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Jamie Fleming is senior underwriter in renewable energy at Axis Capital Ltd. We spoke to him recently about his views on the challenges and opportunities for wind power - if you'd like to take part in a member Q&A, email us at editorial@awordaboutwind.com

In simple terms, what does your company do?

We provide insurance for all aspects of constructional and operational risks, for both offshore and onshore wind projects. We support companies in all aspects of their dealings from marine transit of parts through to breakdown of operational turbines.

What do you want from an A Word About Wind membership?

There have two things that we’ve found the A Word About Wind membership useful for. The first is networking at Quarterly Drinks. These events have allowed us to meet and discuss the industry with a number of different people and have also featured some very interesting speakers from companies like Greencoat, Vattenfall and Ørsted. The second has been the Financing Wind conference. We found it particularly interesting.

Of the deals you’ve worked on, which is your favourite and why?

I predominantly focus on offshore and onshore wind at Axis, with more of a focus on offshore; however one of my favourite deals was for an onshore wind risk. It was one of the first big wind energy deals I made in my career, and was for the largest wind farm in Africa at the time. The project is based in Morocco, where the intricacies of the insurance market are quite complex and different to that of the London market. Moroccan insurance regulations dictate that if an international insurer is to write business in Morocco, it’s a must be a reinsurance of the state reinsurer, who subsequently reinsure a local insurer. Add to this a broker based in London and a broker based in Morocco, and consequently there will be a number of different parts and interests that needed to be considered, including having our wording approved by the Moroccan state reinsurer. It was a time consuming process! Needless to say the deal was made, and it helped open the door for future business in the North African region.

In which markets do you see the best opportunities right now?

Of the established offshore wind markets, the UK is still leading the way in terms of installed capacity and pipeline for the next few years. There are at least five extremely large projects that are due to come online by Q4 2019, and at least 3 that are due to start construction. In addition, it’s been projected that the UK will potentially see a five-fold increase in stalled offshore wind capacity by 2030, with zero subsidy levels; expected by the mid 2020’s. Once the market becomes fully subsidy-free, we will have reached a huge milestone in terms of the industry being able to stand on its own two feet, which will only continue to help the public perception of these offshore mega-projects.

As for the emerging markets in offshore wind, we are keeping a very close eye on Asia, particularly Taiwan. Currently there is one test project there but in the current tender another 5.5GW of contracts will be awarded, many of which are expected to be with European developers that Axis are currently involved with. In addition, the US is slowly bubbling away in terms of offshore wind development. Axis are currently involved in the 2 projects there, and there is 23GW of proejcts in the planning stage around the 12 states that are involved. The US is therefore a key market for Axis in 2019 and onwards.

What is the biggest challenge facing wind and how would you fix it?

Wind energy as a whole is continuing to go from strength to strength. However, we have concerns regarding political uncertainty in particular countries that are currently developing offshore wind. This is particularly topical at the moment with regards to the French offshore market, where currently political uncertainty is arguably the greatest threat to the industry taking off there. With the Government currently reviewing whether or not they can honour the tariffs they awarded back in 2011 and 2013, due to the cost of developing offshore wind dropping per kw/h, there is now significant uncertainty in the market. As we know, uncertainty is extremely bad for progress, and will potentially halt the French market if not resolved soon. If I could fix that, I would move into politics!

Which trends will affect the wind sector most in the next 5-10 years?

Moving beyond the political risk in certain countries, the offshore wind market is moving towards subsidy-free contracts, and that will have a huge impact on the industry. We have recently seen the first non-subsidized wind farm awarded to Vattenfall for a Dutch offshore project, and expect this trend to continue. One of the risks is that as the prices continue to drop for winning these permits; will there be enough margin to make operating the project sustainable and profitable once it starts exporting electricity to the grid?

Another trend which is linked to subsidy-free contracts is the change in technology and the output wind turbines can now produce. With the recent news release of GE’s new 12 MW Halidade turbine, we are entering a new era in turbine size and expect that this trend will continue. As a result of this change in technology, wind farm operators are able to generate more revenue from the same area of ocean than they were able to previously. The justification of the operators for subsidy free contracts is increasing, given that the size of the turbines and thus the output is continuing to grow at such a rapid pace.

What are the most important lessons you’ve learned during your career?

To avoid burning your bridges! Ultimately renewable energy (particularly insurance) is still quite a small market and you never know when you will have the opportunity to transact, or work, with someone again in the future. It’s important to be patient with those that you deal with, as often they are under similar pressures as you are, and in the end we all want to work in harmony to get a deal done…!

Did you have a mentor and what did they teach you?

I have had a number of mentors over the years, both in and outside of the insurance market. All of them have taught me different things, and I hope that in the future I will be able to mentor someone in the next generation in the same way.

In two weeks, trade body RenewableUK is set to hold its Global Offshore Wind event in Manchester – and, this year, the word ‘global’ is more appropriate than ever.

Over the last year we have seen offshore wind open up in countries such as the US and Taiwan. This is driven by trends such as falling costs and growing turbine sizes.

Meanwhile, in Europe, the offshore wind sector in the Republic of Ireland and Poland has taken some important steps, where firms like Equinor, Innogy and Parkwind are leading the way. You can read more about Ireland here and Poland here.

But you're probably already looking at them and so, ahead of this conference, we wanted to take a few minutes to look at countries that have shown some promising activity in offshore wind over the last 12 months. Here are five of the most interesting…

1) Australia: Proximity to Asia-Pacific will prove important

Copenhagen Infrastructure Partners teamed up with Australian developer Offshore Energy in late 2017 to develop the A$8bn ($6bn) 2GW Star of the South project off the coast of Victoria. The two partners plan to complete the wind farm by 2024; and the attention from CIP, which is proving itself in Europe, Asia and North America, represents an important commitment.

The lack of local turbine makers and an established supply chain could be a concern for the country, but its proximity to the emerging Asia-Pacific market will provide vital support.

And, while we don't yet know if the Australian government will support offshore wind, we're confident that hostility to onshore wind from some Australian politicians shouldn't necessarily mean offshore wind suffers. The UK is an interesting model for a country that has gone big on offshore while treating onshore wind more harshly, for example.

2) Canada: Let's not forget the US's northern neighbour

Danish utility Ørsted last year signed a letter of intent with Canada’s NaiKun Wind Energy, which gives the Danish utility exclusive rights to co-develop the up-to-2GW Haida offshore scheme off the coast of British Columbia.

In January, the Canadian government announced the launch of a C$200m ($160m) call to receive expressions of interest from firms keen to develop offshore wind, tidal or geothermal projects. The funding is set to support companies looking to develop green infrastructure projects as part of a C$21.9bn ($17.5bn) programme.

It is still early days, but Canada has the longest coastlines in the world, and major capabilities from marine industries that can support offshore wind projects. The emergence of the offshore wind industry in the northeast US states should provide significant local knowledge too.

3) India: Overseas and local players must make their mark

By 2022, India wants at least 5GW of offshore wind capacity. It's a big four-year target.

Last month, the Indian government called for expressions of interest from domestic and international firms interested in developing the country’s first 1GW commercial offshore wind farm, off the coast of Gujarat; and consulting group COWI announced last September the start of geographical works to build a 200MW scheme.

However, the government has set rules that could make the development of offshore wind farms very challenging. For example, domestic bidders must have an installed capacity of over 500MW of onshore wind and would have to tie up with international companies with at least 500MW of offshore wind experience to submit their bids. International players haven't always found it easy to get into onshore wind in India. Will offshore be any different?

4) Japan: Diet seeks to unblock longstanding offshore interest

In January, Prime Minister Shinzo Abe said the government would introduce laws to open up offshore wind. Following that, the cabinet approved legislation in March to allow developers to place competitive bids to win the rights to develop offshore schemes. The law is due to go through the Japanese Diet this month, and is definitely one to watch.

We've written plenty before about the interest that large Japanese players including Marubeni, Mitsubishi, Mitsui, Samsung and Sumitomo have shown in offshore wind over the years, so we won't go back over that here; and the commercialisation of floating foundations will be an important step for this market. Backing in the Diet could help finally unlock this potential.

5) South Korea: Macquarie development is one to watch

South Korea’s government has set a 2.5GW target for offshore wind by 2019. This fits into the country’s strategy to add 58GW of wind and solar capacity by 2030, up from its current 11GW. To achieve this, the government plans to invest $36bn in renewables over the next five years.

This would be a big step up, given the country has completed so far only its 30MW Doosan offshore wind farm and installed only 1.1GW of onshore wind. Backing from the government is certainly there, and Macquarie has committed to co-develop a 1GW floating project too, which shows that experienced players are taking the opportunity seriously. The country may fail to deliver on that 2.5GW ambition, but it is nonetheless of indication of local support.

Blockchain technology is well-known for its use in the financial sector as it enables the trading of cryptocurrencies such as bitcoin. And, over the last couple of years, we’ve seen more companies investigating its potential in alternative fields, including renewable energy.

We’re now seeing some interesting results of that work.

For example, British utility Centrica said last month that is planning to use blockchain to help address the issue of curtailment of renewable energy, which affects up to 10% of production in the UK. The utility is planning a pilot to help consumers to buy and sell locally produced wind and solar energy in order to avoid waste of energy.

To do this, Centrica would use a blockchain energy trading platform developed by New York-based LO3 to allow up to 200 homeowners, businesses and renewable energy producers to buy and sell energy according to their needs.

Blockchain could change the energy market as we know it.

“Blockchain is an opportunity for the energy market place as a whole. Changing the energy market place then becomes an opportunity for renewables because they would become more flexible and more responsive to what the market really needs,” said Elaine Greig, director at consultancy Renewables Consulting Group, who has been conducting research to encourage the renewable energy market to make use of the opportunities that blockchain could offer.

In short, blockchain could enable the development of a decentralised yet integrated trading system that would permit renewable energy businesses to trade energy with a greater flexibility. This could help create an open energy market, in which large and small renewable energy producers representing interconnected nodes are able to interact directly between each other to responsively satisfy the energy demand.

Such a system would be enable a more efficient management of the grid, cut operational costs and provide new revenue streams for wind and solar producers. That’s the aspect we expect to make investors really take notice.

“Traditionally, renewable energy providers have just sold MWh through a subsidy system. This is how you get some guarantee of income”, said Greig. But the market needs auxiliary services to keep the lights on, and blockchain technology could enable wind and solar producers to come in and give the grid operator alternative ways to manage the grid.

Greig explains: “If you have open access for your energy trading, more and smaller renewable energy providers could be able to provide short-term energy contracts, for example. You know what the wind is going to be in 12 hours, but you can’t say that with six months’ notice. But, for short-term response, you can then bid in and secure income by being available for that need.”

“For renewables, this would take the system beyond just selling few MWh to actually providing services that the grid needs”, she said.

Wind and solar companies would be the biggest winners of this decentralised system and, ultimately, consumers. Greig argued: “People selling would be able to sell what they couldn’t before, while people buying would be able to buy cheaper energy and services.”

This would also potentially represent a threat to traditional utilities.

“A free energy trading system will affect what the utilities can do, because they will have to be very responsive to a market. While previously they had full control over what happened, they have no control of a completely peer-to-peer market, which will be a big challenge, and so they need to get very responsive because it will be very difficult for them”, Greig said.

What’s the solution for these utilities? “At some point they would have to deal with it because they are not like Uber and Just Eat, they are responsible for keeping the lights on, so they will have to find a solution… It’s a problem worth being solved.”

The use of blockchain technology in the energy market is still largely unproven and some barriers remain. One of the biggest issues is the current regulatory framework, which prevents the adoption of a decentralised transaction model. However, Greig said she found it promising that UK energy regulator Ofgem is supporting blockchain as part of its “Innovation Link” programme, for example.

Blockchain hasn’t yet enabled bitcoin to overhaul the global financial system, but it could yet start a revolution in the energy trading market.

Ben Scholes of Papertrail explores how the digitisation of turbines can help the wind industry deliver lower-cost energy.

Something very strange happened to the wind industry last year: it reduced costs.

Reasons behind price reductions

Nothing strange about that, you might say.

Wind energy has been getting cheaper year by year. That's exactly what has allowed the industry to go from strength to strength.

But the magnitude of price reductions in the last year has been staggering. In Mexico last November, for example, wind came in at $17.70 per megawatt-hour in an auction.

In the UK last September, offshore wind - still an emerging technology - managed to undercut nuclear and gas power with a price of $76.34 per megawatt-hour.

And in the US in January, a solicitation by electricity firm Xcel Energy saw average bids of $21 per megawatt-hour for wind… with storage. It’s important to note that all of these prices were for projects that are not due to be built for a few years.

Which is just as well, because none of them are remotely achievable with today’s technology. As Michael Stephenson, Carbon Trust offshore wind associate, has pointed out:

“The prices are predicated on further innovation and further hard work.”

The problem is, wind energy is already highly competitive. And wind turbine manufacturers have already spent years trying to squeeze every last drop of efficiency out of their designs.

So where is this extra cost effectiveness going to come from?

One answer is size. As Berkeley Lab has observed:

“The growing size of wind turbines has helped lower the cost of wind energy to the point that it is economically competitive with fossil-fuel alternatives in some locations.”

That’s why turbine manufacturers are reaching for new heights. The latest? A 12-megawatt offshore machine from GE, called the Haliade-X, which stands at almost the height of the Eiffel Tower and will boast blades longer than a football pitch.

GE is not alone in designing bigger turbines. Last year, the analyst group MAKE Consulting was forced to revise its average turbine rating forecast upwards as manufacturers across the board hastened to bring larger machines to market.

MAKE now expects new turbines to have an average rating of 2.8 megawatts per machine by 2022, up almost 17% from a mean of 2.4 megawatts last year. This increasing reliance on ever-bigger turbines carries a risk, though.

A bigger turbine rating means greater financial losses whenever the machine breaks down. The immense cost of massive turbines means they cannot be allowed to stop except for planned maintenance.

And that places a big burden on operations and maintenance (O&M). Predicting when components may fail is already a fine art in the wind industry and is set to become even more important in future.

Pretty much the only way to outguess turbine component stress and fatigue is through digital sensors. So as turbines grow, so does the amount of digital equipment they rely on. In order to get bigger, the machines must also get smarter.

This digitalisation need not be restricted to the turbine itself, either. Supervisory control and data acquisition (SCADA) systems can provide valuable insights into the working of electronic and mechanical components, but there is a whole level of other information that is less easy to track.

Take items that are subject to visual inspections, for example. This information is not captured by SCADA systems.

However, it is not only important from an O&M perspective but also vital for the management of health and safety, which is even more important to wind asset operators than cutting costs.

Until recently, it wasn’t easy to capture this kind of information in a way that was easily accessible. Nowadays, though, an inspection team can log its findings directly into cloud-based systems, through mobile or tablet devices, and make them available instantly to other teams.

The benefits of this kind of platform are most evident in offshore wind, precisely where the need to cut costs and maintain safety is greatest.

Wind farm operators such as Innogy Renewables UK and contractors such as Offshore Painting Services admit that even such a seemingly modest step as digitising their record-keeping procedures has had a significant impact on their operations.

And this is just the first step.

As wind turbine manufacturers continue to embrace the Internet of Things, we envisage non-SCADA records, often known as ‘dark data’, being integrated automatically with sensor data and other inputs.

This will allow asset owners can check on the status of any turbine component in real time, at a glance. It may sound far-fetched, but it’s likely not that far away. The industry has already placed a bet on what wind will cost in the next few years. Now it needs to deliver.

Each year, we host conferences discussing the biggest issues in European and North American wind. Click below to find out more...

This is a week of firsts for A Word About Wind. On Wednesday, we are due to host our inaugural US conference, Financing Wind New York, in partnership with GCube Insurance Services – and, while we’re there, we’ll be talking about our new special report too.

Tomorrow, we are due to publish our inaugural North American Power List, in partnership with report sponsor Lincoln Clean Energy. This has been a long time in the making and, in our humble opinion, gives a great snapshot of the state of the US wind market.

In addition to the top 100 list, we have also included interviews with high-profile individuals including Bank of America Merill Lynch’s Ray Wood; MUFG’s Beth Waters; Enel Green Power’s Rafael Gonzalez; and Declan Flanagan from Lincoln Clean Energy.

And if you’re not in the US? Well, we think you should read it anyway!

Some of the trends we’re seeing in the US are equally applicable to the global market, and one of the most noticeable this time has been the impact of consolidation. Utilities and large institutions have been buying developers and yieldcos like there’s no tomorrow.

Last week, Canada’s La Caisse de Dépôt et Placement du Québec grew its stake in US developer Invenergy from 24.7% to 52.4%, and in normal times we’d have been picking apart this deal to tease out its significance. But the most remarkable facet of this deal has, frankly, been how unremarkable it has seemed. We've stuck it with all the other similar deals.

This year, Engie has bought Infinity Renewables to get its 8GW project pipeline; and Innogy has acquired EverPower’s 2GW US onshore development portfolio.

The two utilities are seeking to line themselves up alongside the major European utilities that have already made an impact in US wind, including EDF, EDP and Iberdrola.

As for the major institutional buyers, we’ve seen Global Infrastructure Partners buy three parts of NRG Energy for $1.4bn; Ontario Municipal Employees’ Retirement System has bought Leeward Renewable Energy; and Brookfield has been bedding in SunEdison’s two former TerraForm yieldcos are the deal that completed last year.

And this US activity is just a snapshot of what is happening globally.

GIP has this year concluded its $5bn buyout of Equis Energy; India's ReNew Power has paid $1.7bn for Actis arm Ostro; and RWE and E.On have agreed their €60bn asset swap deal. The M&A merry-go-round is moving quickly and there is no shortage of well-capitalised buyers trying to take their seat. In the US, we're looking closely at Apex Clean Energy too.

There are a few things these deals tell us about the wind market worldwide.

First, that companies looking to expand in renewables aren’t content to simply buy assets. Some will remain keen on low-risk assets, but the big attraction is on buying a platform that enables them to take development risk, with the higher returns that entails. As Waters says, there is “tremendous demand by large players in the market for development pipelines”.

It takes two to make these deals work, though. These willing buyers must also have a willing seller – and that brings us to our second point.

These deals are attractive for developers too because it gives the owner an opportunity for to exit their business with a healthy payday; and gives them a well-capitalised partner with which they can realise schemes. Development is capital-intensive and the falling levelised cost of wind is squeezing developers’ margins, so the chance to exit makes sense.

Wood points out that there’s “clearly a trend towards development companies being rolled up into bigger entities” – and, as wind has gone mainstream, the money’s there.

And third, for the larger partner, it is often simply easier to buy projects where the developer has already done the early development work. It means less faffing to acquire the site, appease locals, win consents, secure transmission lines, and so on. No point spending ages developing your own 8GW pipeline if you can buy someone else’s.

Flanagan argues that this shows that new esteem with which developers are being held. He says that, previously, development was sometimes seen as the part of the wind development cycle where cash was burned. However, investors are increasingly seeing this as an area where they can realise higher returns: “We’ve seen a shift in recent years that what you really want to be best as is the development part of the value chain,” he told us.

This isn’t just a US trend, but the US has provided some of the most visible deals so far. What impact will this have on North American Power Lists in future years? We’ll let you know later! I'm going to enjoy a couple of days in New York after the conference recovering from this one.

Portuguese utility EDP has been the subject of takeover speculation for the last year.

However, when a solid contender to acquire EDP emerged last week, it came from a company with which EDP is very familiar.

State-owned power company China Three Gorges last week made an offer to buy the 77% of EDP’s shares it doesn’t own for €3.26 per share, in a €9.1bn deal. This would value EDP at an enterprise value of €28.2bn, making it China’s second-biggest overseas acquisition.

CTG has been EDP’s largest individual shareholder since 2011. The company bought a 21.35% stake seven years ago from the Portuguese government, as part of a privatisation programme following the country’s financial crisis. CTG has also committed to invest €2bn in EDP-led projects, including wind farms; and, last October, it strengthened its position and increased its stake to 23.26%.

CTG has clearly had a longstanding interest in EDP, but why is it now looking to go ‘all in’? Well – and you might expect us to say this – we see wind playing a key role.

In short, the acquisition of EDP represents a unique opportunity for CTG to diversify its portfolio. In its home country, the Chinese firm primarily develops and operates hydropower plants, with a total capacity of 39GW, and it owns a wind and solar portfolio of 2.8GW.

Overseas, CTG has so far invested $17bn on 16GW of capacity in ten countries, with a particular focus on Brazil, Pakistan and Europe. Buying EDP would give CTG a solid platform to diversify its portfolio with a focus on the renewable energy sector including wind, and in particular in North America.

EDP ended 2017 with 27GW of installed capacity of all energy types, 10GW of which come from wind and solar. In particular, EDP Renewables, which manages EDP’s wind and solar portfolio in Europe, North America and Brazil, is the third-largest wind farm operator by installed capacity in the US with a 5.2GW portfolio. This would provide an excellent growth platform for CTG.

But while this looks like an exciting deal for the Chinese company, it will have to fight for it as EDP has not accepted its offer yet.

The Portuguese utility said last week that the offer from CTG was too low and undervalues the company. The €3.26 per share offer is only 4.8% higher than the utility’s closing stock price on 11th May, before the bid was announced, and EDP’s share price currently stands at €3.46, as investors are betting on a higher offer.

It will also have to fight to win approval of competition authorities in the countries in which EDP operates. The hardest consent to get would likely be from the Committee on Foreign Investment in the US, which could force EDP to sell some assets, over concerns that Chinese ownership of power generation in America threaten national security and competition.

This would not necessarily be a disaster, as CTG could use the proceedings of a potential sale to diversify its position in Latin America and to strengthen its presence in Europe, but it may be unpalatable for EDP.

One thing we do know is that money is unlikely to be an issue. CTG has the financial resources to increase its offer if it sees the value in doing so, with the backing of the Chinese government no less, which has reportedly approved its takeover plans. In addition, Chinese Foreign Minister Wang Yi said last week that China would continue to encourage investment by its companies in Portugal because of the country’s open attitude to foreign investment.

The deal has the blessing of the Portuguese Prime Minister Antonio Costa too. In his mind, an acquisition by a company from so far away would have the advantage to keep EDP operating independently, as opposed to a takeover from a European utility, which could lead to a full integration with cost cutting and job losses.

That may help to win over EDP but, with its concern about the pricing, we expect its executive board to officially reject CTG’s offer soon. Then the real negotiation starts.

The UK Government and offshore wind industry are working together on a sector deal that could boost offshore wind in UK waters and support British firms going overseas, but we haven’t heard much on that since March. We might get more at Global Offshore Wind, says Frances Salter

Why is the UK a leading offshore wind market?

The UK has an impressive track record when it comes to offshore wind.

Currently, the UK exports more electricity from offshore wind farms than any other country, and in 2017 it produced half of Europe’s offshore wind power.

The sector makes a significant contribution to the UK economy too. Last year, RenewableUK reported that the offshore wind industry would deliver £11.5bn into the country’s economy between 2017 and 2020. As a percentage of the UK energy mix, offshore wind makes a currently meets 5% of annual demand, and this is due to grow to 10% by 2020 according to estimates by the Crown Estate.

This success is largely the result of a combination of government support and pre-existing favourable conditions. The UK has a history of producing energy offshore because of its long-running involvement in North Sea oil and gas. This meant that some of the technology, expertise and supply chain required for offshore wind were already in place before the industry started to take off in the mid-2000s, and could be adapted from their use on non-renewable energy sources.

The UK also has a geographic advantage. It has a shallow continental shelf that extends far out from the shore, making it a convenient location for building turbine foundations.

And importantly, the offshore industry has enjoyed government support.

The UK government has supported the sector with its feed-in tariff regime and Contracts for Difference; and helped commercialise the sector with its UK Green Investment Bank which, after it was founded in 2012, took financial risks that private developers and utilities weren’t prepared to take. The UK GIB was bought by Macquarie last year.

This has all been underpinned by support from the Crown Estate, which has opened up plots of land for offshore wind farms. It is now looking at new offshore leases to support the government’s Clean Growth Strategy to support more offshore wind.

These have all helped drive down costs and the last CfD round in September, which revealed that new offshore wind is cheaper to produce than new gas, shows how far the industry has come. This combination of factors has allowed the UK offshore industry to flourish and so the question now is what’s next for UK offshore? How can it capitalise and expand on its existing success?

In the UK, offshore is set to continue making a significant economic contribution.

In March this year, RenewableUK reported that the industry’s plans until 2030 include £48bn investment in UK infrastructure, and a growth in skilled jobs from current levels of 11,000 up to 27,000. Considered alongside the government’s Clean Growth Strategy, this would mean that UK wind capacity would more than double.

British offshore wind firms aren’t limiting their ambitions to domestic developments either. Offshore wind and its associated services have great export, meaning that UK companies could capitalise on opportunities in international markets. Scottish Power Renewables, part of the Iberdrola group, has been pursuing plans to build two large projects off the east coast of the US, each the size of its UK portfolio.

Opportunities for offshore wind

These opportunities were the focus of a 2018 report by former UK energy minister Sir Michael Fallon, which is called ‘Winning Locally, Going Global’.

The report outlines his ambitions for offshore as part of the UK’s industrial strategy, and describes the knock-on effect that investing in UK offshore businesses could have on international prospects. He suggests a minimum of 60% of the total capital expenditure on wind farms in UK waters should go to British businesses by 2020, up from the current target of 50%. For schemes that reached financial investment decisions between 2010 and 2015, 48% is currently being achieved.

He said this could be achieved with an ambitious sector deal between companies in the offshore wind industry and the UK government. This would outline what kinds of support would be given to companies developing wind projects, including financial backing from UK Export Finance and the UK Business Bank.

As well as increasing investment in UK companies in the short term, strengthening local manufacturers should help to ensure that they can retain their status as key players in the growing global offshore market over the longer term. Fallon’s report highlighted several global areas for wind farm development, which he’d like to see the UK play a part in: the Indian Ocean, the sea of Japan, and the northeast US.

Will this sector deal happening? Well, the UK’s Offshore Wind Industry Council set out its ambitions in March 2018, and is working with Baroness Brown of Cambridge, a sector champion for offshore wind. She has made positive noises. For example, in March she said:

“With an ambitious Sector Deal, we have the opportunity to take the next transformative steps together, enabling the offshore wind industry to help Government to achieve its clean growth ambitions in a way that boosts productivity and growth throughout the UK.”

We haven’t heard any more yet, but we’ll be keeping a close eye on RenewableUK’s Global Offshore Wind conference in Manchester next month. If any progress has been made yet, we’re sure that somebody will want to shout about it.

The UK’s Conservative Party is meant to be the ‘party of business’. Don’t you believe it! Where onshore wind is concerned, the Conservatives have shown they’re only the ‘party of business’ when they like the industry in question – and onshore wind isn’t it.

There have been some notable UK successes on wind. Support for offshore wind in the Contracts for Difference (CfD) regime has kept the UK at the forefront of a global industry. We’ve also seen developers and utilities building more onshore wind farms in recent years, powered by the now-expired Renewables Obligation Certificates.

And we should celebrate the success of the UK on reducing carbon emissions in the last ten years, since the Climate Change Act was passed in 2008.

But we also need to remember that these policies were put in place under either the last Labour government, or while the Conservatives were ruling in coalition with the Liberal Democrats from 2010 to 2015. It doesn’t mean more good times are coming for UK onshore wind, as a report on investment has said this week.

Last Wednesday, MPs in the UK Parliament’s Environmental Audit Committee warned there had been a “dramatic and worrying collapse” in low-carbon energy investment since 2015, which will threaten the UK’s ability to meet its low-carbon commitments. This report said annual investment in clean energy in the UK dropped 10% in 2016 and then 56% in 2017, and is now at its lowest level for a decade.

Labour’s Mary Creagh, the committee’s chair, warned that “billions of pounds” were needed for the UK to meet its binding climate change targets, but “a dramatic fall in investment is threatening the Government’s ability” to meet them.

In the accompanying report, the committee identified two main problems. The first is the drop in state-backed investment as a result of the privatisation of the UK Green Investment Bank and the UK’s decision to leave the European Union.

And the second is the drop in confidence among private investors following policies introduced by the Conservatives, under then-prime minister David Cameron, in 2015 including the end of ROCs and the moratorium on onshore wind.

That explains the lack of investment – and we see two main ways to fix it.

First, the government could get serious about supporting onshore wind with CfDs. Energy minister Claire Perry has been doing the rounds and giving hope to those in the onshore wind industry, but we haven’t seen much to back this up. Its cynical policy is to only support onshore wind in remote parts of Scotland and Wales.

If that doesn’t happen, there is a second option: reform the planning system. This would make it easier for firms to win consent and communities to attract investment.

The planning system is endlessly complex, and it is understandable why government is reluctant to tackle it for the benefit of a sector that it doesn’t really like. But it could be an effective way to encourage local councils to approve onshore wind farms when they are in the ‘right’ locations, and were local communities are broadly supportive.

A draft of the revised National Planning Policy Framework shows the problems that onshore wind companies are up against. The draft, where consultation closed on 10th May, says that local planning authorities should approve renewable energy projects – including wind farms – as long as their impacts are ‘acceptable’ for both the area and the local community. The problem is that the word ‘acceptable’ is open to interpretation, and it is often easier for planners to refuse projects for an easy life.

Planners will also be mindful that the onshore wind industry didn’t get a look in when the government published its Clean Growth Strategy. When national government has shown it doesn’t want onshore wind investment, why should local communities?

Some planners are aware of the problem. The Town & Country Planning Association and Royal Town Planning Institute this week released a report saying that planners needed new powers if the UK is to hit its climate change goals. That could help to unleash investment in UK onshore wind, without the need for national subsidies.

Or, let the market decide. That’s what the Conservatives are meant to be about.

Turbine makers are always looking for growth opportunities, and squeezed margins are making this drive all the more urgent. Now they have developers in their sights.

This week, Vestas entered into a partnership with Swedish utility Vattenfall and Danish pension fund PKA to develop a 353MW onshore wind farm in Sweden.

This deal is notable for a number of reasons. First, the size. Yes, 353MW isn’t a record-breaker – the 650MW Markbygden 1 is the largest in terms of the European onshore wind sector – but it’s still a sizeable project. This reinforces Scandinavia’s status as a leader in European onshore giants.

Second, the involvement of PKA. The pension fund manager has previously invested in offshore wind farms and, for example, bought a 25% stake in the 659MW Walney extension scheme in October. But its acquisition of a 30% stake in this 353MW wind complex, known as Blakliden and Fäbodberget, is important because it shows there are onshore projects being built of a size that can interest major pension funds.

And third, Vestas has taken a 40% equity stake in the development. This is a major departure for the Danish manufacturer from its core business making turbines, and it has the potential to shake up the onshore wind market. But why make the shift?

Anders Runevad, president and CEO of Vestas, said the falling cost of turbines was “making the market more competitive and creating new opportunities”.

In other words, for manufacturers such as Vestas, it makes sense to use their balance sheet to get involved in the early stages of onshore schemes, and take advantage of the higher returns that come with accepting that early-stage development risk.

Not that there appears to be much risk. The development partners have announced that Norwegian aluminium giant Norsk Hydro is set to buy 60% of the electricity from the complex when it completes in 2022. This follows Norsk Hydro’s power purchase agreement late last year to buy electricity from the Pitea scheme, which is part of Markbygden 1.

This PPA will help de-risk the project for Vestas, PKA and Vattenfall. As a result, the process for securing the €350m of construction financing needed should be a fairly straightforward process. The deal is due to conclude in the coming months.

We have watched for a few years as Vestas has got more involved in the operational side of wind farms, including through its acquisition of US analytics business Utopus Insights in February. It has also been getting more involved in hybrid projects, where it can match its wind turbines with solar, hydro and storage technologies. Therefore, it’s no surprise to see it getting more involved nearer the start of the development cycle.

It isn’t the first to do so. The merger between Siemens and Gamesa last April landed us with a player that could sell turbines and develop its own schemes.

Likewise, GE Renewable Energy said at this month’s AWEA Windpower event in Chicago that it had created a standalone development team to look at onshore wind projects in the Asia-Pacific region and in Europe. GE has indicated it will co-develop early-stage projects and could offer PPAs of its own.

These go even further than the wind financing work that General Electric does via its GE Energy Financial Services arm, and again give it the potential for higher returns.

As well as the returns, getting involved in early-stage projects helps Vestas and GE to de-risk their sales cycles. For one thing, projects they develop themselves will lead to a guaranteed order; and it also makes them less reliant on business plans of external developers. There seems little logic in always waiting for other developers to come along with appropriate projects if they can develop schemes themselves.

And finally, it could help them to open up new markets. Manufacturers are always on the lookout for new countries and regions that they can move into, but their ambition and investment plan has to then be matched to the plan of an external developer. In situations where two parties have the same goal, pooling resources makes sense.

This could worry independent developers. It might mean turbine makers edge them out of the development process. Equally, though, it could mean the developers get a chance to form long-term partnerships with well-capitalised turbine makers. We’ll doubtless see a bit of both.

How much of an impact have President Trump's tax reforms had on the US wind industry, and what does it mean for investors? Guest bloggers David Burton, Jeffery Davis and Anne Levin-Nussbaum take an in-depth look.

How much of an impact have President Trump's tax reforms had on the US wind industry, and what does it mean for investors? Guest bloggers David Burton, Jeffrey Davis and Anne Levin-Nussbaum take an in-depth look. This article first appeared in Pratt’s Energy Law Report March 2018.

On December 22, 2017, President Trump signed into law the bill known as the “Tax Cuts and Jobs Act” (the “Tax Act” or “Tax Reform”) (1.) This article describes the Tax Act provisions of interest to the renewable energy industry, along with some of the possible implications of tax reform on the industry.

OVERVIEW

There were multiple provisions in the House’s tax reform proposals that were specific threats to the economics of the renewable energy industry. Fortunately, for the industry, none of those provisions survived the legislative process. Nonetheless, the reduction of the federal corporate income tax rate from 35 to 21 percent reduces the amount of tax equity that can be raised for renewable energy projects. Further, the renewable energy industry is wrestling with the implications of the base erosion anti-abuse tax (“BEAT”) on certain multinational tax equity investors.

However, the implications of BEAT are not as severe as they would have been under the Senate’s proposal because Tax Reform allows affected multinational corporations to generally benefit from 80 percent of their renewable energy tax credits for purposes of calculating BEAT through the end of 2025 (as explained below). However, that benefit ends starting in 2026, when affected taxpayers are no longer be able to benefit from any tax credits for purposes of calculating the BEAT, if any. The benefit is also muted by the expanded reach of the Tax Act to corporations that make three percent of their deductible payments to foreign affiliates, which is an increase from the four percent threshold under the Senate bill.

For banks, the BEAT provisions apply if payments to foreign affiliates are two percent of deductible payments. On the positive side, the Tax Act repeals the corporate alternative minimum tax (“AMT”), which is necessary to avoid the loss of certain production tax credits (“PTCs”), which were an AMT “preference” when generated by projects after their fourth year of operation. In addition, the Tax Act allows immediate expensing for newly acquired equipment. Notably, the Tax Act follows the House bill in permitting 100 percent expensing of newly acquired “used” property.

CORPORATE TAX RATE AND AMT

The Tax Act reduces the corporate tax rate to a flat 21 percent, replacing the previous graduated rate structure capped at 35 percent for income that exceeds $10 million. This 21 percent rate is incrementally beneficial for operating projects that are beyond their depreciation period. For new projects, the lower rate reduces the amount of tax equity a project can raise; however, the uncertainty of Tax Reform was hampering the market more than the reduced tax rate is expected to. One straightforward implication of the 21 percent corporate tax rate is there will be significantly less “tax appetite” than there was with a 35 percent tax rate. Fortunately, the largest tax equity investors appear to have significant tax appetite, notwithstanding this reduction.

EXPENSING

The Tax Act provides an additional first-year expensing of qualified property at 100 percent. This is also referred to as 100 percent bonus depreciation. This provision is temporary in nature and starts to ratchet down in 2023 and is eliminated completely in 2027. Transmission projects are provided an extra year with respect to each phase-out deadline. Notably, the Tax Act also eliminates the “original use” requirement to qualify for 100 percent bonus depreciation, which means “used” property can be fully expensed in the first year if the taxpayer has not used the property before. This will provide opportunities for acquiring operating projects, including repowered projects.

To prevent abuses, used property acquired from certain related parties is not eligible for expensing. The anti-abuse rule could be a challenge for wind tax equity transactions in which the parties desire to benefit from expensing if the investor has not made its investment in the partnership on or prior to when the project is placed in service (i.e., when the project has essentially become operational), which would require the investor to take construction risk.

Some partners in partnerships owning projects eligible for expensing will face challenges in fully realizing the benefit of the 100 percent deduction. The expensing provision does not treat partnerships differently than other taxpayers; however, the ability of partners in a partnership to claim deductions is limited by such factors as the partner’s “outside” basis and the capital account rules. Those factors may make it difficult for partners to use the expensing deduction without causing other issues. A partnership that is in its first year of doing business can elect out of expensing and claim 50 percent bonus depreciation (2).

Further, all taxpayers can opt for “MACRS” depreciation (e.g., five-year double declining balance for wind and solar property) or the alternative depreciation system (e.g., 12-year straight-line for wind and solar property).

BEAT PROVISIONS

The BEAT provisions were first introduced in the Senate bill and aroused wide concern in the renewable energy sector. The BEAT provisions target earning stripping transactions between domestic corporations and related parties in foreign jurisdictions. The BEAT is a tax (at a phased-in rate discussed below) on the excess of an applicable corporation’s (I) taxable income determined after making certain BEAT-required adjustments, over (II) its “adjusted” regular tax liability (“ARTL”), which is its regular tax liability reduced by all tax credits other than, through the end of 2025, certain favored tax credits. The favored credits are (A) research and development tax credits and (B) up to a maximum of 80 percent of the sum of the low-income housing tax credits and the renewable energy tax credits. This favored treatment of the low-income housing and renewable energy tax credits was in response to concerns raised by those industries.

However, the favored treatment is at best a partial mitigant to the impact of the BEAT on the value of those tax credits and the associated investments. The ability to exclude the renewable energy credits from the ARTL calculation ends in 2026. In particular for PTCs, this could be a deterrent given the 10-year stream of those credits. Further, the Tax Act did not change the BEAT provisions in the Senate bill to distinguish between PTCs and investment tax credits (“ITCs”) earned with respect to projects that have already been placed in service or for which construction has begun. Thus, BEAT could affect monetization of tax credits mid-stream. It could also affect renewable energy credits earned with respect to projects in which tax equity is currently invested. Another issue is that the Tax Act expanded the reach of the BEAT, because the threshold for being subject to the tax is lower than under the Senate version.

Under the Senate version, corporations that make payments to their foreign affiliates equal to four percent of their deductible payments are subject to the BEAT regime. Under the Tax Act, the threshold is three percent and two percent for banks. Confounding the problem is that these companies will not know in advance whether the BEAT will apply, and this uncertainty could cause susceptible tax equity to leave the market. The Tax Act provides a phase-in for the final BEAT rate.

Under the phase-in, the BEAT is five percent for tax years beginning in 2018, 10 percent for tax years beginning between 2019 and 2025, and 12.5 percent thereafter. In the case of banks and securities dealers, the general BEAT rate is increased by one percentage point such that their BEAT rate is six percent for taxable year 2018, 11 percent for taxable years 2019 through 2025 and 13.5 percent thereafter. The higher BEAT rate also applies to corporations and other entities that are members of the same affiliated group of a bank or securities dealer. The higher rate for the specified financial institutions was the “pay for” for allowing the specified financial institutions to exclude payments with respect to derivatives to their foreign affiliates from BEAT. BEAT is a challenge for both PTC and ITC transactions.

However, it is a more significant challenge for PTC transactions due to the fact the PTC benefit is a 10-year stream, while the ITC is all in the first year. Thus, in a PTC transaction, the tax equity investor must predict whether BEAT might apply to it for 10 years in the future, whereas the applicability of BEAT is a one-year concern in an ITC transaction. Wind projects have the option of electing the ITC in lieu of the PTC. The combined effect of BEAT and the availability of 100 percent expensing may cause some wind projects to elect the ITC to attract a larger pool of tax-motivated investors. This would be because a lease structure is the most efficient means for monetizing the benefit of 100 percent expensing and PTCs are not available to the lessor in a lease structure, whereas the lessor is able to claim the ITC.

However, electing the ITC has a cost, as today’s highly efficient wind turbines often cause the present value of a land-based project’s projected PTC stream to exceed the ITC. Therefore, it would appear the ITC election would only be made if it resulted in a significantly larger pool of tax-motivated investors being prepared to bid competitively.

TECHNICAL TERMINATION OF PARTNERSHIPS

The Tax Act repeals section 708(b)(1)(B) of the tax code, which caused a partnership to be deemed to terminate (a so-called “technical termination”) when there is a sale or exchange of 50 percent or more of the total interest in the partnership’s capital and profits during a 12-month period. In the case of such a deemed termination, the terminating partnership was deemed to transfers its assets and liabilities to a new partnership, and the terminating partnership was deemed to distribute interests in the new partnership to the purchasing partner and other partners of the terminating partnership.

One result of the termination was that the recovery period for depreciating the partnership’s assets was restarted. There is a special bonus depreciation rule that provides that the “new” partnership is the entity entitled to claim the deduction for bonus depreciation for property placed in service during the year of the technical termination. The technical termination rule, combined with this bonus depreciation rule, enabled tax equity investors in wind projects to avoid construction risk and still receive bonus depreciation by waiting until after a project was up and running smoothly to acquire an interest in the terminating partnership.

The resulting “new” partnership could claim bonus depreciation, even though the “old” partnership had placed the project in service. Thus, tax equity investors were able to invest in operating wind projects, qualify for bonus depreciation and only lose a few weeks of the 10-year PTC stream. With the 100 percent expensing provisions in the Tax Act, such structuring is not necessary, as “used” property qualifies for expensing so long as the wind project is newly acquired by the taxpayer and the acquisition is not subject to the anti-abuse rules regarding related-party acquisitions (which may still present issues in the case of tax equity partnerships).

Note that the Tax Act does not alter the ITC prohibition with respect to used equipment, so ITC investors will still need to invest at or before the placed-in-service date or execute a sale-leaseback within three months thereof. The repeal also simplifies transfers of interests in tax equity partnerships, which were often restricted by provisions in the partnership operating agreement prohibiting transfers that would result in a technical termination of the partnership. Without the need for this constraint, it is now possible to remove one of the most complex aspects of partnership transfers.

PREPAID POWER PURCHASE AGREEMENTS

The Tax Act eliminates the tax deferral benefit of a prepaid power purchase agreement (“PPA”). Under a prepaid PPA, the offtaker (or residential customer) prepays some or all of the projected cost of the power to be delivered during the term of the PPA. Prior market practice was that the seller of the power (in many transactions, a tax equity partnership) defers the income recognition until the power is actually delivered.

The Tax Act requires sellers to report prepayments for goods and services in the year received or the year following receipt of the payment.3 If the seller of the power is a partnership, the acceleration of the recognition of the prepayment for tax purposes would create more taxable income for the partnership and may increase the ability of the partners to use the 100 percent expensing deduction without causing a deficit capital account problem.

It should be noted that the Tax Act does not make prepaid PPAs impermissible; it merely denies power sellers the timing benefits of income deferral for tax purposes. If the transaction economics are acceptable to the power seller without the tax deferral, parties may opt to continue to include the prepayment feature, as some offtakers find it to be an economically attractive means to deploy their available cash.

INTEREST LIMITATION

The Tax Act limits deductions for net interest expense (i.e., interest expense in excess of interest income) to 30 percent of an adjusted income amount that is calculated using a tax version of “EBITDA” (through the end of 2021, and thereafter switching to a tax version of the more restrictive “EBIT”). Interest that is disallowed as a result of the application of this limitation can be carried forward to future tax years indefinitely. In the case of partnerships, the limitation is applied at the partnership level.

As a result, it applies to each partner regardless of whether the partner has sufficient interest income to otherwise avoid application of the limitation. The limitation only applies to taxpayers with over $25,000,000 in average annual gross receipts for a three-year prior period, unless the taxpayer is a partnership that meets an expansive and highly technical definition of “tax shelter.” (4) The typical tax equity partnership appears to be a “tax shelter” under this definition that, if so considered, would be subject to the interest limitation rules notwithstanding that it has less than $25,000,000 in annual gross receipts.

This concern regarding the application of the interest limitation rules to tax equity partnerships may negatively impact tax equity investors’ willingness to change their existing views regarding the impermissibility of having debt secured by the project. Some tax equity investors are starting to entertain the idea of permitting debt at the project level as that may permit them to benefit from a greater portion of the 100 percent expensing deduction on their tax returns in the project’s first year. Such greater use of the depreciation deductions arises in levered deals due to the application of favorable rules for non-recourse debt under the partnership “outside basis” rules.

The interest deduction limitation is an aspect of Tax Reform some bankers may not be focusing on given that banks generally have more overall interest income than interest expense and, therefore, are not subject to the limitation.

However, the analysis is different when a bank invests in a partnership because the limitation, to the extent applicable, applies at the partnership level (i.e., the bank’s interest income from its general operations would not factor into the equation). Thus, tax equity desks may be surprised by the application of the limitation to levered tax equity partnerships.

It remains to be seen if the detriment of the deferral of the interest deduction due to this 30 percent limitation will be enough to make the use of debt secured by the project unattractive for tax-economic reasons. This would be in addition to the commercial considerations that have made project-level debt a disfavored feature in recent years and caused the market to embrace back-leverage (i.e., debt secured only by the sponsor’s interest in the partnership).

These questions, resulting from Tax Reform, regarding the optimal use of debt and many others will be hashed out in coming weeks as financial models are run and transaction documents are negotiated. Fortunately, the Tax Act was a far less painful blow to the U.S. renewable energy industry than it could have been, and the industry has the experience necessary to optimize transactions under the new tax regime.

Endnotes

David K. Burton, a partner at Mayer Brown LLP and a member of the Tax Transactions & Consulting practice, leads the firm’s Renewable Energy group in New York. He advises clients on U.S. tax matters, with a particular emphasis on project finance and energy transactions. Jeffrey G. Davis, a partner in the firm’s Tax Transactions & Consulting group in Washington, D.C., is a co-head of the firm’s Renewable Energy group, with a focus on project finance and energy transactions. He advises corporations, financial institutions, and private equity funds on U.S. tax matters. Anne S. Levin-Nussbaum is counsel in the firm’s New York office and a member of the Tax Transactions & Consulting practice advising clients on U.S. tax matters, with a particular focus in the renewable energy finance area. The authors may be reached at dburton@mayerbrown.com, jeffrey.davis@ mayerbrown.com, and alevin-nussbaum@mayerbrown. com, respectively.

1 Pub. L. 115-97, 131 Stat. 2054 (2017). (The final text of the enacted bill is available at https://www.congress. gov/115/bills/hr1/BILLS-115hr1enr.pdf.)

2 The Conference Committee Report provides: “A transition rule provides that, for a taxpayer’s first taxable year ending after September 27, 2017, the taxpayer may elect to apply a 50-percent allowance instead of the 100-percent allowance.”

3 I.R.C. § 451(c).

4 I.R.C. § 163(j)(3). Under Section 163(j)(3), the minimum $25,000,000 in average annual gross receipts requirement does not apply to a “tax shelter prohibited from using the cash receipts and disbursements method of accounting under section 448(a)(3).” For that purpose, the following are considered tax shelters: (i) any “syndicate” within the meaning of section 1256(e)(3)(B), (ii) any “tax shelter” within the meaning of section 6662(d)(2)(C)(ii), and (iii) any enterprise (other than a C-corporation) if interests in the enterprise were offered for sale at any time in an offering required to be registered with any federal or state securities regulator. I.R.C. §§ 448(d)(3), 461(i)(3). The definition of a “syndicate” would include a partnership where in any taxable year more than 35 percent of the losses are allocated to partners that do not actively participate in management. I.R.C. §§1256(e)(3), 461(j)(4). Therefore, arguably a tax equity partnership with a 99 percent loss allocation to a passive tax equity investor could be a syndicate. Further, a tax equity partnership could potentially be a “tax shelter” as defined in section 6662(d)(2)(C)(ii), as it may have “a principal purpose of . . . the avoidance of federal income tax.” If it were a tax shelter under either definition, it would be subject to the interest limitation rules regardless of its size.

For the latest in our series of member Q&As, we've spoken to Gil Howard-Larsen of UL (formerly AWS Truepower.) If you'd like to take part in a member Q&A, email us at editorial@awordaboutwind.com

For the latest in our series of member Q&As, we've spoken to Gill Howard Larsen of UL (formerly AWS Truepower.) If you'd like to take part in a member Q&A, email us at editorial@awordaboutwind.com

A Word About Wind Member Q&A Gil Howard-Larsen

In simple terms, what does your company do?

In addition to the due diligence and lenders’ engineering aspects which I lead, we’ve got several other business segments in the renewables division of UL. AWS Truepower (now part of UL) started from the business of energy yield assessments: we have about half the market in America for these, and a significant amount of the market in many other regions globally.

We have developed proprietary software for wind and solar mapping and layouts, and developers can buy our software and use that for site selection and project layout. We also provide renewable power forecasting for the major grid balancing authorities in the US. California, Texas, and New York all use our services. In 2016 we were bought by UL and have now transitioned to the UL brand name.

On the testing and certification side of the business, UL also owns DEWI – headquartered in Germany - who certify and test wind turbines. In addition, we perform lifetime extension and operating asset technical advisory services, so we offer the full suite of technical services from project inception to end of life. We also provide solar and storage testing, certification and advisory services.

Of the deals you’ve worked on, which is your favourite and why?

One of the things about being an independent engineer is that you get to do due diligence on more deals than most of us have hot breakfasts. I spent my career prior to UL working for developer, owner, operators, and my husband and I also had our own development business for a few years so the projects I worked on would take 2-4 years to develop and finance; now, in independent engineering and due diligence technical advisory, UL is working on multiple deals a month. So the deal flow is huge.

In terms of which is my favourite, the first ones are always the most memorable! When I was a developer, the first wind project I worked on for M&A was a repowering in California – I was working in the UK at the time and was told the project was ready to close in 2 weeks. I flew out to California with a team of lawyers and we renegotiated every single project agreement, diligenced the permitting and real estate, negotiated the financing and acquisition agreements and after two months of working 18 hours a day, we closed financing and equity investment for the project.

Once we got into operations, all sorts of things went wrong: we had a serial gearbox failure, there were a number of factors which meant we didn’t meet the energy forecast, so we had to navigate our way through those with the operator and the manufacturer. It was a tremendous learning experience.

In which markets do you see the best opportunities right now?

We are still increasing our market share in North America, and growing in both wind and solar. With the PTC deadline for wind at the end of 2020, we expect the next 2.5 years to be very strong. The Latin American market is also very strong right now: Mexico, Argentina and Brazil are all extremely strong. In Europe, we’re seeing Turkey as a strong market: we recently were selected to work for the lenders on a very large greenfield portfolio financing.

We’re also active in France, the Ukraine and South Africa. India last year was very quiet due to the new market structure, but this year we’re seeing a lot of activity and M&A work there. In China we’ve recently established a team for due diligence and energy work.

What is the biggest challenge facing wind and how would you fix it?

The challenge is getting the cost to the right place, and there always will be challenges in the areas of permitting and ensuring community acceptance, especially in areas which are densely populated. However, I think the biggest opportunity is the fact that costs are really coming down in terms of the cost at which we can deliver power- turbines are getting larger, towers are getting taller and rotor diameters are getting larger, and all of that means that not only can turbines produce more energy but manufacturers are reducing their CAPEX prices as well as their OPEX prices.

We’ve seen some very significant price reductions in the last eighteen months in CAPEX and OPEX. Some of that is a result of competition between OEM’s, but it’s also a result of pushing the envelope on engineering, improving the development and supply chain, and improving operability. A lot of maintenance and major component repairs that could previously only be done downtower, can now be done uptower. Some of this has been a response to competition from solar, with rapidly reducing solar prices.

Which trends will affect the wind sector most in the next 5-10 years?

I think the pricing is critical – we will continue to scale, markets are going to continue to grow although there is always political risk, and storage will be critical for wind and solar. Storage will be a game-changer, not just in developed countries but in developing countries with weaker grids and less centralised systems. Again, it’s about getting storage to the right price point, but we’re seeing things moving there – lots of large utilities are funding storage systems on balance sheet to get experience with the technology, and storage will have an important role to play in load shifting to release the power generated by renewables to the times of day we need it the most, and in grid support

What are the most important lessons you’ve learned during your career?

There have been lots! I started in energy when I was 22, straight out of university, and moved to wind and renewables about 6 years later and have been doing this ever since. I just had my 20-year anniversary in wind. I think really enjoying what you’re doing and having a passion for it goes a long way.

There have been many times in my career when I’ve got ahead of myself, fallen flat on my face and had to pick myself up, figure out what went wrong and ask for help. Building relationships is really important: we all need other people to work with as none of us can be successful on our own, and it’s really satisfying and motivating to work with great people and a great team.

Do you have a mentor and what did they teach you?

I’ve learned a lot of things from different people. I started in the industry because my father ran a coal-fired cogeneration plant in Derby. Growing up, the things we would hear at the kitchen table as children in terms of managing people, managing operations and maintenance, everyday problems and troubleshooting, were things all things which have come in useful in this job.

In my first job, I had a really great boss who was an extremely hard worker and had a very balanced view of things and always found solutions to problems. He was definitely very influential, though there have been many people along the way. I think the longer I’ve been working, the more I see things that have had a lot of influence on me that earlier in my career I never recognised. It is definitely a journey.

Three years ago, the Galloper wind project looked dead and buried. SSE pulled out of the UK offshore development in late 2014, and remaining developer RWE Innogy put it on hold. With stiff competition, it looked like Galloper would fall by the wayside.

Then it staged a resurrection that would make Jesus proud. In October 2015, RWE Innogy said it would start building Galloper after it secured backing from Macquarie Capital, Siemens Financial Services and the UK Green Investment Bank, which is now part of Macquarie. The 353MW £1.5bn scheme was completed this March.

The commissioning also enabled Irish state-owned utility Electricity Supply Board to then enter the offshore market, as it bought 12.5% of Galloper from Macquarie. ESB owns a stake alongside Innogy (25%), Macquarie’s Green Investment Group (25%), Siemens Financial Services (25%), and Japan’s Sumitomo (12.5%). We talked to David McNamara, renewables manager in asset development ESB, about this deal and what it means for ESB’s plans more broadly in wind in the UK and Ireland.

McNamara says that ESB had been looking at investment opportunities in offshore wind “for several months” before the Galloper deal, and that it took the plunge with this project because it “represented an excellent combination of a strong project, excellent sponsors and debt providers”. He calls it the “perfect size” for its entry.

This isn’t the first time that ESB has considered offshore wind projects, though. In 2017, the company said it was looking to establish offshore wind farms in Ireland’s waters, and planned to make its first Irish offshore wind deals in the early- to mid-2020s. However, this is the first time that it has taken a stake in a working project.

McNamara says ESB sees the UK and Ireland as “increasingly integrated market” and that “Galloper is a very natural addition to that business”.

This represents a significant move for ESB, which had previously focused on the onshore sector. The company has a 400MW onshore portfolio in the UK and Ireland, of which three of the projects totalling 125MW are in the UK. In total, ESB operates 18 wind farms, ten thermal power stations and nine hydro plants in the countries.

McNamara says that increasing the proportion of wind in its portfolio will be key as it seeks to increase the proportion of zero-carbon generation in its asset mix. He says wind can help provide “bulk, low-cost renewable energy… Therefore, we see it as being a very important component of our generation portfolio in the coming years”.

One potential obstacle to ESB’s growth in Ireland is the fact that the government is overhauling renewable energy support, planning guidance and grid access rules. McNamara says it is difficult to discuss the direction of Irish policy in great detail as the new system is still taking shape, but he adds that the business case for wind is getting stronger because of cost reductions and the growth of electric vehicles.

He says: “In addition, as the carbon content of electricity continues to drop, the case for electrification of transportation and heat with efficient electricity technologies becomes compelling. This is positive for renewable electricity and ESB expects to play its part in further reducing the carbon intensity of the Irish economy.”

Galloper may be ESB’s first foray in the offshore wind sector – but, with momentum starting to pick up in Ireland and asset sales in the UK as owners look to recycle their capital, we don’t expect it to be the last.

When you think of Colombia, two of the first words that come to mind are probably coffee and cocaine. There’s just something about the country and stimulants – but now it is the investors that are helping to stimulate the nation’s wind market.

Two recent deals show that the South American country is on the radar of wind investors.

German investor MPC Capital and developer Martifer Renewables formed a joint venture in March to build wind and solar projects in the country. And, last month, a joint venture of Colombian utility Celsia and Portugal’s Renovatio started developing two wind projects totalling 330MW in the La Guajira region.

These might seem small deals but, in a country with only 19.5MW of installed wind capacity, they signal that something is changing.

Colombia has massive wind potential and, in particular, the northeast region of La Guajira has strong winds that could support the installation of up to 21GW of wind farms. But, at present, 69% of Colombia’s energy mix is from hydro, 30% from fossil fuels, and only 1% from wind and solar.

Nicolas Navas, project finance director at Latin America-focused developer Jenner Renewables, says that Colombia is a “sleeping giant of renewables”. But he says there are three issues that have prevented Colombia from unleashing its potential thus far.

First, wind developments would require more investment in grid connections. Navas says the areas with the best wind resources are not linked to the rest of the country, and this means that government and developers would need to build adequate grid connection to make the largest wind projects viable.

Colombian utility Grupo Energia Bogotá won a contract in February to build and operate a 370km power line able to carry 1.4GW of wind capacity by 2022. However, the construction of long transmission links is often challenging and unpredictable in emerging markets. Problems at the Kenya’s Lake Turkana show exactly that.

Also, while the grid currently copes well with the existing capacity made up mainly of hydro, introducing wind and solar in the mix may require work on the capacity and transmission of the existing network.

Second, he says that legislation is “not really there yet” to support the development of a wind market. As the country heavily relies on hydropower, new laws to support wind and solar by, for example, giving priority grid access have not yet happened. Likewise, last November, the Colombian government announced its intention to hold its first renewables auction by the end of this month, but plans have stalled since.

Third, financing could present a challenge for inexperienced investors. Navas says: “Financing will happen mainly through local banks, for example… In an ideal world, there would be an auction in Colombia which leads to a long term PPA, key to any renewable project, which is denominated in US dollars. But I don’t think that would happen, the revenue generation will be denominated in Colombian peso.”

This means that developers would have to deal with a currency risk attached to their long-term financing, which would affect capital costs of wind schemes. This is highly relevant since there are very few investors in Colombia with the financial capabilities to assume high financing costs of renewables projects.

The picture looks challenging, so why are investors currently looking at the country?

Many investors now seem to be positioning themselves in the market as they expect favourable regulations to come. These would follow the new term for the Colombian president that is set to start on 7th August following elections this month and next.

Navas is confident: “After August, it is likely that legislations and auctions will be introduced. By the end of this year or the beginning of next one, there will be much more noise about legislation in Colombia and it would be the right time to invest.”

But much will depend on who succeeds incumbent President Juan Manuel Santos, who cannot stand again after serving two terms. The current favourite appears to be the right-wing pro-oil Ivan Duque, but other candidates are more pro-renewables – including the left-wing Gustavo Petro. This will be a key vote for wind in Colombia.

It has the resources, but it also needs the political will. One to watch.

Wind Watch

By Jatin Sharma, President, GCube Insurance Services

The US offshore sector needs to find a balance between lowering the levelized cost of energy (LCOE) and retaining the public and political buy-in needed to help it flourish.

INTERNATIONAL EXPERTISE VERSUS LOCAL SUPPORT

Recently, the US government announced 25% tariffs for Chinese imports including the biopharma, robotics and aviation industries. This is just the latest in a series of protectionist tax reforms imposed by the Trump administration which have garnered attention worldwide – much of which has been negative.

Tariffs on solar panels, intended to protect American panel manufacturers, were widely labelled counter-productive when announced in January – and little wonder. With US solar developers no longer able to benefit from the cheap Chinese panels that have, in the past, contributed to project viability, US development schemes – and the revenue and jobs they create – are feared to be under threat.

Experts have warned of similar effects from recently announced steel tariffs, with Wood Mackenzie Power and Renewables analysts pointing out that: ‘Steel and aluminum are important commodities for critical wind, solar and storage components, with few bankable substitute materials available.' The consensus appears to be that import taxes will damage, rather than bolster, the local economy.

Yet these recent examples of addressing the trade deficit highlight an important issue.

For, while international free trade has undoubtedly been integral to the success of sectors such as the global wind industry, helping to drive down costs and accelerate growth, this has often come at the expense of local economic prosperity, undermining public and political support for local development.

Losing public and political support threatens very real damage to nascent markets such as US offshore wind. The benefits of free trade – most notably, its integral role in driving down the Levelized Cost of Energy (LCOE) – must therefore be weighed against the dangers of alienating local communities and governments.

There is a balance to be struck, here – and doing so will be particularly necessary for the US offshore wind market, as it seeks to become a more mainstream provider of...

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The US offshore sector needs to find a balance between lowering the Levelized Cost of Energy (LCOE) and retaining the public and political buy-in needed to help it flourish

The US offshore sector needs to find a balance between lowering the Levelized Cost of Energy (LCOE) and retaining the public and political buy-in needed to help it flourish. Jatin Sharma, President of GCube Insurance and Financing Wind New York speaker, reports

INTERNATIONAL EXPERTISE VERSUS LOCAL SUPPORT

Experts have warned of similar effects from recently announced steel tariffs, with Wood Mackenzie Power and Renewables analysts pointing out that ‘Steel and aluminum are important commodities for critical wind, solar and storage components, with few bankable substitute materials available’ (GreenTech Media, 2018). The consensus appears to be that import taxes will damage, rather than bolster, the local economy.

Yet these recent examples of addressing the trade deficit highlight an important issue.

There is a balance to be struck, here – and doing so will be particularly necessary for the US offshore wind market, as it seeks to become a more mainstream provider of American energy.

THE ROLE OF FREE TRADE IN OFFSHORE WIND

Many have made the case for the role of free trade in allowing US offshore wind to take off. Certainly, the ability to import technology and expertise from more established markets has played a pivotal role in the development of offshore wind elsewhere, both in driving down costs by creating competition and incentivizing innovation, and in allowing for the transfer of knowledge across national boundaries.

With only one project complete off the US coast (Deepwater Wind’s 30MW Block Island), the US offshore wind sector is sorely lacking the expertise and established supply chain required for success. While offshore oil and gas experience – for example, from oil drilling in the Gulf of Mexico – offers some transferrable skills, the US would benefit from importing the sector-specific expertise needed to precipitate growth while maintaining efficiency, thus keeping costs low without compromising on quality.

Mature markets such as Germany and Denmark offer decades of experience, and the reputations of European manufacturing giants such as Vestas and Siemens Gamesa, combined with their long-term service warranties, provide quality assurance. In addition, established conglomerates such as these are more likely to adhere to the high standards laid out by international bodies such as the World Trade Organisation (WTO).

Unsurprisingly, the rewards on offer have led developers to favour low-cost, highly experienced foreign supply chains over domestic offerings. However, the tendency of the industry to outsource manufacturing and services to markets with established legacies in offshore wind – understandable though this may be – can lead to public and media backlash.

OPPOSITION TO THE UK OFFSHORE WIND MARKET

Since its inception, the UK offshore wind market has relied heavily upon imported expertise to drive the market, from its first pilot project, Blyth, through advancements most recently leading to the world’s first utility-scale floating wind farm, Aberdeenshire’s Hywind, which came online in October 2017.

Yet the failure of UK offshore wind projects to demonstrably contribute to the local economy has, in the past, resulted in public and political disquiet.

Take, for example, the case of Thanet Offshore Wind Farm, opened in 2010 off the coast of Kent. The project, the largest offshore wind farm in the world at the time, used Italian submarine power cables, while turbines were installed by the Danish services provider A2SEA and maintained by the turbine supplier, Vestas – also Danish.

The project, owned by Swedish developer Vattenfall, attracted significant negative media attention when it emerged that only 20% of investment in the wind farm was contracted to British firms – among them, the Aberdeen-based company SubOcean, which signed on to lay the subsea cables (The Guardian, 2010).

The London Array offshore wind scheme attracted similar criticism after developer E.ON revealed that less than 10% of its contracts were awarded to UK companies (The Guardian, 2010).

Despite the undeniable truth that Britain simply lacked both the capacity to manufacture turbines and the supply chain experience necessary to lower costs and ensure quality, local industries felt cheated out of the work that they had been promised by renewable energy advocates and politicians alike. Meanwhile, public opinion reacted against the idea of UK taxes, awarded to projects in the form of subsidies, failing to generate any benefit for British citizens.

These low levels of ‘local content’ – work awarded to domestic firms – threw doubt on the conviction, shared by industry and politicians alike, that renewable energy would be a growth sector, providing jobs and kick-starting manufacturing following the 2008 financial crash.

UK SUPPORT FOR LOCAL CONTENT

In this period of uncertainty, various solutions to the challenge of retaining public and political support for the industry were floated, including a minimum local content requirement for projects.

While this has not yet seen implementation – perhaps due to concerns about contravening world trade rules – the then-Energy Minister Michael Fallon asserted in 2013 that future projects would have to produce ‘supply chain plans’ in an effort to encourage projects to support the local economy (Business Green, 2013).

The British government subsequently agreed a 50% local content goal with trade body RenewableUK, and a later study commissioned on behalf of the Offshore Wind Programme Board found that UK offshore wind farms invested an average of 48% in the domestic economy through local content (RenewableUK, 2017).

The UK economy has benefitted correspondingly, with the offshore wind sector creating local jobs, supporting factories and industries, and increasing the local tax base. These benefits can be further reinforced by the option to export these goods and services. Meanwhile, any cost savings attributable to the locality of the supply chain and the independence from exchange rate fluctuations can be passed down to ensure lower cost electricity for the end user.

APPLYING LESSONS LEARNT

Returning to the US, the longstanding Jones Act – which requires vessels operating in US ports to be American-made and -owned – ensures that all US offshore wind farms will necessarily create some jobs and opportunities for American maritime companies.

However, securing further benefits for the domestic economy will be key to achieving, and retaining, public and political support for the nascent American offshore wind sector – and this will, in turn, be important for the success of the market as a whole.

For, just as political support in the form of subsidies was integral to the initial viability of offshore wind in markets such as the UK, the global sector remains subject to political decisions in the form of Contracts for Difference (CfD) auctions and planning permission grants. Meanwhile, dissenting public opinion can create problems ranging from lawsuits to lobbying groups such as Mothers Against Wind Turbines.

WHAT DOES ‘LOCAL CONTENT’ ACTUALLY MEAN?

In addition, confusion around the exact meaning of ‘local content’ can lead to difficulties in quantifying it.

In its broadest form, ‘local content’ could encompass the development, construction and operational phases of a wind farm, including physical products created – such as turbine blades – as well as the logistical work required to construct the farm. Associated service industries such as risk management and insurance, as well as the maintenance of turbines throughout the wind farm’s operational life, could also be included.

Yet definitions vary; a survey of leading project managers in 2012 showed significant divergence in the definitions ascribed to ‘local content’ by different companies (Jatin Sharma, Master’s thesis, 2012).

And the decision of what to include in – and exclude from – this definition is a wide-reaching one; for example, the decision to include operations and maintenance services (often supplied on a long-term basis by domestic companies) is likely to significantly push up the calculated percentage of local content.

To ensure clarity and transparency, the US offshore wind sector should agree on a unified definition of ‘local content’, just as the UK has done in its ‘UK Content Methodology’ (RenewableUK).

STRIKING A BALANCE

Free trade has certainly been integral to the success of offshore wind markets in Europe, and particularly the UK, which – at least in its early years – imported a large majority of content from long-standing, reliable and experienced supply chains in Europe.

However, as the case of Thanet Offshore Wind Farm – among others – showed, the failure to provide tangible benefits to the local economy can result in significant backlash to projects. This in turn can affect political decisions pertaining to auctions and subsidies, as well as planning permission grants.

Inversely, if managed correctly, local content has immense power to achieve public and political buy-in. This is nowhere more apparent than in the softening of President Trump’s stance on wind energy, prompted by the hundreds of thousands of American jobs created by onshore wind (Renewable Energy World, 2017).

It is therefore clear that local content, with its potential to secure domestic support for projects, will be integral to the success of the US offshore wind sector.

Supporting domestic supply chains while keeping costs, and risks, low will be challenging, and the case of the US solar panel taxes – intended to protect American manufacturing jobs, but in reality likely to jeopardise jobs in project development – highlights the complexity of negotiating local content policies.

Get it wrong, and you risk either alienating both the public and government – endangering the viability of a sector that relies on the support of both – or stifling development by imposing too-stringent sanctions on imported expertise and low-cost, high-quality products.

For US offshore wind, a nascent sector at the mercy of a renewables-sceptic government, getting the balance right has never been more important.

Here’s an exciting experiment for you.

Take one UK wind industry professional and start a conversation with them. Q2 Quarterly Drinks would be a great place to do so.Then mix ‘EDF’ and ‘UK energy policy’ into one of your sentences. If done correctly, this should provoke an extreme reaction of eye-rolling and exasperated sighs.

I’m sure you know why. Five years ago, the UK government agreed to let French utility EDF build the controversial Hinkley Point C nuclear power station in Somerset, paying a guaranteed £92.50/MWh that it set to rise in line with inflation.

The deal looked expensive then, and stunning falls in the price of offshore wind and onshore wind since then have made it look more so. The £20bn 3.2GW project could also be ruinous for EDF if the worst fears for problems at the projects are realised. It is set to use the same reactor design as the Flamanville project in northern France, which is six years late, three times over budget and facing problems with its welding. Mon dieu!

But this focus on Hinkley Point C makes it easy to forget that EDF is a serious player in UK wind. The utility currently operates 27 onshore wind farms with total capacity of 489MW, and the 62MW Teesside offshore wind farm off the Yorkshire coast.

And the company reminded us of its UK wind plans last week as it picked up headlines, good and bad.

Let’s start with the good. On Thursday, Mainstream Renewable Power revealed that it had sold the 450MW Neart na Gaoithe offshore wind project to EDF for a price of more than €500m.

Mainstream won backing for the project under the UK’s Contracts for Difference regime in 2014 at a strike price of £114.39/MWh, which has now risen to £127.21/MWh. The project was then mired in a legal fight with bird charity RSPB, which was only resolved in Mainstream’s favour by the Supreme Court in November.

That battle was frustrating, of course. But the fact Mainstream has been able to exit means that it can reinvest the proceeds in its emerging markets strategy. And EDF has a project that is ready to build, with a CfD that looks generous given the fall in the cost of offshore wind power over the four years since it was awarded.

It could also help EDF to establish itself in offshore wind, which it has not been able to do in its home market. It gained support from the French government in 2012 to develop three offshore projects with total capacity of more than 1.4GW, but it has experienced delays and is now faced with a government that wants to change the generous deals agreed then. Say what you like about Theresa May and co. – at least when they end up with something that looks like a bad deal, they stick with it!

But it isn’t all straightforward for EDF’s UK wind ambitions. Last week, it emerged that the utility has been looking to renegotiate plans for two onshore wind farms on the Scottish island of Lewis, to increase turbine heights at its 162MW Uisenis and 130MW Stornoway wind farms from around 150metres to 200metres.

EDF has been looking to take advantage of UK government plans to back onshore wind farms on remote Scottish islands – in other words, away from England and any Conservative heartlands where it could cause more political headaches.

And yet, it turns out that crofting communities in Scotland have opinions too, and are furious about the idea of building offshore-sized turbines on land. EDF, via its Lewis Wind Power joint venture with Amec Foster Wheeler, plans to bid for UK government support in a planned CfD auction in 2019.

I can see the logic for bigger turbines. They would help EDF to generate more power at the same site. But I also sympathise with objectors who were already against the development and are now faced with even bigger turbines near them. This isn't the way for EDF to secure more of the local support that the schemes need.

Goodness knows, it could do with a little less of the eye-rolling.

Guest blogger Jon Rose of Hyperion Executive Search reflects on the last decade of US wind, and gives his predictions for what's ahead.

Guest blogger Jon Rose of Hyperion Executive Search reflects on the last decade of developments in American wind power, and gives his predictions regarding how US wind could reach its 2030 targets.

It’s July 2008. The New England Patriots are embroiled in ‘Spygate’ after losing to the New York Giants in SuperBowl XLII, Bill Gates has stepped down as the chairman of Microsoft and Barack Obama has just secured the Democratic Party Presidential nomination. Time flies by.

It’s now exactly a decade since the American Wind Energy Association published an in-depth report detailing a bold new vision for wind power in North America: 20% Wind Energy by 2030. This technical report was not intended as a prediction of the future, but sought to paint a hypothetical picture of the national consequences of increasing wind energy’s contribution to US electricity supply.

Ahead of the annual AWEA conference in Chicago this month, coinciding with the twelve-year anniversary of the Bush Administration’s call for the US to rethink its energy mix, now is a good time to review the key points and challenges raised in this report. It’s interesting to see how things have changed since 2008, particularly given the current President’s alternative views on clean energy research and climate change.

Expanding markets and multiple revenue streams

To achieve the 20% by 2030 scenario, according to the 2008 report, would require large expanded markets to purchase and use wind energy and that multiple revenue streams for wind generation output would be increasingly important.

The landscape has changed drastically in this respect. The cost of renewable energy has plummeted and so, with companies, cities & universities looking to be more sustainable, wind energy has become the number one choice for corporate and non-utility purchasers. US businesses, from tech giants to grocery stores, signed up to over 2GW of wind energy in 2017, a huge jump from 100MW in 2009.

The other main buyers of energy, utilities, are rapidly evolving to benefit from America’s wind power boom, moving away from primarily purchasing power from wind farm owners and instead buying the assets outright. With the cost of building wind farms sliding, owning renewables is a more attractive proposition than ever for utilities as they look to diversify their portfolio. AEP is investing $4.5bn that will land them a massive 2GW wind farm in Oklahoma and Xcel Energy is looking to add 3.4GW of new wind energy over the next five years.

The future looks very promising with a much greater and varied demand for wind power, driven by Fortune 500 companies, cities and universities looking to go green as well as utilities providing cleaner, cheaper energy for their customers.

Technology: Improving output and reducing cost

The 2008 report stated that with sufficient research, development, and demonstration, new advances could potentially have a significant impact on commercial product lines in the next 10 years. In 2018, this is very much in play as rotors are getting larger and towers are getting taller, resulting in considerable increases in capacity.

In 2006, the installed wind capacity of North America was 11.6GW and the average size of an onshore turbine was 1.6MW. Fast forward twelve years, and there is now over 89GW of wind capacity and more than 90% of turbines are 2MW or larger, with 23% at 3MW or larger. GE have recently announced significant investment specifically to build a 12MW offshore wind turbine by 2020, the largest the world has ever seen.

Technology advancements have significantly lowered the levelized cost of electricity and, to realistically achieve 20% by 2030, the industry is evolving to continually improve its output (performance) and reduce its cost (maintenance). With a growing number of projects across the US, enormous amounts of data are being generated and companies are increasingly turning their attention to the Internet of Things (or the Industrial Internet) to maximise the efficiency of existing equipment, moving away from traditional, reactive O&M to more sophisticated, predictive and proactive O&M solutions.

There is huge potential for these techniques to provide value to the industry in the coming years. Through harnessing the data at their disposal, wind farm operators can better understand what is happening in the field, plan ahead, and accurately predict extended operating life, resulting in reduced maintenance costs and improved performance.

Providing accurate forecasts, increasing the generating capacity, improving the life span of assets and reducing project uncertainty are key goals for the wind industry moving towards 2030, improving bankability, reducing project risks and creating a more attractive opportunity for long-term investment & policy support.

Offshore Wind – can the US follow in Europe’s footsteps?

The growth of offshore wind in Europe is still too expensive and too difficult to replicate in US waters, the 2008 report concluded. However, it did illustrate the vast opportunity that exists for the nation moving towards 2030. The report showed that the US has an enormous 4,150GW of potential offshore wind power capacity, an amount 4 times that of the country’s total installed capacity from all sources in 2008 - 1,010GW.

In 2018, after a number of false starts, the offshore wind industry in the United States finally seems to be gaining some momentum. Although still lagging behind the burgeoning offshore industry in Europe, companies such as Statoil, Avangrid, and Ørsted are joining US wind energy developers to pursue a number of projects along the U.S. coast. According to the US Department of Energy, over 25 offshore wind projects (24GW) are being planned off the North East and Mid-Atlantic coasts and though not all of these will be built, and only one commercial offshore wind has been constructed (Block Island, which became operational in 2016), the majority of analysts predict that offshore wind is expected to see significant growth in the coming decade.

As oil and gas companies look to diversify into clean energy there exists an opportunity for the wind industry to utilise an enormous network of skilled workers, existing infrastructures and the expertise in operating major offshore projects; this is something the Trump administration is taking note of. In April 2018, interior secretary Ryan Zinke threw his weight behind offshore wind, citing economic, environmental, moral and strategic reasons for looking to partner with this emerging industry.

Whilst there remain several obstacles ahead that make the widespread development of offshore wind farms less than a foregone conclusion, they are being met by a flurry of innovation and activity. Of the present US energy portfolio, offshore wind has the greatest opportunity for growth in the coming years.

The importance of long-term, stable policy

The 2008 report notes that achieving the 20% wind scenario would involve a major national commitment to clean, domestic energy sources and would require clear leadership from Congress to provide wind energy with the long-term, stable policy it provides to other energy sources.

Two years before the 2008 report was published, President Bush emphasised the nation’s need for greater energy efficiency and a more diversified energy portfolio. Despite often being criticised as being an anti-renewables President, during his time as Governor of Texas Bush signed a bill that set the state on a path to becoming a leader in generating carbon-free electricity. During his second term in power, from 2004 through 2008, over one-third of the electricity capacity added in the US was from wind power, largely due to federal subsidies and other government tax breaks.

In 2012, under Obama, wind energy became the number one source of new U.S. electricity generation capacity for the first time, representing 43% of all new electric additions and accounting for $25bn in U.S. investment.

Now in 2018, it’s clear that the industry has capitalised on this momentum. Declining costs and the longest ever period of federal policy stability have led to new records being broken, popularity across demographics, and now a growing number of cities adopting a 100% renewable energy target by 2030 (Minneapolis has recently become the 65th city to join this list including Atlanta, Portland and San Diego).

Like many other energy industries, wind has relied heavily on federal incentives, particularly the bipartisan Production Tax Credit, introduced in 1992 to help finance & construct new projects. As the PTC is phased out by 2019, wind energy is well placed to compete without this support, but the sector shouldn’t take anything for granted and will face new challenges as it continues to contest with heavily-subsidised competition.

So what’s next?

The key suggestions of the 2008 report for that large expanding markets continuing to purchase and use wind; improved turbine technology, utilising previously untapped offshore wind potential; and clear and consistent policies.

Although changes to transmission systems still need to be addressed, and we shouldn’t get complacent about the PTC phase-out, the US wind industry is moving in the right direction.

Wind power is the cheapest form of new electricity, having generated 6.3% of US electricity in 2017. In four states (Iowa, Kansa, Oklahoma and South Dakota) wind generates over 30% and 14 states are currently producing over 10% of electricity by wind. AWEA now predicts that wind energy can grow to supply 10% of total US electricity by 2020 and support tens of thousands additional well-paying jobs.

Despite initial uncertainties about the impact of a Trump administration, given that the president had criticised regulations that pressure businesses to address climate change, talked openly about his distaste for wind turbines and in 2018 looked to cut funding for clean energy by 72%, American companies are investing more than ever in wind energy. American companies are building more wind energy projects and bipartisan Americans want more wind energy than coal. Whilst this follows a global trend towards greater sustainability, it is the economics of wind energy in the US that are converting aspirations into actions.

A decade on from the report, US wind energy has faced its fair share of challenges but just like the New England Patriots, it continues to roll on whether you like it or not.

Jon Rose is a Principal Search Consultant at Hyperion Executive Search, a specialist in clean energy recruitment. He has spent the last 5 years working in the US supporting wind developers, IPPs and OEM’s in their search for talent. Whilst he doesn’t care much for the New England Patriots, he is a passionate supporter of renewable energy & clean technology!

The battle to connect Kenya’s flagship Lake Turkana wind farm to the grid is again in the news as will now fall to Kenyan consumers to help foot the bit for delays. We first wrote about this “compelling” 310MW scheme in 2013. Is it still so?

The wind farm is near Lake Turkana in northern Kenya, and has been developed by a consortium including KP&P Africa, Aldwych International, Finnfund, Norfund, the Investment Fund for Developing Countries, Sandpiper and Vestas.

The development reached financial close in December 2014 and construction started in 2015.

That year, Google announced that it would acquire a 12.5% stake in the project from Vestas upon completion, which was due in 2017; and Vestas completed installations of 365 of its 850kW turbines in March 2017, two months early. This is where the story stalls. The project is ready to be connected to the grid, the power line is not.

Construction of the 428km transmission line, which would carry wind power from the north to the centre of Kenya, started in November 2015 but it is not complete yet. It is no small feat, given the vagaries of land ownership in rural areas of Kenya, and the need to station guards along the length of the line to stop cables from being stolen.

The project also faced a major setback when its main contractor, Spanish firm Grupo Isolux Corsan, closed due to financial difficulties last year. The Kenyan government assigned then the work to Chinese companies Nari Group Corporation and Power China Guizhou Engineering Company, which are still working on the project. These delays have been affecting investor confidence, and are set to hit consumers too.

In fairness, Kenya’s government has been in talks with the owners. In September, it agreed to pay KES10.3bn (€86m) to the Lake Turkana consortium, setting January 2018 as the new deadline to complete the transmission line. The figure included a KES5.7bn (€48m) fine to be paid by a monthly increase in consumer bills spread across six years; and a KES4.6bn (€38m) payment to a special fund created by the government to cushion Lake Turkana’s investors from losses.

When the contractors failed again to meet the January deadline, energy minister Charles Keter committed to pay an additional KES1bn (€8.3m) if the link was not ready by the end of June. And, last week, the government approved an additional payment of KES960m (€8m) each month to the Lake Turkana consortium, signalling that the June deadline won’t be met, and that consumer bills will need to rise.

But what impact will this have on the development of the wind sector in Kenya?

The situation may not be encouraging for investors – but, then again, a 428km grid link to a project in a remote part of Kenya was always going to be a risk. It’s a good reminder that grid links cannot be taken for granted, especially in new markets.

The Kenyan government has also given other investors cause for optimism. There may be problems with the Lake Turkana link, but it is also making sure that it has a deal in place with the investors to compensate them. That must help confidence.

It is also worth noting that problems with transmission links aren’t insurmountable. In the early days of German offshore wind, for example, there were big problems with TenneT failing to connect projects on time. That is now fading to a distant memory.

The biggest problem we see here is that consumers are now picking up the tab for these delays. These people were promised cheap electricity produced by the wind farm, but they are now facing higher bills because the costs of the continue delays. This has become a reputational issue for the wind industry in Kenya, and will make life harder for developers that might already face opposition over land issues.

Kenya wants 1GW of installed wind farms in the next two years and 3GW by 2030, but sceptical investors and hostile consumers would make that hard to achieve. Last week, Keter set September as the new deadline for getting Lake Turkana connected to the grid. The sooner that happens, the less damage this will cause.

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In simple terms, what does your company do?

What do you want from an A Word About Wind membership?

Of the deals you’ve worked on, which is your favourite and why?

In which markets do you see the best opportunities right now?

What is the biggest challenge facing wind and how would you fix it?

Which trends will affect the wind sector most in the next 5-10 years?

What are the most important lessons you’ve learned during your career?

Did you have a mentor and what did they teach you?

Reasons behind price reductions

Nothing strange about that, you might say.

So where is this extra cost effectiveness going to come from?

Why is the UK a leading offshore wind market?

The UK has an impressive track record when it comes to offshore wind.

And importantly, the offshore industry has enjoyed government support.

In the UK, offshore is set to continue making a significant economic contribution.

Opportunities for offshore wind

OVERVIEW

CORPORATE TAX RATE AND AMT

EXPENSING

BEAT PROVISIONS

TECHNICAL TERMINATION OF PARTNERSHIPS

PREPAID POWER PURCHASE AGREEMENTS

INTEREST LIMITATION

Endnotes

In simple terms, what does your company do?

Of the deals you’ve worked on, which is your favourite and why?

In which markets do you see the best opportunities right now?

What is the biggest challenge facing wind and how would you fix it?

Which trends will affect the wind sector most in the next 5-10 years?

What are the most important lessons you’ve learned during your career?

Do you have a mentor and what did they teach you?

INTERNATIONAL EXPERTISE VERSUS LOCAL SUPPORT

THE ROLE OF FREE TRADE IN OFFSHORE WIND

OPPOSITION TO THE UK OFFSHORE WIND MARKET

UK SUPPORT FOR LOCAL CONTENT

APPLYING LESSONS LEARNT

WHAT DOES ‘LOCAL CONTENT’ ACTUALLY MEAN?

STRIKING A BALANCE

Expanding markets and multiple revenue streams

Technology: Improving output and reducing cost

Offshore Wind – can the US follow in Europe’s footsteps?

The importance of long-term, stable policy

So what’s next?