It is no coincidence that the surge in global renewable energy capacity occurred at a time of record low interest rates. As central banks responded to the global financial crisis, global renewables capacity stood at about 130GW in 2010, according to the International Renewable Energy Association.

That is now at 340GW as cheap finance propelled the economics of a sector that was already benefiting from strong policy tailwinds and a technological evolution in wind turbines and solar panels.

As the calendar changes to 2024, that picture is rather different. Supply chain issues mean the technological evolution has become a costly one and UK and US interest rates are at 15- and 22-year highs, amid hikes across the rest of the globe. That, of course, makes everything more expensive, but renewable energy is an infrastructure sector that faces a development requirement like no other, with investment of $4.5 trillion per year required through to 2030, according to the International Energy Agency.

It makes building the next stage of the energy transition a financing struggle, alongside its material struggles in supply chains. Offshore wind, due to higher construction and capital costs, has been the highest-profile victim, with cancelled or postponed projects, but there have been impacts on land-based wind and solar projects too.

“We have closed a lot of deals this year but instead of helping developers make significant development fees, we’ve been helping our clients manage risk, renegotiate contracts and survive in this very difficult business environment,” explains Ted Brandt, founder and chief executive of Marathon Capital, an investment bank advising developers globally on renewable energy project finance.

“The developers’ business previously was to negotiate and get a certain contract done at an 11 percent return and then sell down at a 7-8 percent return.

“The new reality is to develop an 11-12 percent return and to sell a de-risked project at a 9-10 percent return. There’s a whole development value chain across the scaled onshore wind and solar business that has dropped in value or become negative.”

Romain Voisin, head of energy and infrastructure group for Asia at Crédit Agricole CIB, says that several investors have been pausing on deploying new capital into projects because they feel that returns are not as attractive as they need to be.

“But it does vary – some are still driven by strategic long-term views and are making investments. I have not seen investors visibly pulling out of projects, but they are certainly taking more time to see how things will play out. So, we will potentially see a slowdown in new projects,” he says.

“The difficulty right now is matching the revenue side of the story and expectations around the cost of green electricity to the cost of capital. The construction risk on some of these projects has materialised as well, which also inevitably leads to investors pushing for a higher return.”

“I have not seen investors visibly pulling out of projects, but they are certainly taking more time to see how things will play out”
Romain Voisin
Crédit Agricole CIB

Yet at the tail-end of 2023, central banks have stopped hiking interest rates each month, suggesting the stability infrastructure investors crave is not far away.

“What got difficult was the prediction with interest rates. The uncertainty is worse,” says Jehangir Vevaina, managing partner in Brookfield Asset Management’s renewable power and transition business, focused on transaction execution.

“We know rates are what they are. They’re higher than they were two years ago. We at least feel they’re nearing the top of the cycle in most markets. We can predict with quite a lot of certainty what we expect the interest rates to be and that provides a strong advantage.”

It’s all about the offtake

At the heart of managing the rising costs of projects has been the handling of power purchase agreements. Many agreements are typically signed before financial close and before construction begins, leaving sponsors with projects where the financing and equipment costs outweigh the price agreed for electricity.

It has left project developers coming back to offtakers cap in hand, asking for a renegotiation. In the case of public utility offtakers in US offshore wind, these requests have been rejected. However, some are finding success, following an 18-24-month period of rising power prices.

“In the majority of cases, we’ve either been able to raise the PPA price so that we’re effectively neutral to the increase in the cost of debt or that the project has had some competitive advantages that are meaningful for the customer,” says David Scaysbrook, co-founder and managing partner of Quinbrook Infrastructure Partners, pointing to its recent green data centre platform in the US, amid the greater need for power with generative AI.

“If you can estimate that cost will be higher, then you can factor that into the PPA price you ask from your offtakers,” believes Vevaina. “We find that the prices we need to get our returns, many offtakers are accepting. The demand on the commercial and industrial side is so strong. It requires a higher PPA price and a higher levelised cost of electricity, but we’re seeing C&I absorb it.”

Similarly, at Macquarie Asset Management’s Green Investment Group, the appetite from corporates for clean energy is still dwarfing higher capital costs.

“We’re seeing projects maintain viability because the price of the rise in interest rates is being passed on to the offtakers and the offtakers have such strong demand for these electrons that, at least today, they’re willing to pay a higher price. They’re still the lowest price of electricity,” argues William Demas, GIG’s head of Americas.

Seeing this absorbed has made debt providers feel altogether more comfortable in backing projects, according to Nasir Khan, head of infrastructure and energy finance in the Americas for Natixis.

“Since cashflow is higher, applying the same debt sizing metrics at a higher interest rate does get you back to about the same point with respect to leverage levels, as where you were before,” he reasons.

“Utilities will ultimately pass this through to end users. It’s going to be a more expensive cost of energy for everyone, but that’s the environment we’re in”
Andy Nguyen
CRC-IB

It might not be as easy in the future, with PPA pricing showing downward trends. PPA prices fell in the US by 3 percent in Q2 2023 and a further 1 percent in Q3, according to consultancy Edison Energy. In Europe, prices vary depending on jurisdiction, but an 8.8 percent decline in pricing was seen in Q3 by Edison. It is already leading to some opposition from offtakers, according to Marathon Capital’s Brandt.

“For the first time in years, we’re watching corporate buyers of green electricity push back hard on their cost of electricity and state that while they do absolutely want the environmental attributes and to hit climate goals, signing contracts at $50/MWh versus $25/MWh is a much riskier and volatile instrument than contracts they might have signed 24 months earlier,” he says.

Sponsors of projects are now pricing in the higher cost when bidding on contracts, maintains Andy Nguyen, managing director at investment bank CRC-IB, formerly CohnReznick Capital.

“Utilities will ultimately pass this through to end users,” he says. “It’s going to be a more expensive cost of energy for everyone, but that’s the environment we’re in.”

Consumers, of course, may not be delighted at having to share the burden of an increased cost.

Costs of platform building

The trend among some of infrastructure’s larger players in recent years has been to acquire large development platforms or independent power producers, capitalising on the large development pipelines boasted by such groups.

Some, though, are warning that the aim of bringing those to fruition may need to be tempered by the new rate environment.

“Low interest rates were key a few years ago where there was a huge [amount] of M&A activity where funds were buying platforms and were being very favourable with valuations,” says Nguyen. “Now what you’re seeing is from an M&A standpoint, there’s been a reduction, and that’s primarily because of the higher rate environment. Funds are now pricing that in when they acquire platforms. They’re also being choosier on the types of transactions they evaluate and how aggressive they want to be with valuations.”

According to Matt Wade, executive director in IFM Investors’ debt team, financiers are also wary when lending to such platforms.

“There’s been a slowdown on devco financings. People are tightening up what they’re lending against, particularly on the devco side, and looking very much at shovel-ready construction projects,” he states.

Orhan Sarayli, another private debt lender in his role as head of North America for Barings global infrastructure group, acknowledges that “on a current yield basis, a single renewable project on its own may be tough to hurdle because the cash yield is tight”. He is unconcerned about platform development generally, although he foresees pressure on asset performance.

“People are tightening up what they’re lending against, particularly on the devco side, and looking very much at shovel-ready construction projects”
Matt Wade
IFM Investors

“I think the market is readjusting. I don’t expect the interest rate environment to impact the development of renewables in a material way, but it’s already a tough yield environment. With the higher rate environment, renewable projects are effectively higher levered given the fixed costs, and can’t afford weak performance as they might have before.”

Scaysbrook adds that there is not the same level of aggression among banks to fund such development platforms, instead waiting to see when those become shovel ready. That being said, those types of portfolios are what is on offer to funds.

“We’re seeing a lot of development-stage portfolios in the market, particularly solar in Texas,” he says. “A lot of the development shops are putting assets on the market either because they cannot stand the delays in connections, or they don’t have the same capacity to arrange tax equity and all the economics are under pressure because of the cost of money.”

The left behind mid-market

If those are headwinds for larger infrastructure funds, the tailwind may well be that the new environment leads to a thinning out of the mid-market. As costs mount, observers are seeing the market crowd in a select group of players, with too much risk seen in backing smaller sponsors.

“People are coalescing around certain sponsors, backing quality sponsors,” believes IFM’s Wade. “Some of the sponsors are generating scale and sufficient interest for these facilities, because you do need to keep a certain size of facility for it to make sense because of the fees involved.”

It is certainly a view shared by Vevaina at Brookfield, which this year became one of the largest owners of renewable power in the US, with the acquisition of a 5.9GW operating and under-construction portfolio from Duke Energy.

“I’m seeing that in a very large way. It’s very multi-faceted,” Vevaina says. “Offtakers don’t want to deal with smaller developers that are going to renege on contracts or renegotiate them. They’ve had to deal with that in this period of volatility and would rather deal with a larger player than struggle with someone who will make a commitment for a low price then walk away from it.”

The larger investors have the benefit of being able to commit further capital to projects if needed, as interconnection queues add to the rising capital costs.

“Sponsors have to use their dry powder in order to make these [interconnection] deposits. For smaller guys who may not have that equity, they have to choose the projects to move forward,” says Nguyen, who outlines additional benefits for large-cap investors to continue with lower-returning projects.

“Larger sponsors are continuing to push through with those projects with the understanding that returns are less attractive but continue to build the projects and raise financing for them, particularly public companies [which stand to benefit later] from an earnings standpoint.”

“When debt was cheap, a few basis points didn’t make a significant impact in terms of the risk-return proposition […]  In today’s environment where debt is so much more expensive, it’s really vital to make sure you’re negotiating the best package possible”
Charlie Reid
BlackRock

At BlackRock, one way to deal with higher financing costs has been to leave out debt financing altogether where it makes sense to do so. Charlie Reid, managing director and head of APAC for BlackRock’s renewable power group, says: “Subject to the market, we are building assets out all-equity, as by adding project finance debt we’re significantly increasing risk but we aren’t materially increasing returns. We raised A$1 billion ($650 million; €600 million) in equity for the Waratah Super Battery, being built outside Sydney, to build it all-equity for that reason.”

He says it is “vital” to be able to have large-scale and deep relationships with lenders to get the best deals. “When debt was cheap, a few basis points didn’t make a significant impact in terms of the risk-return proposition of your asset. In today’s environment where debt is so much more expensive, it’s really vital to make sure you’re negotiating the best package possible.”

Indeed, IFM’s Wade says there has been a 50-75 basis point increase on “fairly straightforward, contracted renewables”.

All-equity deals are inevitably easier for the largest asset managers, who can not only raise larger funds more easily but can also mobilise bigger amounts of co-investment capital from LPs.

“When interest rates were low, co-investment was a relatively unattractive way of financing assets. But where they are today, those co-investment relationships are vital to a healthy project financing ecosystem,” Reid says.

Where no manager has gone

There’s an uncertain outlook going forward for many. It’s not necessarily that projects won’t get financed, as there remains plenty of appetite from both equity and debt providers. It’s that the renewables market sits in a position it has never encountered in the 15-20 years when projects have been built en masse.

For some, it may be that renewables fit certain capital structures, with development potentially less of a core-plus-style return.

“[PPA price increases speak] to the resilience of these assets as core assets. They don’t have monopolistic tendencies but they do have purchasing power. These are limited assets, there’s not an infinite supply,” argues Demas.

Brandt adds that the energy world is still adjusting to what reality looks like post the Russian invasion of Ukraine, and how countries and investors alike come to terms with energy security and independence.

“Up to the beginning of 2022, the combination of low interest rates with the LCOE constantly coming down was the secret to the growth of the business,” he says. “I think we have some real adventures in the next couple of years we have to work through.”

We may be at the top of the cycle, but we are certainly not at the end of the story.

HARD-HIT OFFSHORE WIND

The most high-profile challenges within the renewables sector to date have been seen in offshore wind, where the likes of Ørsted and Vestas have pulled out of contracts in the US, citing higher costs, while the UK’s most recent auction round received no bids from developers at all.

Rob Grant, head of projects at Pollination, says this shows that developers who are reliant on government-led offtake agreements have to be especially sure that they are getting their costs right, as these events demonstrate.

“The problem isn’t on the revenue side for these guys – it’s been on the capital side where returns have dropped,” he says. “They’ve seen price escalation in their capital, which may be the same as the price escalation they will see in revenue that will come later on, if it’s linked to CPI – but the problem is in the tyranny of the IRR, where you incur all those costs up front.

“There are those moments in markets where you have to walk away, taking the view that not doing a bad deal is better than chasing a good deal. It then becomes an issue for government – if they want to stand an industry up, this is now what it costs. They can go back to the market and re-bid it, but it will need to be at a higher price.”

Crédit Agricole CIB’s Romain Voisin says it takes time for governments or utilities that are buying the power to recognise that this must ultimately lead to an increase in electricity prices.

“We’ve seen some countries being less proscriptive in terms of ceilings for tariffs on upcoming auctions and there is an increasing role for corporate-type offtakes which offer more flexibility [with CPI linkage].”

The US and many Asian governments have not included an element linked to CPI in their contracts – but others, such as the UK, have.

But as Grant says: “I think the issue for the ‘failed’ offshore wind projects is that they based their starting PPA price on capex costs at the time. Now the capex has increased, no matter what the indexation mechanism in the PPA, they will not be able to achieve their investment hurdle rate without a reset.”

One major infrastructure investor active in the Asia-Pacific region, that both invests in commingled funds and pursues direct infrastructure investments, argues that “the reality of rising costs seems to be lost on some policymakers”.

Requesting to speak anonymously due to being involved in active negotiations about greenfield projects, this person says: “The whole idea that renewables will be cheaper is clearly not the case.

“There is clearly massive risk in supply chains, which can be mitigated for except for the risk of delay. And that risk in the delay of delivery of components has not lessened, in my view. I think this is especially the case for offshore wind.”