Suriname’s Gas-to-Shore IPO: A Game Changer

GLIAG Essay · Gas-to-Shore (GtS) · Bankable IPO Case · 22 October 2026

Before Suriname’s Gas Sails Away

The bankable Gas-to-Shore IPO case, and the terms Suriname must secure before the Sloanea FID

Suriname’s first offshore gas field is being designed for a floating LNG plant and the export market.

The development plan and the investment decision are being prepared now, between Staatsolie and PETRONAS.

A country that is short of power has a few months left to reserve part of that gas for itself, on terms that lenders will finance and that the IMF will accept.

By Drs. M.P.T. Chin-A-Lien, MBA, M.Sc., Ing. Geologist · Golden Lane Investments Advisory Group B.V.

On 11 November 2025 Staatsolie approved the Sloanea gas discovery in Block 52 as a commercial field.

PETRONAS operates the block with 80%; Staatsolie’s subsidiary Paradise Oil Company holds 20%.

The two companies evaluated how to monetise the gas and agreed a gas addendum to the 2013 production-sharing contract; the selected concept combines subsea wells with a floating LNG facility, a first for the region (Staatsolie; Rigzone).

PETRONAS is now drafting the development plan for Staatsolie’s approval. The final investment decision is targeted for the second half of 2026, with first gas around 2030, and has not yet been announced (Global Energy Monitor, October 2026).

President Jennifer Simons has made Gas-to-Shore a priority project, and a State team drawn from the presidency, the ministries of Oil, Gas and Mining and of Natural Resources, and Staatsolie has been formed around it (Starnieuws).

The terms on which Sloanea is sanctioned are therefore being discussed now.

Once the FID is taken and the LNG offtake contracts are signed, the molecules are spoken for.

Gas that is not reserved for Suriname before then will be very hard to bring back.

I have worked the Guyana–Suriname Basin for more than 2 decades, and between 2008 and 2010 I helped Staatsolie bring Tullow, Kosmos, Murphy and Repsol into Suriname’s offshore.

I have argued for Gas-to-Shore in a series of essays since February 2026, listed at the end of this one.

What follows rests on that rebuilt model, GLIAG-FM-2026-GTS-001 Rev 002, and on public data as of October 2026.

Both the New Refinery IPO project proposal as well as this GtS IPO project proposal.

Are part of my self-architected Suriname Horizon 2050 and Beyond doctrine, vision and mission.

That is supported by and relates to the Conversion Trilogy, Suriname 2050 and Beyond & Syncronization Navigator, as published extensively on my website.

1. A country short of power

Suriname’s main grid is running out of headroom.

Peak demand in the Paramaribo–Para area has risen to about 280 megawatts against about 254 megawatts of available capacity; demand is up about 10% on 2025, and EBS estimates that about US$500 million of new generation is needed (Keynews, 2026).

The 189 MW Afobaka hydro plant carries the base load, and heavy-fuel-oil and diesel plants fill the gap (IDB, SU-L1055).

When the reservoir fell during the drought of 2024–25, EBS had to rent diesel generators to avoid load shedding.

Figure 1 · Suriname main grid (EPAR), 2026, megawatts

Peak demand · ≈280 MW

Available capacity · ≈254 MW

Afobaka hydro · 189 MW

Sources: Keynews (2026); IDB project document SU-L1055.

2. What the IMF is asking for

The IMF’s 2025 Article IV mission was explicit: electricity subsidies should be removed, the automatic link between tariffs and the cost of electricity production established in 2024 should be restored, and prices should keep rising towards cost recovery (IMF Staff Concluding Statement, November 2025).

The Executive Board added that offshore oil should lift growth to around 30% from 2028, and that strong institutions are needed to manage the revenue (IMF Press Release 26/025, January 2026).

There is a tension in that advice that Gas-to-Shore resolves.

Cost-recovery tariffs are hard to defend politically when the cost being recovered is that of burning imported fuel oil.

Lower the cost of generation, and cost recovery stops being a burden on households and becomes a reform the country can sustain.

That is the economic logic of Gas-to-Shore, and it is the reason this case is written for the IMF as much as for investors.

3. What Guyana built next door

Guyana faced the same problem and chose gas.

Its Gas-to-Energy project brings associated gas from the Liza field to a 300 MW combined-cycle plant and a natural gas liquids plant at Wales.

ExxonMobil built the pipeline, about US$1 billion of a total of roughly US$1.8 billion, and the government is paying for the plant (OilNOW).

The goal is to halve tariffs from US$0.22 to US$0.11 per kWh and save at least US$100 million a year (DPI Guyana).

The plant contract of US$759 million was settled at 12.8% above its original sum (OilNOW, 2026), and the first turbine is expected around December 2026, about two years late (Rio Times, 2026).

The US Export-Import Bank approved more than US$526 million (US EXIM).

Crucial aspect	Guyana, Wales	Suriname GtS (GLIAG case)
Gas source	Associated gas from producing oil fields (Liza)	Non-associated gas field (Sloanea), developed for LNG
Pipeline	Built by ExxonMobil, ≈US$1bn, cost-recovered	Upstream-built under the Block 52 terms (GLIAG proposal)
Gas terms	“Free gas” arrangement	Cost-reflective price, negotiated with the tariff
Plant	300 MW CCGT + NGL; US$759m, settled +12.8%	300 MW CCGT + NGL; US$856m budget
Owner	Government of Guyana	Onshore company, listed in 2035; ≈half Surinamese
Finance	Treasury plus US EXIM	ECA, IDB Invest, Afreximbank, Surinamese bond
Tariff target	US$0.22 → US$0.11 per kWh	≈US$0.11 per kWh PPA with EBS
Schedule	About two years late	Two-year delay tested in the model

Sources: OilNOW; DPI Guyana; Rio Times; US EXIM; GLIAG model GTS-001 Rev 002.

Two differences matter most.

Guyana’s gas comes from oil fields that would produce it anyway;

Sloanea’s gas has an export alternative, so its price must be negotiated.

And Guyana’s plant sits on the government’s balance sheet, while GLIAG’s case puts Suriname’s plant in a company that private lenders finance and Surinamese savers can own.

4. The question that decides bankability

GLIAG tested two ways to own a Suriname project of Guyana’s size: about 50 million standard cubic feet of gas a day into a 300 MW combined-cycle plant and an NGL facility, selling power to EBS at 11 US cents per kWh.

If one company owns everything, including a pipeline of about US$1 billion, it fails a lender’s test: a 6.2% project return and a minimum debt cover of 0.89×.

It would need a tariff of 15.4 US cents to reach 10%, more than the fuel-oil power it replaces.

If the pipeline is built and cost-recovered within the upstream development, as in Guyana, an onshore Power & NGL company of about US$856 million stands on its own (GLIAG model GTS-001 Rev 002; nominal terms; NPV at 10% to end-2026).

Figure 2 · Project IRR by ownership structure, %

One company owns pipeline and plant · 6.2%

Pipeline upstream, onshore company stands alone · 14.3%

Whole system, economic return to Suriname · 15.0%

Source: GLIAG model GTS-001 Rev 002 (October 2026).

14.3%

Project IRR, onshore company

17.8%

Equity IRR

+US$271m

NPV at 10%

1.81×

Minimum debt cover, 50% debt

5. What Suriname gains, and what it pays

Moving the pipeline upstream does not make it free.

Under production-sharing terms its cost is recovered from Block 52 production, so the State pays for it through a smaller share of profit gas. An IMF mission will want that cost in the budget, and so does GLIAG.

Judged as a whole system, pipeline included, Gas-to-Shore returns 15.0% to Suriname, with an economic net present value of about US$739 million at 10%.

Replacing thermal power that costs about 15 US cents per kWh with an 11-cent power-purchase agreement saves about US$144 million a year over the first decade (GLIAG model and judgement).

Phase 1 uses about 0.45 Tcf over 25 years: of the same order as Staatsolie’s 20% share of a field in the 1–2.5 Tcf range that GLIAG’s essays have discussed (GLIAG arithmetic; operator volumes are not yet public).

15.0%

Economic return to Suriname

+US$739m

Economic NPV

≈US$144m

Lower power cost per year

≈0.45 Tcf

Gas used over 25 years

6. The price of a molecule

The hardest question will come from PETRONAS and from the IMF: why sell gas at home when the world pays more for it as LNG? On 16 October 2026 Henry Hub stood at about US$3.1 per MMBtu, while European TTF and Asian JKM were near US$29 (Global LNG Hub).

GLIAG’s base case prices gas at the shore at US$2.5 per MMBtu, reflecting a cost-recovered pipeline.

At US$6.0 the onshore company’s return falls to 9.2% and debt cover to 1.23×; with a 13-cent tariff it recovers to 12.5% and 1.61×. Gas price and power tariff must therefore be negotiated as one package.

Phase 1 needs about 50 MMscfd, a small share of an export development of this kind (GLIAG judgement).

The domestic tranche does not compete with LNG; it completes it. This is what GLIAG calls the Sovereign Molecule™: gas that is legally reserved for the country before the export architecture closes.

7. PETRONAS knows this model from home

Suriname does not need to invent its negotiating position.

It can ask PETRONAS for the principle on which Malaysia built its own gas economy.

Malaysia’s Petroleum Development Act of 1974 vested the country’s petroleum resources in PETRONAS; the National Petroleum Policy of 1979 followed; and the Peninsular Gas Utilisation project, approved in 1981, delivered first gas on 1 August 1984, bringing offshore gas ashore to power stations and industry across the peninsula (PETRONAS, Energy Commission of Malaysia).

The Gas Supply Act of 1993 then provided for the supply of gas at reasonable prices (Gas Supply Act 1993, Act 501).

Malaysia’s experience also carries a warning that strengthens Suriname’s case rather than weakening it.

PETRONAS itself has told Malaysia’s Energy Commission that years of regulated, below-cost gas prices created unsustainable demand and revenue forgone, and it has pressed for domestic gas-price reform.

The lesson for Suriname is precise: reserve the molecules, build the shore infrastructure, and price the gas at a cost-reflective level that the power tariff can carry.

That is a position PETRONAS will recognise, because it is the one PETRONAS argues for at home.

Three principles for the Sloanea terms, before FID

1. A defined domestic gas tranche for Suriname, written into the development plan.

2. A shore-line right of way and tie-in capacity, so that later discoveries in Block 52 can use the same line.

3. A cost-reflective gas price, set together with the power tariff.

8. Stress-tested

GLIAG ran 5,000 probabilistic cases, with ranges skewed deliberately to the downside: capital cost up to 40% over budget, tariffs from 9.5 to 12.5 cents, plant load down to 65%, gas up to US$4.0, no NGL at all, and delays of up to two years.

Net present value stayed positive in 86% of cases and debt cover held at 1.30× or better in 84%.

The median project return was 11.8%. The project breaks even at a capital cost of about US$1.30 billion or a tariff of about 8.1 cents (GLIAG model GTS-001 Rev 002).

86%

Chance of positive NPV

84%

Runs with debt cover ≥ 1.30×

US$1.30bn

Break-even capital cost

8.1¢

Break-even tariff per kWh

9. The IPO case: a company Suriname can own

The onshore company is designed to be listed.

GLIAG’s case ends in an IPO in 2035, after three years of operations, at an equity value of about US$1.1 billion, with about half of the shares in Surinamese hands.

The capital exists: Surinamese investors filled Staatsolie’s 2025–2033 bond with US$515.8 million in March 2025.

The lenders exist too: export credit agencies, development banks and Afreximbank, with which Suriname ratified a partnership agreement on 5 April 2025.

The national long-term view is set out in the Suriname 2050 report of the Planning Office, which already expects the gas revenue picture to be revised once Sloanea is sanctioned.

10. What this essay does not tell you

The numbers above are the result.

The route to them is in GLIAG’s Gas-to-Shore Bankable 5-Pack, and it is not in this essay.

The 5-Pack sets out what must be built and what each part costs, the capital structure and the lenders, how Surinamese savers can own part of the company years before it lists, the gas and power contracts that make it bankable, the full negotiating position behind the three principles above, and the six conditions that must be met before any lender commits.

The first of those conditions has a deadline.

It must be met before the Sloanea final investment decision, which PETRONAS has targeted for the end of 2026.

The Gas-to-Shore Bankable 5-Pack

(GLIAG-IPO-2026-GTS-001, Rev 002):

Executive One-Pager, Terms of Reference, Bankable IPO Case, What Is Built and What It Costs, Financial Model Summary and Investor & Lender Deck.

Available to the Government of Suriname, Staatsolie, EBS, the IMF, the World Bank Group, Afreximbank, export credit agencies and qualified lenders and investors on request: info@gliag.com.

3. Independence of analysis. GLIAG prepared this analysis independently. It is not commissioned, reviewed or endorsed by the Government of Suriname, the Government of Guyana, the Government of Malaysia, Staatsolie, EBS, PETRONAS, ExxonMobil, the IMF, the World Bank Group, US EXIM, Afreximbank or any institution or publication named or linked.

4. Forward-looking statements. Projections, estimates and model results depend on assumptions that may prove wrong, including gas volumes and composition not yet published by the operator. Actual results may differ materially.

© 2026 Golden Lane Investments Advisory Group B.V. and Drs. M.P.T. Chin-A-Lien. All rights reserved. Golden Lane™, GLIAGOGRAPH™, Sovereign Molecule™, Sovereign Conversion Capacity™ and Caribbean Gas Arc™ are trademarks of GLIAG. The rightsholder expressly reserves this work from text and data mining, including for the training of artificial-intelligence and machine-learning systems, under Article 4(3) of Directive (EU) 2019/790.

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Marcel P.T. Chin-A-Lien - Principal Founder & Chief Architect of GLIAG N.V. - Golden Lane Investments Advisory Group — Marcel P.T. Chin-A-Lien – Principal Founder & Chief Architect of GLIAG N.V. – Golden Lane Investments Advisory Group