Oil Refinery Business Plan Template

The 2025 refining market in numbers, not adjectives

Refining is a margin business. Crude price moves dominate the headlines, but refiners earn the spread between the barrel of crude they buy and the barrels of gasoline, diesel, jet fuel, and residual products they sell. Any plan that opens with crude price forecasts is asking the wrong question. Lenders, EPC contractors, and offtake counterparties all want to see that the founder understands utilization, slate, and crack spread mechanics before they read a single page about strategy.

According to the U.S. Energy Information Administration, U.S. operable atmospheric distillation capacity stood at 18.4 million barrels per calendar day on 1 January 2025, essentially flat year-over-year, with 132 operable refineries — the same headcount as 2024. No greenfield refinery has been built in the United States since 1976. The story of the last decade has been capacity creep at the largest sites: Marathon's Galveston Bay (665,000 b/sd) and Motiva Port Arthur lead the table, while smaller plants close or convert to renewable fuels.

What is actually growing — and what is shrinking

McKinsey and EIA both show transportation fuel demand growing 0.5–1% annually, while petrochemical and plastics feedstock demand grows 3–4%. That gap is the single most important strategic input in a 2026 refining business plan. New entrants who size for gasoline-heavy slates risk launching into a flat-to-declining product market. Operators converting capacity to renewable diesel, sustainable aviation fuel, or aromatics for petrochemical complexes are reading the demand curve correctly.

On the supply side, no major refinery expansions or transactions occurred between January 2024 and January 2025 — a notable contrast with 2023, when ExxonMobil's Beaumont expansion and Motiva's Port Arthur uplift added meaningful barrels. The pause matters: it tells lenders that incumbent operators are choosing capital discipline over volume growth, which keeps the medium-term supply curve tight and supports merchant refiner margins. Your plan should explicitly cite this dynamic when explaining why a new modular topping unit can sustain a $12–$16/bbl gross margin against a backdrop of nominal capacity contraction.

Outside North America, Africa is the only region with meaningful new-build refinery activity. Nigeria's Dangote Petroleum Refinery (650,000 bpd, $19B capex, commissioned January 2024) is the world's largest single-train facility and reset West African product flows in eighteen months. Smaller modular plants from Waltersmith and Edo Refinery are licensed by the Nigerian Upstream Petroleum Regulatory Commission (formerly DPR), and the latest tranche added four more modular licences. Anyone planning a refinery in Africa, the Middle East, or South Asia needs a paragraph in the executive summary explaining how their plant differentiates from Dangote's slate and pricing.

Questions buyers and lenders ask first

Before tackling the financials, address the questions Google's People Also Ask box surfaces for "oil refinery." These are the questions a banker or a sponsor's investment committee will ask in the first ten minutes of your pitch.

How much does it actually cost to build a refinery?

The honest answer spans three orders of magnitude. A used-motor-oil re-refining skid running 250 barrels per day of waste oil costs $2.5M–$5M including site works. A modular crude topping unit at 1,000–5,000 bpd costs $30M–$150M turnkey. A full conversion-grade refinery at 100,000 bpd or above runs $1B–$10B, with the Dangote complex at $19B for 650,000 bpd. The benchmark for modern modular construction sits at roughly $30,000 per barrel/day of installed capacity, per published industry data.

Can a small company really build a refinery?

Yes, but only at the modular end of the spectrum. The economic floor for a viable plant is around 1,000 bpd; below that, fixed overhead consumes margin. Most "small" refining ventures in the United States today are either used-motor-oil re-refiners (Crystal Clean is the largest, processing waste lubricants into Group II base oils) or specialty distillation plants serving local trucking, agricultural, or marine fuel markets.

Why has no new US refinery been built since 1976?

Permitting timelines and risk-adjusted returns. PSD permits routinely take 12–30 months. Title V operating permits add another 9–18 months. A NEPA challenge on greenfield siting can extend total approval by years. With existing operators able to expand brownfield capacity through deeper conversion at a quarter of the cost and a fraction of the timeline, no merchant refiner has chosen greenfield. Plans that ignore this history get rejected at term-sheet stage; plans that explain why a modular brownfield is the only viable path get funded.

What is a crack spread and why does it matter?

The crack spread is the difference between the cost of a barrel of crude and the combined market price of the refined products it yields. The 3:2:1 crack spread (three barrels of crude → two barrels of gasoline plus one barrel of distillate) is the reference benchmark. In Q1 2025, EIA reported margins fell slightly. By Q3 2025, refining margins had reached year-high levels. By March 2026, ULSD futures crack spreads briefly hit a record $86.25 per barrel on geopolitical disruption. Margin volatility, not crude price level, is the dominant risk factor in a refining model.

Do you need an EPA permit to operate?

Multiple permits. PSD for new construction, Title V for ongoing operation, NESHAP MACT II for hazardous air pollutants (with a fenceline benzene action level of 9 µg/m³), NPDES for wastewater discharge, and RCRA Subtitle C authorization for hazardous waste handling. State agencies — TCEQ in Texas, LDEQ in Louisiana, SCAQMD in California — administer most permits under EPA delegated authority. There is no shortcut.

Capital costs by refinery archetype

Founders compress wildly different projects under the label "refinery." A bank reviewing a refining loan needs to know within the first paragraph which archetype they are reading about. The four most common entry archetypes — used-motor-oil re-refining, modular crude topping, mid-scale modular conversion, and renewable diesel retrofit — have radically different capex, opex, regulatory exposure, and time-to-revenue.

Used-motor-oil re-refining ($2.5M–$5M total)

The lowest-capital entry route. A 250 barrel-per-day re-refining skid (PESCO and similar OEMs are common) processes waste lubricating oil into Group II base oils and diesel-range distillates. Equipment includes a thin-film evaporator, clay treatment, hydrofinisher (optional), fuel boiler, and storage. Feedstock is collected from oil-change shops, fleet operators, and industrial sites — typically at $0.50–$1.50 per gallon depending on logistics. Resale of the rerun base oil at $4–$6 per gallon, plus diesel-range distillates at rack pricing, generates the spread.

Modular crude topping unit (1,000–5,000 bpd, $30M–$150M)

A topping plant runs an atmospheric distillation column with no downstream conversion (no FCC, no hydrocracker). Output is naphtha, kerosene/jet, diesel, and atmospheric residue. Margins are thinner than full-conversion refineries because the residue (typically 30–40% of the barrel) sells at a discount to crude — but capex per barrel is a fraction of the alternative. Suitable for landlocked markets with a stable diesel demand and no nearby competition (Cushing OK, Williston ND, parts of West Africa, Iraqi Kurdistan).

Mid-scale modular refinery (10,000–20,000 bpd, $300M–$600M)

Adds a vacuum distillation unit (VDU), a catalytic reformer (for octane and hydrogen), and often a hydrotreater to meet ULSD specs. The unit-economics improve dramatically: full slate of on-spec gasoline and diesel at rack price. This is the sweet spot for African and South Asian projects where local fuel imports trade at a 10–20% premium to international rack pricing.

Renewable diesel / SAF conversion ($500M–$1.5B+)

Existing petroleum refineries — most visibly in California — are being converted to process tallow, used cooking oil, and soybean oil into renewable diesel and sustainable aviation fuel. The conversion is faster and cheaper than greenfield biorefinery construction because the hydrotreating, separation, and tankage assets carry over. The AltAir / World Energy Paramount conversion and Eni's Livorno retrofit are the reference precedents. Some conversions exceed $1B in capex.

Detailed capex breakdown for a 5,000 bpd modular topping plant

• Crude pre-heating + atmospheric distillation column: $18M–$28M
• Naphtha stabiliser + product treaters: $4M–$7M
• Furnace + heat integration train: $6M–$10M
• Tankage (crude + 4-product slate, 7-day inventory): $14M–$22M
• Flare, blowdown, slop oil system: $2M–$4M
• Utilities (power, steam, cooling, instrument air, nitrogen): $6M–$11M
• Wastewater treatment (API separator, DAF, biological): $4M–$8M
• Loading rack (rail or truck) + product blending: $5M–$9M
• Site civil, foundations, piling: $8M–$15M
• EPC engineering, procurement, project management: $14M–$22M
• PSD permitting, Title V application, NESHAP fenceline monitoring: $1.2M–$3M
• 90-day crude inventory at $70/bbl WTI = $31.5M working capital line

Round numbers for the 5,000 bpd archetype: $80M–$140M total project cost depending on site, plus $25M–$40M working capital for crude inventory. Almost every line item has an inflation factor since 2022 — quoted contractor rates for refinery EPC work are 18–28% above 2021 levels per industry benchmarks.

Process units & equipment specification checklist

Lenders and offtake counterparties scrutinise the process flow diagram before they read the financials. A complete equipment list, with named licensors and rough capacity, signals that the founder has actually engaged with EPC firms rather than copying a generic refinery diagram. The list below covers the standard kit for a 5,000–15,000 bpd modular plant; renewable diesel conversions use a related but distinct subset (mainly hydrotreating plus pretreatment).

Distillation and conversion units

• Crude Distillation Unit (CDU) — atmospheric column, 60-90 trays or structured packing. Common licensors: UOP (Honeywell), Axens, KBR. Tray suppliers include Sulzer, Koch-Glitsch, Raschig.
• Vacuum Distillation Unit (VDU) — for slates with >20% atmospheric residue. Recovers LVGO and HVGO as cracking feed. Required for any conversion-grade refinery.
• Catalytic Reformer — converts naphtha into high-octane gasoline blendstock and produces hydrogen. UOP Platforming and Axens Octanizing are the dominant technologies.
• Hydrotreater (Naphtha + Diesel) — removes sulfur to meet ULSD (15 ppm) and Tier 3 gasoline (10 ppm). Catalysts from Albemarle, Haldor Topsoe, Shell Catalysts & Technologies.
• Hydrocracker (optional) — converts heavy gas oil to diesel and jet. Shell, Chevron Lummus Global (CLG), and Axens hold the bulk of operating licences.
• Fluid Catalytic Cracker (FCC) — converts VGO to gasoline + light olefins. Major licensors: UOP, KBR, Axens, Stone & Webster.
• Alkylation unit — combines isobutane with light olefins to produce alkylate, a high-octane gasoline component. Sulfuric or HF acid technology.
• Hydrogen plant — steam methane reformer (SMR) or electrolyser. Required for any plant running a hydrotreater or hydrocracker. Air Products, Linde, and Praxair (Linde) dominate hydrogen supply contracts.

Utilities, safety, and bulk equipment

• Storage tanks — API 650 carbon steel for crude and products; floating roof for gasoline (vapour control); fixed roof for diesel/distillates. Typical sizing: 7-day crude + 4-day finished product.
• Flare and blowdown system — ground or elevated flare; staged smokeless design to meet NESHAP MACT II flare emission limits.
• Wastewater treatment — API separator, dissolved air flotation (DAF), biological treatment. Discharge under NPDES permit.
• Cooling tower — induced or forced draft; usually 3-5 cells for a mid-scale plant.
• Boilers + steam network — at least 2 boilers (N+1 redundancy); typical pressure ranges 600 psig and 150 psig.
• Instrument air + nitrogen plant — required for emergency purging.
• Fire water system — NFPA 11/15 deluge and foam coverage on tanks and process units.
• DCS / SCADA — Honeywell Experion, Emerson DeltaV, Yokogawa CENTUM, or ABB 800xA dominate the control system market.

Standards and licensor selection

Every reactor and pressure vessel design must comply with ASME Section VIII. Hydroprocessing reactors additionally follow API 934-A/C for materials. Tank inspection is governed by API 653 on a 5–20 year cycle depending on service. For licensor selection, modular projects often choose Axens or UOP for atmospheric distillation, Shell Catalysts & Technologies for hydroprocessing, and a single EPC contractor (Wood, Worley, KBR, Petrofac, Saipem, McDermott, Bechtel) to wrap the lump-sum turnkey. Used process equipment can be sourced through brokers such as Louisiana Chemical Equipment Company and Aaron Equipment, where 250 bpd PESCO re-refining plants and complete used distillation columns trade regularly.

Crack spreads, refining margins, and unit economics

The single most common error in early refining business plans is modeling revenue from the crude price up. The right model anchors on the crack spread — the spread per barrel that the plant captures regardless of crude direction. Refiners do not profit when oil rises; they profit when the spread between crude and products widens.

Reference crack spread environment, 2025

• Q1 2025: Refining margins down slightly Q-on-Q per EIA Today in Energy.
• Q3 2025: Margins reach year-high; Valero +44% per barrel; refining margins highest of 2025 per EIA.
• Q4 2025: Marathon discloses $18.65 per barrel, 95% utilization.
• March 2026: ULSD futures crack spread spikes to record $86.25/bbl on geopolitical disruption (transient, not modelable).

Worked unit economics — 5,000 bpd modular topping plant

Assume a modular topping unit running 90% utilization on light sweet WTI feed in PADD 2 (Cushing-area logistics). Annual throughput = 5,000 × 365 × 0.90 = 1,642,500 barrels.

• Gross refining margin at $14/bbl (a conservative assumption, well below Marathon's disclosed $18.65/bbl since topping plants do not capture conversion uplift): $22.99M / yr.
• Variable opex (catalysts, chemicals, utilities, fuel gas, electricity) at $4.50/bbl: $7.39M / yr.
• Fixed opex (35 FTE labor at fully loaded $145K, maintenance at 2.5% of capex, insurance, property tax, third-party inspection): $11.0M / yr.
• EBITDA: $22.99M − $7.39M − $11.0M ≈ $4.6M / yr.
• At a $90M total project cost, this implies an EBITDA / capex of 5.1% in a flat-margin year. In the Q3 2025-style spread environment ($18/bbl gross), EBITDA would step up to roughly $11M and 12% return on capex.

Worked unit economics — 250 bpd used-motor-oil re-refiner

• Throughput: 250 bpd × 320 operating days ≈ 3.36M gallons/year of waste oil feed.
• Yield: ~75% rerun base oil + diesel-range distillates ≈ 2.5M gallons saleable.
• Gross margin: $1.20/gallon spread (resale price minus waste-oil acquisition + transport): $3.0M / yr.
• Operating expenses (8 FTE, energy, clay disposal, maintenance): $1.5M / yr.
• EBITDA: ~$1.5M / yr against a $3.5M project cost ≈ 43% EBITDA / capex. This is why the small re-refiner archetype is the only entry route some sponsors recommend for first-time operators.

Margin sensitivities the model must show

The lender's first ask after seeing base case is a sensitivity table. Stress-test your model on (a) crack spread compression by $4/bbl, (b) utilization drop to 80%, (c) crude basis differential widening by $2/bbl, and (d) a scheduled 21-day turnaround in Year 3. Each scenario should show debt service coverage above 1.20x in your worst case. If it does not, the project is not financeable on conventional bank debt and must add mezzanine, sponsor equity, or an offtake-prepayment structure.

Product slate and offtake

A 5,000 bpd modular topping plant typically yields a slate close to: 12% naphtha, 18% kerosene/jet, 35% diesel, 30% atmospheric residue, 5% LPG/fuel gas. The naphtha sells as petrochemical feedstock or is blended into gasoline at a host refinery; jet and diesel sell at rack pricing; residue sells as feedstock to a coker or as bunker fuel at a discount. Lenders want to see signed offtake agreements or, at minimum, a marketing services contract with a major (Vitol, Trafigura, Mercuria, Glencore, Sunoco, Pilot Flying J for retail diesel) before they release the construction draws.

Funding stack: SBA, term loans, mezzanine, and project finance

Refinery projects almost never sit cleanly inside the SBA 7(a) box because the maximum loan size is $5M. That said, a small re-refining or specialty distillation project can fit, and the SBA's NAICS 324110 (Petroleum Refineries) allows a "small" classification at up to 1,500 employees or up to 200,000 b/cd — so size is rarely the constraint. The constraint is collateral and environmental risk: SBA-affiliated lenders are cautious on hazardous-substance facilities because of CERCLA exposure.

SBA 7(a) — feasible for re-refining and specialty distillation

• Maximum loan: $5M.
• Typical interest: prime + 2.25%–2.75% on variable-rate notes.
• Term: up to 25 years for real estate, 10 years for equipment.
• NAICS 324110 size standard: up to 1,500 employees or 200,000 b/cd refining capacity.
• Lender preference: well-established re-refiners (used motor oil collection routes, base oil offtake) rather than crude refining. Look for SBA Preferred Lenders with energy experience — Live Oak Bank, Byline, Wells Fargo SBA group.

Senior bank syndicate — the workhorse for $30M–$300M projects

• Tenor: 7–12 years amortising; sometimes a 3-year construction draw period plus 7-year mini-perm.
• Rate: SOFR + 250–425 bps depending on offtake quality.
• Collateral: first lien on plant, tankage, real estate, and assigned offtake receivables. Often a Debt Service Reserve Account funded with 6 months of debt service.
• Covenants: minimum DSCR 1.30x, maximum leverage 3.5x EBITDA after stabilisation, CapEx restrictions, and reserve tail.
• Active lenders for energy/refining: Wells Fargo, JP Morgan, Citi, Truist, BMO, ING, Société Générale, Mizuho, MUFG, NatWest. Regional banks (Comerica, Cadence, Hancock Whitney) lead deals in PADD 3.

Mezzanine and energy private credit — for the gap between bank debt and equity

• Typical size: $10M–$50M for modular projects.
• Coupon: 10–14% cash plus 2–4% PIK; some funds take warrants.
• Active lenders: Riverstone Credit Partners, EIG, Ara Partners, Carlyle Energy Credit, BlackRock Energy & Power Infrastructure, Macquarie Energy Capital.
• Use of proceeds: bridge to first cash flow, working capital line, or contingency reserve.

UK funding routes

• Start Up Loans (UK) — up to £25,000 at 6%, government-backed via the British Business Bank. Useful for the planning, feasibility, and permitting stage but nowhere near sufficient for plant construction.
• Innovate UK + UK Infrastructure Bank — relevant for renewable diesel or SAF conversions; grants and concessional debt for projects that decarbonise fuel supply.
• UK Export Finance — relevant if the refinery is built abroad with UK EPC content.
• Senior bank debt — Lloyds, NatWest, HSBC, and Standard Chartered all have project finance teams that will look at modular refinery deals with a credible offtake structure.

Equity and sponsor structures

Sponsor equity is typically 25–35% of total project cost. Strategic partners include trading houses (Vitol, Trafigura, Gunvor) who take equity in exchange for offtake; midstream operators (Enterprise Products, Plains All American, Energy Transfer) who provide pipeline tie-in; and EPC contractors (a small minority of EPCs take limited equity stakes in their projects to align interests). For Africa and Middle East projects, the IFC, AfDB, and FMO frequently anchor capital stacks with concessional debt. Investors expect a clear waterfall: distributions only after senior debt is current, DSRA is funded, and a 12-month operating expense reserve is held.

Permitting in the United States, the United Kingdom, and beyond

Permitting is the single largest non-construction risk in a refining project. Plans that omit a credible Gantt with permitting on the critical path get rejected before financial review. The summary below covers the three regulatory environments most relevant to Avvale clients; your final plan should expand the relevant subsection into a 6–10 page chapter.

United States

• PSD (Prevention of Significant Deterioration) Permit — required for any new major source under the Clean Air Act. Issued by EPA Region or delegated state authority. Application requires Best Available Control Technology (BACT) analysis, air quality modeling, and a one-year ambient monitoring baseline. Typical legal + engineering cost $250K–$1.5M; timeline 12–30 months.
• Title V Operating Permit — operating umbrella required after construction. State agency leads. Cost $50K–$300K plus per-ton emission fees; timeline 9–18 months.
• NESHAP Refinery MACT II (40 CFR 63 Subpart UUU and CC) — the EPA's air toxics standard for refineries. The fenceline benzene action level is 9 µg/m³ over a 14-day rolling annual average. Exceedance triggers root-cause analysis and corrective action. The current rule is projected to reduce benzene emissions by 53,000 tons annually across the sector. Capex impact for legacy plants typically $5M–$50M. See the EPA's Petroleum Refinery Sector Rule.
• NPDES Wastewater Discharge Permit — Clean Water Act. EPA or state-delegated agency. Cost $30K–$200K; timeline 6–12 months.
• RCRA Subtitle C Hazardous Waste Authorization — handling of refinery solid wastes (spent catalyst, tank bottoms, slop oil). Cost $20K–$100K per facility.
• PHMSA pipeline / DOT 49 CFR 195 — for any product pipeline tie-in. Ongoing inspection regime.
• State and local — TCEQ in Texas, LDEQ in Louisiana, SCAQMD in California, NJDEP in New Jersey. California's CARB regulations layer additional emissions and product-spec requirements that materially affect economics.
• EPA petroleum sector overview: epa.gov/regulatory-information-sector/petroleum-sector-naics-324.

United Kingdom

• COMAH 2015 Top Tier Designation — any refinery exceeding the qualifying inventory of dangerous substances is automatically Top Tier. Operators must submit a written safety report to the Competent Authority within statutory timeframes and prepare on-site and off-site emergency plans. The CA is jointly the HSE and the Environment Agency in England, SEPA in Scotland, and Natural Resources Wales in Wales. See HSE COMAH guidance.
• Safety Report writing cost: £200K–£1M. CA chargeable hours typically £140/hour. CA review can take 6–12 months. The Chevron Pembroke refinery 2011 explosion case study illustrates the consequences of inadequate safety report execution.
• Bespoke Environmental Permit (Schedule 1, Section 1.2 — refining of mineral oil) — issued by the Environment Agency under the Environmental Permitting (England and Wales) Regulations. Application £25K–£150K; subsistence fees by activity tier; timeline 4–13 months.
• Hazardous Substances Consent — required from the local planning authority for storage of named substances above threshold quantities.
• UK ETS — refineries surrender carbon allowances annually. 2025 allowance prices ranged £35–£50/tCO2; a typical refinery emits 0.3–0.6 tCO2 per barrel processed. For a 5,000 bpd plant at 0.4 tCO2/bbl, annual ETS exposure ≈ 730,000 tCO2 × £40 = £29M (free allocation reduces the net cash impact substantially).

Nigeria (and the broader West Africa permit map)

• NUPRC (formerly DPR) Licence to Establish — preliminary licence allowing site studies, EIA, and FEED.
• Approval to Construct — issued after FEED and EIA approval; allows mobilisation and construction.
• Licence to Operate — final operating licence; conditional on commissioning, performance test, and safety report.
• Application fees: General Category ₦5,000; Major Category ₦5,000; Special Category (which covers refinery licences) ₦250,000. The headline numbers understate effective cost — a refinery licence dossier typically requires $0.5M–$2M of consulting work to assemble.
• The latest licence tranche added four modular refinery permits (alongside Waltersmith, OPAC, Edo). Dangote Petroleum Refinery, commissioned January 2024, holds the largest single-train licence in the world at 650,000 bpd.

EU and Canada in brief

EU refineries operate under the Industrial Emissions Directive (IED) BAT-AEL framework, the Seveso III Directive (the European parallel to COMAH), and the EU Emissions Trading System. Each member state designates a competent authority. In Canada, the Alberta Energy Regulator and federal Impact Assessment Act govern new builds. Both jurisdictions use a carbon-pricing mechanism that directly reduces refining margins on every barrel processed.

Six expensive errors first-time refiners make in their plan

1. Pricing the project on crude price instead of crack spread

Investors see this immediately. The line "we project oil prices to rise to $X" is a red flag because it implies the founder believes the refinery profits from absolute crude price. Refiners earn the spread. Replace any oil-price-prediction language with a spread-history chart and an explicit downside scenario at $8/bbl gross.

2. Underestimating PSD permitting timeline

A 12–30 month PSD timeline is normal. Plans that show "permits secured Q2" in a 12-month construction Gantt fail diligence on the first read. The credible Gantt has permitting and front-end engineering running in parallel for 18–24 months before the construction notice to proceed.

3. Treating modular as plug-and-play

Modular construction shifts work to the fabrication yard but does not eliminate site work. Foundations, tankage, flare, control room, switchgear, fire water, and tie-ins to grid power, water, and product evacuation typically add 60–110% on top of the modular skid sticker price. A $30M skid quote becomes a $60M–$80M total installed cost. Lenders will ask for a P50/P90 cost certainty range from a third-party cost engineer.

4. Skipping signed offtake before construction draw

No senior bank releases construction draws on a refinery without either (a) signed offtake agreements covering 70–100% of expected production, or (b) a marketing services contract with a recognised trader that includes a price-at-rack mechanism. Plans that wave at "we expect strong local demand" without a counterparty list rarely move past intercreditor.

5. Missing fenceline benzene monitoring obligations

The NESHAP MACT II refinery fenceline rule is not optional. The 9 µg/m³ benzene action level triggers a root-cause analysis and a corrective action plan that EPA enforcement staff actively police. Capital provision of $1.5M–$5M for fenceline monitors (Atmospheric Sciences, Argos, Picarro), data management software, and inspection routines belongs in the capex line, not the contingency.

6. Building for gasoline yield in a diesel + SAF market

Transportation fuel demand grows 0.5–1% per year; petrochemical and SAF demand grows 3–4%. A new modular plant designed around a 50% gasoline slate is structurally underwater on five-year demand. Plans that demonstrate slate flexibility — a hydrocracker option, a renewable diesel co-processing block, or a petrochemical naphtha export route — receive materially better term sheets.

Sample plan extract — executive summary

This 380-word summary is the type of opening a senior banker will read. The full template includes 9 chapters: executive summary, market and competitive landscape, technology and process design, regulatory and permitting strategy, project execution plan, organisational structure, financial projections, sensitivity analysis, and risk register.

What's inside the Avvale oil refinery business plan template

The template is a 38-page Word document with a linked Excel financial model. It is structured for a refining-specific reader — senior bankers, project finance lawyers, EPC bid teams, and offtake counterparties — and uses the chapter ordering favoured by IFC and the major commercial banks.

• Executive summary with crack spread sensitivity, capital ask, and use of proceeds
• Market chapter covering global refining capacity, crack spreads, regional demand by PADD or by African/Middle East market
• Technology and process design — block flow diagram placeholder, licensor selection rationale, slate yield table
• Site selection criteria — crude logistics, product evacuation, water, power, labor catchment
• Regulatory and permitting plan — PSD/Title V/NESHAP/NPDES/RCRA Gantt for US; COMAH safety report and EA Bespoke Permit Gantt for UK; NUPRC three-stage licence for Nigeria
• Project execution plan — EPC strategy (LSTK vs split LSTK + reimbursable), schedule, contingency, risk allocation
• Organisational chart with role descriptions for ~35 FTE at the 5,000 bpd archetype scale
• Five-year financial model: monthly Year 1, annual Years 2–5; income statement, balance sheet, cash flow, capex schedule, debt schedule
• Sensitivity tables on crack spread, utilization, crude basis differential, debt cost, and turnaround timing
• Risk register covering technical, market, regulatory, counterparty, environmental, and political risks
• Appendices: equipment list, license summaries, comparable transactions, glossary

Where you fit on the spectrum determines how much of the template you'll customise. Re-refining founders will skip the FCC and hydrocracker sections; renewable diesel converters will replace the conversion chapter with a feedstock supply analysis (UCO, tallow, distillers corn oil); large-greenfield sponsors will expand the project execution chapter into a separate volume.

Frequently asked questions

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