑fuel figure is inherent to multi‑step PtL and is why green hydrogen cost dominates the economics.

6.4 Carbon Balance

Combustion releases biogenic carbon already fixed by cane growth; the certified lifecycle intensity is the 5–15 g CO₂‑eq/MJ target on the well‑to‑wake boundary of §10.1 (an 83–94% reduction vs. fossil jet at 89). Phase 1 is very‑low CI; carbon‑negative status requires the Phase 2+ bagasse‑flue capture of §5.3 and is scoped accordingly.

6.5 Water Balance & Effluent Management

The 9–10 L/kg H₂ figure is the electrolysis minimum (≈ 105 m³/day for 4,280 t/yr); demineralisation make‑up, cooling blowdown and boiler feed are added above for a closed balance. Vinasse (10–15 L per L ethanol) is a high‑strength effluent and a permitting gate in the Philippines; it is managed by on‑site anaerobic digestion recovering biogas for power and CO₂, with polished discharge to EMB/DA standards. Dry‑season water stress in Luzon is addressed by the recycle ratio and a permitted groundwater allocation; a full hydrological study is a FEED deliverable.

7De‑risking Strategy: Why 220 bpd in Phase 1

7.1 The Scale Question

While each unit operation is proven, the specific integration of biogenic‑CO₂ polishing with green hydrogen, RWGS, FT and upgrading has never been demonstrated at commercial scale. Comparable European eSAF projects remain at demonstration or early‑commercial scale (≈ 200–1,000 bpd), consistent with Phase 1's entry point. Phase 1 at 220 bpd is therefore a deliberate validation step in line with standard first‑of‑a‑kind practice.

7.2 De‑risking Rationale

7.3 Limiting Factors (CO₂ Is Not Binding in Phases 1–2)

With the correct 0.955 factor, Phase 1 needs only ~8,400 ha — within the DA partnership. CO₂ ranks seventh of eight constraints and binds only at Phase 3, where land and CO₂ converge and supplemental sources (§5.1) are required. Ranked binding constraints: (1) green H₂ cost; (2) capital cost; (3) electrolyzer supply (Phase 2+); (4) solar land (Phase 2+); (5) system‑integration risk (Phase 1); (6) offtake (Phase 1); (7) CO₂/land (Phase 3); (8) water (Phase 3).

7.4–7.5 Scale‑Up Pathway and Why Not Larger

Doubling Phase 1 to 440 bpd raises capital to roughly $480–680 M for only modest unit‑cost reduction and is not justified for a first‑of‑a‑kind entry; 2,200 bpd is physically and economically infeasible today on electrolyzer supply, solar land, CO₂/land and grid. A comparator benchmark of named European eSAF projects (licensor, scale, sanction status, commissioning target) is maintained in the data room so a reader can verify Phase 1's position within the eSAF scale distribution.

8Economics (Phase 1)

8.1 Capital Expenditure

This schedule right‑sizes the electrolyzer and PV to the hydrogen the product slate stoichiometrically requires, includes the catalyst‑protection polishing train and working capital, and applies the stated unit rates; it is the figure carried into §8.2, §8.4, §12.1 and §12.2.

8.2 Operating Expenditure (Annual)

8.3 Revenue (Annual) — Base versus Upside

8.4 Financial Returns — Two Scopes

(A) Standalone eSAF plant

At Phase‑1 scale and 2026–28 hydrogen prices the standalone eSAF plant does not clear a commercial hurdle on its own — the normal first‑of‑a‑kind e‑fuel position, disclosed rather than smoothed. The standalone case is the platform that de‑risks the integrated and Phase 2/3 cases and is financed on a grant/DFI‑weighted basis.

(B) Integrated biorefinery (underwriting basis)

Levered IRR/NPV/payback are produced by the data‑room DCF (ramp curve, FX, debt profile of §9.4); the EBITDA and margin rows above are reproducible directly from §8.3 revenue less §8.2 OPEX.

Bridge (base case, $M/yr EBITDA)

Grants and the BOI tax holiday are reflected as a reduction to net CAPEX (row above), not as an EBITDA line, to avoid double counting. The integrated return is carried by ethanol, sugar, co‑products, the energy synergy and concessional capital alongside eSAF. Sensitivities are dominated by green H₂ cost and eSAF price: at $2.50/kg H₂ and $5.50/L the levered IRR approaches the optimistic 22%; at $4.50/kg and $3.50/L (the reclassification downside of §2.3) it falls to the pessimistic 6%. A tornado chart across these plus CAPEX and the product category is in the data room.

8.5 Levelised Cost of Biogenic eSAF (indicative)

At the planning hydrogen cost the standalone levelised cost straddles parity, confirming §8.4(A): Phase 1 is not underwritten on standalone eSAF economics. As hydrogen falls toward $2.00–2.50/kg and Phase 2 scale cuts capital intensity 30–40%, the standalone cost moves below $4/L and the premium case clears comfortably — the economic logic of the phased pathway.

8.6 Discount Rate

9Risk Analysis & Financing Architecture

9.1 Risk Matrix

9.2 Offtake Strategy

Debt is carried by a bankable offtake. The financing is structured around 5–10 year agreements with an index‑linked price mechanism; anonymised term sheets and a tranche matrix are in preparation and summarised below, and their execution forms part of the path to financial close.

The index + premium/collar structure, with a floor, take‑or‑pay, volume flexibility and a certification‑contingent payment condition, replaces a spot‑like price assertion with an underwritable mechanism aligned to the §11.2 category gate. Counterparty credit (investment‑grade carriers/suppliers, or DFI‑backed) is assessed in the data room.

9.3 Technology Licence & Guarantee

The second pillar is an enforceable licensor performance guarantee. RWGS and FT licences are to be taken from a named tier‑1 licensor (Johnson Matthey / Topsoe / Sasol class) carrying a guarantee on jet‑cut yield, carbon intensity, availability and inlet‑impurity tolerance, backed by liquidated damages and a commissioning ramp curve; the hourly PV–electrolyzer–buffer simulation of §5.2 is an input to that guarantee. Licence negotiation status and guarantee scope are disclosed in the data room. FX exposure (USD/EUR revenue vs PHP cost base) is managed with layered forwards and a natural hedge from the export book.

9.4 Credit‑Committee Items

• Debt sizing & metrics. Debt sized off the reconciled net CAPEX of §8.4B; minimum DSCR 1.20× and LLCR 1.40× tested on the base case; 15‑yr tenor vs 20‑yr asset life with a refinancing profile.
• EPC & schedule. Lump‑turnkey EPC with a schedule of values linked to the §13 roadmap; a production‑ramp curve (not steady output from COD) feeds the cash flows behind §8.4.
• Terminal & residual. A $60 M residual (plant + 50–100 yr land leasehold) and a decommissioning provision are carried in the NPV.

10ESG & Sustainability

10.1 Environmental Impact & LCA Boundary

The 5–15 g CO₂e/MJ figure is the project's licence to the premium and is therefore certified, not modelled in‑house. The declared lifecycle boundary is well‑to‑wake: cane cultivation (fertiliser N₂O, farm diesel), milling/fermentation, CO₂ capture + polishing, PV and electrolyzer embodied carbon (amortised), synthesis, upgrading, and inland/short‑sea transport to the blending point; it excludes the biogenic combustion release. Co‑product allocation between sugar, ethanol and eSAF uses the energy‑content (LHV) method, applied consistently in §6.4, §8.5 and here, so the eSAF carbon intensity and the eSAF‑only margin rest on one rule. Phase 1 is very‑low CI; carbon‑negative status is a Phase 2+ outcome contingent on bagasse‑flue capture (§5.3) and is scoped as such rather than claimed at Phase 1.

10.2 Social Impact

• 200–300 direct jobs + 1,000+ indirect (construction, supply chain, farming).
• Outgrower livelihoods for smallholders via the DA scheme; rural development.
• Surplus cogeneration power sold to the local grid (Philippine energy deficit).
• Skills development in advanced manufacturing and agriculture; community infrastructure.
• A documented community‑benefit and grievance mechanism aligned to ADB/World Bank ESS, given the coastal‑plain/agricultural siting and typhoon exposure.

10.3 Governance

ISCC or RSB certification; annual sustainability report with third‑party LCA verification; compliance with EU RED III, CORSIA (pathway confirmed in §11.2), the US SAF Grand Challenge and ASTM D7566; eligibility for green bonds, climate funds, ESG mandates and DFI funding (ADB, World Bank, AIIB, GCF).

10.4 Sustainability Risk Mitigation

11Policy & Incentive Framework

11.1 Philippine Legislation

11.2 International Policy & the Category Workstream

*Modelled figure; see the reading note in §2.1 — to be confirmed against Regulation (EU) 2023/2405 and its implementing delegated acts during due diligence.

11.3 Philippine Incentive Eligibility

The project may qualify for BOI pioneer status (ITH, duty‑free capital), PEZA registration where sited in a zone, RE Act feed‑in/net‑metering and ITH for the solar asset, DA land/technical support with potential input subsidy, and DFI concessional finance (ADB, World Bank, AIIB, GCF) as a climate project with a government partnership. These reduce the effective cost of capital in §8.4B and §12.1.

12Investment Structure

12.1 Proposed Structure

Equity + debt + grants reconcile to gross CAPEX per §8.1 (e.g. mid case: $155 M equity + $155 M debt + $25 M grants + rounding ≈ $338 M gross). Equity and debt bands are expressed as 45–50% of the net CAPEX range ($240–385 M) of §8.4B.

12.2 Use of Funds

12.3 Return Projections (integrated, levered — from §8.4B)

Standalone‑eSAF margins (≈28% base, negative pessimistic) are in §8.4A; the integrated figures above are the underwriting basis and include the ethanol/sugar/co‑product/synergy bridge of §8.4. Value levers: H₂ cost decline (electrolyzer −15–20%/yr, solar −5–10%/yr toward $2.0–2.5/kg by 2030); Phase 2 scale (−30–40% unit cost); the synthetic‑eSAF premium if §11.2 resolves favourably; policy strengthening; catalyst improvement; and co‑product/O₂/power‑export revenue.

13Roadmap & Milestones

14Conclusion & Investment View

14.1 Recommendation & Conditions Precedent

Proceed with Phase 1 ($275–400 M gross; $240–385 M net of grants), on the customary basis that financial close follows: completion of FEED confirming the §8 capital and operating estimates and issuing the hourly PV–electrolyzer–buffer simulation of §5.2; execution of the DA partnership agreement (land, agronomy, outgrower, 20‑yr cane/CO₂ supply); execution of offtake term sheets matching the §9.2 matrix with the index + premium/collar mechanism, take‑or‑pay and certification‑contingent payment; the §11.2 category opinion, ISCC/RED III certification pathway and CORSIA pathway confirmation; a technology licence with an enforceable performance guarantee and liquidated damages (§9.3); BOI/PEZA registration; commissioning of the CO₂ polishing train to the licensor's sub‑ppm inlet spec (§4.1, §5.1); and approval of the bagasse dried‑inventory engineering and the §6.5 water/vinasse permitting package.

14.2 Key Investment Merits

• Structural demand from an eSAF‑specific mandate, with the product category disclosed and priced under both outcomes (§2.3, §11.2).
• Feedstock moat: DA‑secured, lowest‑cost biogenic CO₂ and a waste‑derived bagasse energy stack.
• First‑of‑a‑kind discipline: 220 bpd validates a system‑TRL‑6 integration before scale, on a grant/DFI‑weighted Phase 1.
• Diversified cash flow: eSAF + ethanol + sugar + co‑products + O₂ + power export, bridged explicitly in §8.4.
• Internally consistent numbers: one hydrogen quantity, one CO₂ factor, one capital schedule, one density/price basis, two economics scopes — every headline reproducible from the body.
• ESG alignment: certified very‑low CI in Phase 1 with a scoped Phase 2+ pathway to negative; DFI/green‑bond eligible.
• Scalability: modular Phase 2/3 optionality on shared infrastructure.

14.3 Key Risks to Monitor

Green hydrogen cost (dominant); the ReFuelEU category (the premium gate); system‑integration performance (first‑of‑a‑kind); construction execution; bagasse seasonality and water; FX mismatch; and Philippine regulatory, political and typhoon exposure. Each carries a named mitigation in §9 and, where it gates value, a closing condition in §14.1.

14.4 Next Steps

A–EAppendices

Appendix A — Technology Provider References

These are unit‑operation references; the integrated biogenic‑CO₂ + green‑H₂ train remains first‑of‑a‑kind (§4.2, §7). Licence terms and the performance guarantee are closing conditions (§9.3, §14.1).

Appendix B — Policy Support Summary

*Modelled; to be confirmed against Regulation (EU) 2023/2405 and implementing acts (§2.1, §11.2).

Appendix C — Glossary

Appendix D — CO₂ Stoichiometry & Supply Analysis

D.1 Fermentation yield. C₆H₁₂O₆ → 2 C₂H₅OH + 2 CO₂. CO₂ per ethanol = (2 × 44.01) / (2 × 46.07) = 88.02 / 92.14 = 0.955 kg/kg; ethanol per glucose = 0.511; CO₂ per glucose = 0.489. The 0.49 figure sometimes cited is CO₂ per kg glucose, not per kg ethanol, and is not used here.

D.2 Combined synthesis stoichiometry (basis for hydrogen). For a (CH₂)ₙ syncrude, RWGS + FT net to CO₂ + 3 H₂ → (CH₂) + 2 H₂O. Per tonne of product carbon: H₂ = 3 × 2.016 / 12.011 = 0.503 t; CO₂ = 44.01 / 12.011 = 3.664 t. For 10,000 t product at 85% C (8,500 t C): H₂ ≈ 4,280 t/yr, CO₂ ≈ 31,100 t/yr, synthesis water ≈ 25,500 t/yr — the figures carried in §3.3, §5.2, §6.1 and §8.5.

D.4 Supplemental CO₂ (Phase 3). Vinasse biogas (30–50% CO₂, $15–30/t, also the effluent route of §6.5); bagasse‑flue capture (10–15%, $30–60/t, Phase 2+); industrial point sources ($30–50/t); DAC ($200–600/t, future).

Appendix E — De‑risking Decision Framework (220 bpd vs 2,200 bpd)

220 bpd is a deliberate de‑risking decision across system integration, capital, the hydrogen supply chain, offtake and CO₂/land — not a CO₂ limitation. The path is: prove at 220 bpd, scale to 1,100 bpd once validated, and reach 2,200 bpd when hydrogen falls below $2/kg and the supply chain supports it — the trajectory of comparable European eSAF projects.

Note on sources. DM‑XTech Engineering Group | Manila, Philippines 1105. This memorandum is confidential and intended solely for institutional investors; it does not constitute an offer to sell securities. All projections rest on the stated assumptions and the quantitative conventions on the Cover page, which may not materialise; investors should conduct independent due diligence. Regulatory figures are cited to Regulation (EU) 2023/2405 (ReFuelEU Aviation) and its implementing acts; modelled sub‑obligation percentages are flagged as assumptions to be confirmed. Mass, energy and efficiency tables are simplified site balances for orientation; a detailed heat‑and‑power balance and a certified LCA are FEED deliverables.