The plan as written is a no, and a restructured version of it is a go on economics with two criteria still failing.

Salerno's own case is a liquefied biomethane business shipped to Singapore. On a delivered-cost basis it returns minus 5.2% and would need $25.78/MMBtu against a $20 price. Liquefaction costs about $4.00/MMBtu, and the gas pipeline from Songkhla to Singapore already exists, so the plan pays for a step it does not need.

Compressed biomethane injected into that pipeline returns 16.3% on a 100 tonne-per-day first phase, against a 13% Go bar, with payback at 6.06 years including construction against an 8-year bar. All three of the brief's financial conditions clear: the price floor is $18.89 against $20, the feedstock ceiling 4.83 THB/Nm3 against 4.17 paid, and the route-cost ceiling $2.65 against $1.65.

Two criteria do not clear, and one gating condition sits above all of it.

Two of the three conditions clear by less than the unsourced content of the stack behind them: $1.15/MMBtu of the $12.33 delivered cost has no external source, against margins of $1.11 and $1.00. They are met on the modeled numbers and not with room to spare.

The gating condition is whether Thai biomethane can reach the Malaysian pipeline at all. The only physical link from the Songkhla corridor is the Trans Thai-Malaysia line, a 50/50 PTT and PETRONAS project company that transports for those two shareholders and nobody else; PTT's published access code governs a different asset. So the question is not what the tariff is but whether an access regime exists on that segment, and both owners sell the gas this project would displace. If the answer is no, the remaining route returns minus 5.2% and this is a No-Go.

The cost-stress case returns 5.8%, below the 8% No-Go floor, so the route condition fails on the brief's own wording even though the base case clears.

Salerno reaches $5.79M a year against a US$10M target: equity at 27.5% worth $2.40M, the joint-venture fee $3.12M, an operations contract $0.27M. The shortfall is structural. Two revenue lines the criterion allows, trading margin and custody fees, are not computed here.

Three findings behind the numbers.

The feedstock is about a third of what the plan assumes. An average Southern mill yields 11,252 Nm3 of biogas a day, not 30,000, so a 200 tonne-per-day hub needs about 32 of Southern Thailand's 70 mills and 32 of the 42 that have a digester, or 42 at the low end of the measured yield range. The client's own aggregation slide is short of its target by about three times: three mills at 30,000 Nm3/day make 39 tonnes a day, not the 100-plus claimed.

Contracted volume is the largest single risk to the return. The brief's own indicative offtake obliges about 60% minimum take, and at 60% the project returns 2.8%, below the No-Go floor. It needs 73.3% lifted to reach the 8% floor, 88.6% to reach the 13% bar, and full nameplate to reach the 16.3% above. Every headline figure here is computed at full nameplate because that is the client's own basis.

The client's model answers a different question. All eight scenarios are ex-plant, every transport input is zero, and the headline 36.3% case prices gas at Thai liquefied petroleum gas parity rather than at a Singapore price. It also charges working capital in full every year without releasing it.

The verdict. No to the project as planned. Go to a first stage of testing on the restructured plan, and to the build only on three answers: a written position that Thai biomethane may be transported to and injected into the Malaysian system at a charge at or below $1.50/MMBtu; take-or-pay at or above 89%; and a mill census confirming clusters of four within about 15 km. The first can end it.