How can Asia make offshore wind projects bankable? Lessons for governments, developers and lenders

Offshore wind is an asset class that requires “patient capital”. Every government in the region wants gigawatts in the water by the end of the decade and every developer's investment committee wants a financial close in sight. But the truth of the matter is that this has not been easy. So how can Asia make offshore wind project bankable?

This article explores four key points. First, that offshore wind is not really a renewables investment at all. It’s a large-scale infrastructure investment and has to be financed as one. The second is that whether a project is bankable depends less on any single party's strength than on how risk is allocated between government, sponsor and banks. Third, that Taiwan, Japan, Korea and the Philippines are each, right now, teaching us something quite specific about getting that allocation right. And fourth, that the UK has already run much of this experiment, and we would do well to take reference.

Offshore wind is an infrastructure investment, not a renewables investment

Given the size of the capital expenditure required, the technical complexities, the permitting requirements and the long gestation periods of seven years or more (far longer than the project cycles of other renewable technologies) offshore wind requires a great deal of regulatory support, though that does not necessarily mean subsidies. At the same time, offshore wind projects must survive the regulatory change that inevitably occurs over such long periods.

It is for these reasons that we should think of offshore wind less as a renewable energy investment and more as a large-scale infrastructure investment. Solar and onshore wind are, in financing terms, relatively modular and repeatable: modest ticket sizes, construction periods measured in months, standardised equipment, and a contractor market deep enough that a single underperforming supplier rarely threatens the whole project.

Offshore wind sits in a different category altogether. It has the capital intensity, multi-year construction programme, heavy civil and marine engineering, port and grid interface, and concentrated supply chain of a port.  This is similar to building an LNG terminal or a major transport link. Offshore wind is financed the way infrastructure is financed: long-tenor debt, staged drawdowns, syndicates with deep technical capability, and a sponsor expected to stand behind the asset through a full economic cycle rather than to build and flip it shortly.

This means that offshore wind must be underwritten on infrastructure disciplines: counterparty credit over decades, construction and interface risk allocation, and the durability of the regulatory agreement. Not on the shorter, more forgiving metrics that have served the rest of the renewables sector well.

Bankability is a question of risk allocation

The key question when it comes to financing offshore wind is what project finance has always really been about - who bears which risk, and who is the right party to bear it. In offshore wind that question is unusually consequential, because the risks are large, long-dated and interlocking.

The orthodox allocation is straightforward to state. Government takes the risks only governments can control or absorb - the durability of the regulatory regime, permitting and consenting, grid delivery, and, through some stabilisation mechanism, the tail of merchant price risk. The sponsor takes the risks it is paid to manage - procurement, construction and interface risk, contractor performance and cost overruns - backed by equity that sits first in the loss waterfall. The banks take the residual risk of a completed asset performing to a technical and commercial case they have diligenced (including wind resource, availability, operating cost and refinancing).

Project finance works when that allocation holds. It breaks when a risk is pushed to a party that cannot price it. And the mirror-image failure is just as real. Where governments retain too much for example, open-ended sunk-cost compensation, or auction designs that let a bidder win cheaply and walk away later, sponsors are not disciplined to bid realistically, and the taxpayer ends up underwriting optimism.

For the banks, the practical consequence of this is that the loan is not really secured on the turbines in the sea. It is secured on the integrity of the risk allocation: a regulatory agreement that survives a change of government, a construction contract wrapped by a contractor that can pay damages, a sponsor with both the capacity and the willingness to fund a gap if needed, and a revenue mechanism with a floor beneath it. Where each of those sits with the party best placed to carry it, offshore wind is financeable on long-tenor, largely on non-recourse terms. Where one of the risks has been shifted to whoever was least able to refuse it in a competitive auction, no amount of documentation will make the project bankable.

What Taiwan, Japan, Korea and the Philippines are teaching us

We do not need to theorise about this. Four markets in the region are running the experiment in real time, and each is teaching us something different.

Taiwan: do not let the market bid away its own cushion

Taiwan's Round 3 auctions crystallise the problem with unusual clarity, because nearly every winning bid came in at zero premium. Bidders in Rounds 3.1 and 3.2 offered NT$0 or NT$0.1 per kilowatt-hour to win development rights. That means there is no fallback tariff if a corporate offtaker defaults. The project's entire revenue case rests on the credit of a single corporate power purchase agreement counterparty, with no cushion beneath it.

In practice that counterparty is very often the same name. So a market that sets out to create competitive price discovery has ended up concentrating a very large share of its offshore wind revenue risk on the balance sheet of one company.

Offtake credit risk, which should really be a market or government-supported risk, was transferred wholesale to sponsors and lenders. Lenders cannot diversify a concentrated counterparty exposure of that size, and sponsors cannot hedge it. The result was not better price discovery. It was a financing market that slowed down. In that structure, the sponsor's willingness to backstop the cash flow gap becomes the de facto credit support the lenders are actually underwriting, whatever the loan documentation says.

Taiwan itself has since acknowledged this. In March 2026, the MOEA announced the selection mechanism for Round 3.3 corporate PPAs remain the primary route to market, but a floor purchase price of NT$2.29 per kilowatt-hour was introduced for surplus green electricity, expressly to support financing and reduce development risk. That is a regulator putting a floor back under a market that had bid its own cushion away, though the floor still isn’t solid enough to protect against the offtaker default.

Taiwan's second lesson concerns the supply chain. Early localisation requirements were industrial policy, not supply chain strategy. The intention was to build a domestic offshore wind industry so that the towers, foundations, cables and installation capability would remain in Taiwan long after the wind farms were commissioned. That is a legitimate and understandable objective. However, its effect on any individual project was to narrow the pool of qualified vendors to a domestic supply base that did not yet have the track record or the capacity. The lesson for financiers is that local content rules are a constraint on command of the supply chain, not an instrument of it.

This is why it’s worth noting what Gentari did at Hai Long, investing alongside NPI and Mitsui. This was a bold decision, but one made with considerable care and deliberation. Gentari's parent is Petronas, and what Petronas really brought, beyond just a balance sheet, was decades of relationships with the offshore marine and heavy fabrication vendors who build sea-worthy mega-structures and operate the installation vessels. This is the same contractor universe that serves offshore oil and gas.

Japan: a strong balance sheet is necessary, but it is not sufficient

Japan's Round 1 projects were awarded to a Mitsubishi-led consortium in December 2021, with commercial operation targeted for 2028 to 2030. Mitsubishi Corporation had won all three zones in a clean sweep and priced well below the rest of the field.

In August 2025, Mitsubishi walked away from all 1.7 gigawatts it had been awarded. Construction costs had more than doubled since the 2021 bid, and the impairment booked exceeded ¥50B.

Mitsubishi's decision was an astute commercial one. Mitsubishi certainly had the balance sheet. A strong balance sheet is necessary, but it is not sufficient to drag over the line a project that has become uneconomic because the macro environment has shifted. A bank isn’t just underwriting the size of the sponsor's balance sheet, it’s also underwriting the sponsor's willingness to deploy it when the business case has deteriorated and no sponsor's willingness is unlimited.

Japan's post-Mitsubishi reforms are, in effect, a regulatory acknowledgment of the same lesson. The government is now redesigning its auctions to weight project stability and realistic procurement more heavily than raw price, and to allow zero-premium projects access to a twenty-year Long-Term Decarbonisation Power Source Auction for guaranteed revenue. Like Taiwan's NT$2.29 floor, that is in substance a government taking back a risk the private sector had been asked to carry and could not.

Korea: discipline the bid, not the project

Korea's fixed-price contract auctions run in half-yearly cycles, but the projects they select still carry construction and permitting timelines stretching well past 2030. Korea has moved in the opposite structural direction to Taiwan and Japan. Bidders must now submit a written waiver of any right to claim compensation for sunk costs so that only sponsors who intend to see the project through will bid at all.

That is the mirror-image correction of the point earlier: a government declining to absorb a risk that properly belongs with the sponsor, in order to force realistic bidding.

Three markets, three different mechanisms, one shared conclusion – that the risks allocation has to be deliberate, in both directions.

The Philippines: setting the terms before the first auction clears

The Philippines is one of the newest entrants in Asia, having issued its first dedicated offshore wind auction in November 2025 under GEAP 5. This initially targeted delivery between 2028 and 2030 for a market that has never built a turbine offshore before, with a reserve price set slightly above Php 10 per kWh. For various reasons, the Philippines has now postponed the GEAP 5 auction process for a review, targeting a re-issue in December 2026. While the delay may be disappointing to bidders, careful deliberation and robust auction design is warranted for an auction of such scale.

As the Philippines works through the GEAP 5 auction, it may be worthwhile to consider the ~Php 10 reserve price and whether this is market-appropriate, considering that the Philippines does not yet have an offshore wind track record, no proven local supply chain, and considerable macro uncertainty layered on top.

Fundamentally, the Philippines has an advantage the others did not. It can set its risk allocation before its first competitive auction clears, rather than after. Whether it does so is the thing to watch most closely in this region over the next two years.

Take reference from the UK

Asia is not the first place to step through offshore wind projects, though various regulators here are learning the ropes on a compressed timeline. There’s much we can learn from the UK.

The UK's Contracts for Difference (“CfD”) mechanism was built for exactly the problem Taiwan and Japan are now grappling with. How do you take a technology with a decade-long gestation and give it a revenue profile a bank can actually underwrite?

The CfD is a two-way contract. The generator receives a top-up when the market price falls below the agreed strike price and pays back the difference when the market price rises above it, converting volatile merchant exposure into a predictable, government-backed cash flow. It is a deliberate decision that the long-term power price risk sits with government rather than with sponsors and lenders and that is precisely what allows offshore wind to be financed on appropriate leverage - that is on a largely non-recourse basis rather than depending entirely on sponsor balance sheet strength to absorb price risk.

Adopting CfD-style models reduce revenue risk for developers and financiers and improve bankability. This is most valuable exactly where off-taker creditworthiness is still evolving, which is a fair description of several markets in this region.

But the UK also offers a cautionary lesson. In 2023, Allocation Round 5 produced zero bids for offshore wind, because the strike price ceiling had not kept pace with post-inflation costs. This is almost exact echo of what we have just seen in Japan and Taiwan. The UK government responded by raising the price ceiling for the next round and has continued refining the mechanism through to Allocation Round 7.

CfD-style mechanisms are not a silver bullet. They only work as a stabilisation mechanism if the government keeps it calibrated to reality and revisits it in genuine dialogue with developers rather than defending a price cap for its own sake.

This is the single thread running through the examples discussed. Korea recalibrating its price caps and tightening its evaluation criteria. Japan rebuilding its auction design after a headline withdrawal. Taiwan putting a floor back under its market and easing its localisation rules to match actual supply chain capacity. The Philippines setting a ceiling price before it has even seen a competitive auction clear. Every one of these cases is a market trying, in real time, to do what the UK did with the CfD a decade ago. Find the point where price discipline and bankability stop pulling against each other.

Long gestation periods will not shorten. Offshore wind will remain an infrastructure asset with infrastructure risks. So the governments, sponsors and banks who succeed in this region will be the ones who stop asking “can this project be built” and start asking the harder question. Who precisely is standing behind it when it does not go to plan and is that the right party to be standing there?

About this article

This article draws on Baringa’s expertise in energy markets and extensive experience advising on transactions, with a focus on offshore wind. This includes a review of policy developments in Taiwan, Japan, South Korea, the Philippines and the UK to share lessons on how to make Asia’s offshore wind projects bankable.