Big Oil, Utilities Seen Covering Risks for Wind, Solar: Q&A

By Angus McCrone, BloombergNEF Chief Editor. This article first appeared on the Bloomberg Terminal

The coming era of unsubsidized wind and solar projects is likely to see companies with large balance sheets such as oil and gas majors and utilities stepping in to cover the electricity price risk and so helping make those plants financeable.

So said Allan Baker, head of power advisory and project finance at Societe Generale Corporate & Investment Banking, in an interview with BloombergNEF. The French bank took part in several big green energy project financings last year.

These included that for the 487-megawatt, $1.5 billion SeaMade offshore wind array off the Belgian coast, and that for the $5.9 billion acquisition by Global Infrastructure Partners of 50 percent of the 1.2-gigawatt Hornsea 1 project in U.K. waters.

Baker told BNEF that making projects bankable in the unsubsidized era will require at least part of the electricity price risk during the project life to be hedged, with two options being deals where utilities provide a floor price, and those in which big-balance-sheet entities such as oil companies offer cover. He said: “I think we’ll increasingly see large players stepping into this space, including both utility companies and oil and gas companies.”

In offshore wind, projects are getting bigger and bigger, with developers for instance planning to build an array of between 1 and 3 gigawatts on Dogger Bank in the North Sea between the U.K. and Denmark, at the cost of between $3 and $10 billion.

Baker said: “The increasingly large projects should still be financeable, but it will need banks and also capital markets to contribute, and it will require innovative solutions on the hedging.”

He also spoke about financing battery storage projects and electrolysis plants to produce hydrogen, in the Q&A below.

Q: When it comes to renewable energy financing in the new, unsubsidized era, what do you think are the lessons we can learn from the problems that occurred with the merchant gas-fired power station projects 10 or 15 years ago?

A: At that time, the banks took a view on merchant risk based on an evaluation supported by market consultants, but ultimately in the U.S., the U.K. and elsewhere, some of the issues faced were due to a combination of market changes, overcapacity and over-gearing on a number of projects. For example, in the U.K., [there was] market reform plus over-capacity caused by continued build based on a flawed expectation that older plants would close. More recently, we have seen similar issues in other markets including in Northern Europe, where the pace of renewables growth has materially impacted spark spreads – leading again to issues for bank-financed projects and value impairment on utility-owned thermal plants.

Banks are not in a position to project long-term power prices as a basis for non-recourse project finance transactions in markets that are exposed to a range of commodity risks, potential market reform and, now, where the whole industry is experiencing a fundamental transition.

Q: What does that mean in practice for how banks should finance renewable energy projects that don’t have guaranteed tariffs now that subsidies are disappearing?

A: Banks should be looking for [the sponsor to get] cover for the merchant risk, whether that is via electricity floor price contracts, traditional PPAs [power purchase agreements] or some other mechanism. It is not necessarily about locking everything down, but more about adequately protecting banks from the downside on electricity prices and providing a route to market.

We are looking at projects where a floor price contract would give security but still leave the project shareholders with the potential for upside if the electricity price was higher. Another option is a more hybrid approach where the project is exposed to a proportion of merchant risk on its output and has contracted revenues for the remainder. In this case, banks could apply more conservative debt-sizing metrics on the merchant revenues than would [apply] for the lending that was secured by the contracted part.

We are working on a number of other solutions to provide value in respect of merchant revenues. We fully accept that as renewables approach grid parity, banks will come under increasing pressure to take merchant exposure.

Q: Who do you see providing those contracts that enable renewable energy projects to secure their revenue streams – financial investors, utilities, corporate energy buyers, the exchanges?

A: 
There are an increasing number of non-traditional offtakers willing to take renewable energy but it’s the tenor of the contracts that has been the biggest challenge to date: 10 or 15 years is a different type of risk from two, three or five years being offered based on the forward curve.

As for the utilities, their whole business model is changing and their risk appetite, strategy and, in some cases, credit ratings are changing as a result – so they are no longer necessarily the obvious counterparties. With the more non-traditional corporate buyers that are now emerging, there are a few that have high-grade ratings but, when they have filled their power needs, you may have to look at having a portfolio of 10-15 smaller buyers with often more challenging credit profiles. That increases complexity but also diversifies the risk. And there is the scale issue – for the larger offshore wind projects for instance, with capacity of one gigawatt or more, that’s a lot of corporate PPAs to find.

That brings us back to one of two solutions. The first is finding some form of utility-style offtake contract, such as a floor contract on the electricity price, or possibly some form of rolling contract structure with the banks offering a mini-perm or “borrowing base” type facility and the sponsor having the obligation to hedge a defined proportion of the electricity price over a defined forward period.

The second is finding someone in the market that has a large enough balance sheet to backstop certain risks on the project. We have seen developers, including Orsted A/S for instance, acting as an offtaker for offshore wind projects to manage risk for debt and incoming equity. We also see a business opportunity for creditworthy entities to act as an aggregator for smaller corporate offtakers, to facilitate larger offtake contracts and manage counterparty risk. However, overall I think we’ll increasingly see large players stepping into this space, including both utility companies and oil and gas companies.

Q: The move by PG&E Corp. into Chapter 11 bankruptcy over in the U.S. shows that utilities can run into their own problems, with the potential to affect the PPAs they have signed. So I guess that banks will have to take a view on any utilities that provide security on electricity revenues for projects?

A: Banks would have to look at what the position of those utilities would be if the electricity price were to fall. Utilities’ old business model based on large-scale, centralized generation is under threat, so they are transitioning to a new model. In the future, we will have to focus more on analyzing their strategy and understanding the associated risk. Banks will rely on credit [rating] agencies in the future to some extent, but will also need to do their own fundamental analysis [of the position of utilities].

It is not just traditional power utilities going through a transition. We are more and more involved with oil and gas companies that are also looking at clean energy and project finance. They are aware that their business model is changing, with an increasing overlap in transition technologies and cooperation between companies that were previously in very different areas of the energy chain.

Q: Does this all mean that it will be more difficult to finance offshore wind in the new era than it was in the past when revenues were protected by government-set tariffs?

A: It will certainly become more complicated. Advisers and structuring banks will become more important in optimizing debt structures to meet the new challenges. The flow of “greenfield” transactions for financing may also be slowing after a very busy 2-3 years for the project finance community. Two-yearly CfD [Contract for Difference] auctions in the U.K. market, largely merchant Dutch and German projects, and slow progress in some other markets may mean that transactions also take longer to structure.

Q: Is there a danger of too much slowing in the offshore wind market, so it becomes overly difficult to get new projects financed?

A: I don’t think so. A lot of banks are now looking at offshore wind and have invested a lot in their teams. Given the ingenuity of the project finance business, different solutions from banks and sponsors will ensure that liquidity is maintained in the market.
The increasingly large projects should still be financeable, but it will need banks and also capital markets to contribute, and it will require innovative solutions on the hedging.

Q: What about the financing of battery projects? You seem to be more comfortable with the idea of funding batteries that are located with wind or solar projects, than with standalone battery projects that are providing services to the grid.

A: With the grid-connected battery projects, unless you can get long-term capacity payment contracts, they are very exposed to significant market volatility and so-called “revenue stacking” – depending on a number of different revenue streams from various grid services, all of which are difficult for banks to analyze.

With standalone batteries, in U.K. auctions we’ve seen that potentially debt-financed projects have not been that competitive. It is possible that banks’ understanding and performance experience will improve, but grid storage is a very variable duty, and it is not clear at the moment how batteries will perform in the long term.

Batteries on renewable energy projects may not be any easier to analyze from a performance perspective but there is a duality of revenues to help in risk mitigation. In places like Australia, Spain and the U.K., there may be significant value in being able to store electricity. A solar project, for example, might be generating at peak capacity around midday when demand is relatively low and not at around 5-6pm for the peak, when people come home from work. Being able to store during periods of low prices and discharge during the peak has clear commercial advantages, with other valuable benefits such as balancing volatility. The integration of wind and solar with batteries is likely to make fully merchant solar and wind projects more bankable in the future.

A number of companies are looking at retrofitting batteries to existing wind or solar projects. The challenge would be metering the green output: if the battery is connected to the grid, you need to make sure that the electricity you are supplying from the battery is actually green. It is likely that initial funding of those batteries will come from equity as small incremental capex, then an overall refinancing of both the renewable generation capacity and the battery, in which banks would take part.

There are a large number of renewable energy projects that could benefit from retrofitting with batteries. That is something we see coming if the regulations allow for it.

Q: Electrolysis to produce hydrogen is something you have mentioned as an interesting opportunity. Are you talking about it being on the horizon now, or about it being something that might come up sometime in the next decade?

A: It’s not far away. At the moment, hydrogen is something that is being thought of more as a transport fuel [rather than for long-term energy storage or as a feedstock]. Japan, for instance, is hoping to have a lot of its fleet converted to hydrogen in time for the 2020 Olympics. The U.K. also has some pilots. However, the potential for hydrogen in the gas network is being tested in Leeds, and other uses could lead to a much wider use of hydrogen to decarbonize the energy markets.

It could be an area for non-recourse project finance sooner rather than later. Hydrogen is a commodity you can store. It has an end-use you can value. There are a number of different revenues and these are more obvious than for battery storage in a way.

Whilst a number of companies involved in hydrogen are deep-pocketed organizations that may not have used debt finance before, like the oil and gas companies, it is likely that significant debt will be required in the medium term. This is a new business with new risks, and even large companies may want the due diligence that comes with seeking debt finance, and they may want to gear up their capital because producing hydrogen will be a lower-return business for them.

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