Frequently Asked Questions

1. Isn't this just a smaller Chart or Galileo project?

No. Chart sells equipment, not a project — it has no plant of its own and its customers have to assemble every other part of the export stack themselves. Galileo and Cryobox are modular plant manufacturers; Titan is a conventional mega-terminal developer; New Fortress Energy owns downstream generation offtake; Stabilis is an early-stage distributed player. Catoosa is the only player pursuing a producer-to-export modular thesis as one integrated offer — pipeline interconnect (ONEOK / Kinder Morgan / Tallgrass) plus modular liquefaction plus barge loading from a single port-locked origin. That places us in an uncontested lane between OEM-only, mega-only, and offtake-owned.

Modularity gives Catoosa the speed advantage: phased modular trains deliver first cargo in 2–3 years versus 5–8 for Chart and Linde mega-terminals. That shorter CAPEX cycle is what lets Catoosa contracts reset to market instead of locking into a 20-year base-load SPA.

2. How can small-scale modular CAPEX compete with virtual pipeline economics?

Catoosa's modular CAPEX is $50–200M versus $5–15B for a Gulf Coast mega-terminal — roughly two orders of magnitude lower — and the build time is 2–3 years instead of 5–8. Contract length is also shorter: 5–10 year contracts instead of a 20-year SPA. That right-sizing matters most for island-grid and industrial buyers in the Caribbean and Central America, where mega-terminal minimum-volume commitments blow up virtual-pipeline or ISO-tank inland-LNG economics. Modular trains scale to actual buyer demand.

The economic consequence: a buyer paying for 20-year SPA base-load volume through a Gulf Coast mega carries that minimum-throughput risk regardless of whether their grid actually draws it. A modular right-sized contract lets the buyer match cargoes to real consumption, which is what makes the difference for an island utility with a single swing-season peak.

3. What is the Catoosa-specific permitting and regulatory path (FERC NEPA, USCG, PHMSA)?

Catoosa has two parallel permitting tracks that run simultaneously rather than sequentially. Track A is the Tulsa Ports Authority land lease and Port Development Agreement (months 1–9). Track B is the feed-gas interconnect with competing proposals from ONEOK, Kinder Morgan (Midcontinent), and Tallgrass (Pony Express) — whichever is selected then executes a Gas Gathering or Transportation Agreement; FERC Form 567 may apply to the 4–6" lateral tap if the interconnect crosses onto an interstate pipeline segment.

The rate-limiting item on the overall timeline is the DOE NOTA filing, which must begin in parallel with Tracks A and B (months 1–3) because NOTA drives the 18–30 month authorization window. Track A and Track B are not on the NOTA critical path, but lease execution and the interconnect agreement are prerequisites for activating FEED once NOTA is granted.

For ISO-tank ocean transport from the Gulf to Caribbean and Central American buyers, U.S. Coast Guard and PHMSA hazmat-transport overlays apply to the vessel itself — this is a standard regulatory layer for any ISO-tank LNG shipment, not a Catoosa-specific permitting risk.

4. How does Catoosa priced-to-Henry-Hub compare to a Henry-Hub-plus-toll-plus-shipping stack?

Catoosa prices to Henry Hub — the U.S. benchmark — rather than Brent or JKM, which means we avoid the structural premium that competing terminals on oil- or Asian-desk-linked indices carry. For a Caribbean or Central American island utility, that alone removes a layer of basis risk that small buyers cannot hedge.

The liquefaction toll stack is also leaner than at a mega-terminal because Catoosa's modular CAPEX ($50–200M versus $5–15B) and 2–3-year build (versus 5–8) keep the project-level cost of capital inside Caribbean / Central American utility budgets. Add the 5–10 year contract length (versus 20-year SPA) and a buyer can step into delivered LNG without underwriting a 20-year base-load take-or-pay through a Gulf Coast mega — which is what made modular-format cargoes uneconomic for the islands in the first place.

The route itself — McLellan–Kerr to the Mississippi to a Gulf loading terminal, then to Jamaica, Dominican Republic, Panama, and the Bahamas — is the same export lane the section 5 route map already shows, with no project-specific chokepoint added by Catoosa's location.

5. What about offtake counterparty risk and routing reliability?

Two points. First, the modular format shrinks single-buyer concentration risk: phased, modular trains deliver incremental cargoes under 5–10 year contracts that reset to market, instead of locking a buyer into a 20-year SPA they have to underwrite before first cargo. That is fundamentally a different risk shape for an island utility than the base-load mega-SPA path.

Second, the buyer mix is diversified by design across island-grid and industrial end-users in Jamaica, the Dominican Republic, Panama, and the Bahamas — all destinations on the McLellan–Kerr → Mississippi → Gulf route map already filed in the Export Lane section. Diversification across four destination markets, not single-offtake concentration, is what underwrites routing reliability for any one buyer.