New Trends: Developer Perspective

New Trends: Developer Perspective

July 09, 2015 | By Keith Martin in Washington, DC

Developer optimism about the renewable energy market is on the upswing. A lot more money is chasing renewable energy today than two years ago. The degree of penetration of enewables into the global energy supply has accelerated substantially. Roughly a third of the US coal-fired fleet is expected to be retired during the period 2017 through 2020. Demographic changes among US voters could lead to a tipping point in US public opinion about the need for tougher action on global warming.

Five top developers had a wide-ranging discussion about market trends at the annual REFF Wall Street conference hosted by Euromoney and ACORE in New York in late June. The five are Andrew de Pass, CEO of Conergy, a developer and construction contractor of solar photovoltaic projects, Bud Cherry, CEO of Eagle Creek Renewable Energy, an aggregator and owner of small hydroelectric projects, Kevin Smith, CEO of SolarReserve, a developer of solar thermal projects and molten salt storage facilities, Tristan Grimbert, CEO of EDF Renewable Energy, the North American arm of Electricité de France, and Thomas Plagemann, executive vice president for capital markets at Vivint, a rapidly-growing solar rooftop company. The moderator is Keith Martin with Chadbourne in Washington.

MR. MARTIN: Andrew de Pass, what is different about the renewables market today than even two years ago?

MR. DE PASS: I come at this from the perspective of a solar company. Two years ago, oil prices were higher, so it was not as difficult to make competitive bids to supply electricity in certain countries. Of course today we also have the whole yield co craze whereby long-duration cash flows are in vogue. This has the potential, with the launch of vehicles like the SunEdison yield co aimed at emerging markets, to give developers like Conergy more transparency and visibility on take-out pricing in those markets. So one change is the fossil fuel pricing and a second is the attractiveness of the long-duration cash flows in the capital markets.

MR. MARTIN: So both reasons for optimism. You do not see any clouds on the horizon.

MR. DE PASS: We can start talking about regulatory issues, but that would be depressing.

MR. MARTIN: Bud Cherry, what is different today?

MR. CHERRY: Andrew’s perspective on finance is spot on. The significant penetration of renewables into the broader energy supply has accelerated substantially since a couple of years ago. If there is a cloud, it may be concerns in some states that renewable portfolio standards are driving up electricity prices.

MR. MARTIN: So the rate of growth in renewables is accelerating, but you worry about the potential for erosion in political support?

MR. CHERRY: I worry about the political factor that is beyond the control of the primary players in the business.

MR. MARTIN: Do you, as a hydro developer, need renewable portfolio standards to thrive? Hydro does not qualify as a form of renewable energy under all state RPS programs.

MR. CHERRY: We do not qualify in all states, but we qualify in many states and, to the extent there is an RPS in place, it is certainly helpful to us.

MR. MARTIN: Kevin Smith, what is different today?

MR. SMITH: We have seen a big increase in international activities in some markets where people would never have considered going in the past. The African continent is now the hot place to go for renewable energy activity. Some countries where you would never have imagined going a few years ago are now open for business.

MR. MARTIN: Which countries in particular?

MR. SMITH: We have been very active in South Africa, but the continent as a whole is opening up. The fact that yield co funds are now looking at targeting emerging markets will help drive more business.

Another change is that for the first time over the last couple years, you see renewable energy being chosen as the least-cost alternative in a lot of markets, including not only in some states in the United States, but also in South Africa, Chile, some other countries in Latin America and Dubai. Renewable energy is now being viewed as the least cost alternative over all other fuels in a growing number of markets.

MR. MARTIN: Tristan Grimbert, what is different?

MR. GRIMBERT: First, there is a lot more money looking to move into renewable energy. It is not only yield cos. There is an imbalance between the amount of money and the number of projects available for investment.

Second, our business is becoming more and more technical. Being able to deliver on the business plan requires more and more technical knowledge and resources. I am thinking in particular about turbine performance, congestion risk and basis risk. As there is more and more penetration of renewables, the ability to understand and act on business risk and market conditions is becoming more and more important.

The third thing that is different is we have reached a turning point in the last year in the US where we can talk again about carbon pricing and about moving away from subsidies to something that would recognize the cost of carbon. My hope is that, within the next five years, we will move away from renewable portfolio standards and all the subsidies to a truly market-based mechanism for carbon pricing. That is my hope.

MR. MARTIN: Thomas Plagemann, what is different?

MR. PLAGEMANN: Let me address the question from the perspective of a residential solar developer. There are three things.

There has been tremendous growth in distributed generation. It has become a much larger part of the total renewable energy installed capacity in the last couple years and, along with that, has come an increased acceptance by financial investors to do the work required to understand consumer risk and accept a portfolio of either commercial offtakers or residential offtakers as a substitute for utility-scale offtakers. We have also seen the tax equity market rebound rather nicely in the last couple years.

MR. MARTIN: Surprisingly, as the tax credits are about to expire, more tax equity investors come into the market.

MR. PLAGEMANN: If you look at the market history after the financial crisis, there was not a lot of profitability. I think in 2009, perhaps $1 billion of tax equity was done, but as financial institutions become more profitable, more money is shifting into tax equity.

Access to Capital

MR. MARTIN: Tristan Grimbert said there is a lot more money chasing renewable energy projects today than two years ago. There have been periods in the life cycle of this industry when developers have felt people are throwing more money at them than they can usefully deploy. Are you feeling that today and, if so, is the imbalance of money to projects being reflected in the cost of capital? Kevin Smith, let me start with you.

MR SMITH: I think so. It is not only yield cos chasing projects but also strategic investors, and the competition is driving down the cost of capital in the US deep into the single-digit numbers. Even in some of the emerging markets, the returns are being pulled down into the low teens. A few years ago, people would not have touched some of those markets unless the projected return was 18% to 20%, and now they are moving into the same markets for expected returns of 12% or 13%.

MR. MARTIN: It is not only the equity returns that are falling, but also developer returns?

MR SMITH: Equity returns, but after a time lag, the falling cost of capital ultimately pulls down developer returns as well because everyone is bidding lower and lower prices to supply electricity. There is always a bit of a time lag, so those that participated in the first wave of yield cos got nice premiums for projects, but then when they have to go back into the market to rebid, everyone is bidding lower power prices so asset valuations will eventually come down.

MR. MARTIN: Andrew de Pass, is access to capital no longer an issue for this industry?

MR. DE PASS: The cost of capital and availability vary at different stages from early-stage development, mid- to late-stage development, during the construction cycle from notice to proceed to the commercial operation date, and then for operating assets.

The market for operating assets is extremely competitive, and there is price visibility and good availability of capital.

In certain markets, construction finance remains a challenge. For example, as we look to finance projects in new markets like Turkey or Mexico or Southeast Asia, construction finance is more challenging and expensive. In the US, it is available for properly structured projects.

Late-stage development capital is available and the returns have definitely been pushed down. For example, in the UK where we developed, constructed and operate more than 200 megawatts in the last 12 months, we were buying later-stage development rights for a cash-on-cash return of 1.25 to 1.5 times investment, and that has now been pushed down to 1.1 times.

The returns are still very attractive in early-stage projects where the dollars per megawatt to develop are low in solar, $25,000 to $50,000 maximum, and the returns can be multiples. But you have to work with a portfolio because you can lose money in any one project.

The point is it is important to differentiate among stages of development.

MR. MARTIN: So capital is not a problem for solar, especially as one gets farther along in the development cycle. Bud Cherry, hydro developer, plenty of capital?

MR. CHERRY: It is important to note that our business plan is to deal primarily in operating facilities. Only a couple percent of our portfolio is in what I would describe as late-stage development. We have seen the impact of a significant amount of new money entering the space and, as a result of that, we have gone back to our original business plan which was negotiating bi-lateral deals rather than bidding into large auctions with multiple bidders.

MR. MARTIN: So plenty of capital means that you are being pushed out of the market? You are backed by private equity, so you are not able to compete with the yield cos for operating hydro projects?

MR. CHERRY: We look for deals that are not attractive to the yield cos and other players who lack the ability to fix facilities that need work, either mechanical, structural or in their capital structures. We go after projects with some amount of challenge and do negotiated deals instead of participating in auctions.

Greatest Challenges

MR. MARTIN: Let’s move to the next broad question. What are your greatest challenges today? Bud Cherry, you just mentioned one of yours, so Andrew De Pass, let’s go back to you.

MR. DE PASS: Conergy has a global footprint and so the challenges vary by country. We operate in 15 countries.

One of our challenges in the developed markets is they are moving away from utility-scale to distributed generation including industrial rooftop. We expect this trend to continue over the next five years. Distributed generation is a different business than utility scale because you have to acquire customers, you have challenges with credit assessment, you have to scale up, and the projects are relatively small. The question is how are we going to make money consistently in such markets?

MR. MARTIN: You need lots of employees, and the business has more in common with the cable television business than with power.

MR. DE PASS: We are too late in the US to tackle residential, but we are a leader in solar in many other markets where residential is starting to take hold, and the discussion amongst senior management and the boards is do we or don’t we do this? The projections say that residential could be 30% of these markets and then you ask, “What is the business, and how do we do it effectively?” It is a customer acquisition business; it is not a technology business. What can we learn from the best practices in the US, and can they apply in other markets? Some do, and some don’t. So our challenge is, in addition to the complexity of managing a global solar downstream company, how do we make money consistently in distributed generation specifically with rooftop?

MR. MARTIN: In which countries are you trying to move to distributed?

MR. DE PASS: In the US, we are focused on small-scale utility as well as commercial rooftop. We think in the US market you have to have financial innovation, so we recently closed on the first commercial PACE deal with tax equity with the project owned by Conergy. In the UK, we launched a commercial industrial product. In Germany, we have rooftop partnerships with utilities like RWE and local residential players. And this morning, in our operating management board, we agreed that The Philippines are now emerging as a rooftop opportunity.

MR. MARTIN: Kevin Smith, what are your greatest challenges today?

MR. SMITH: There are two sides to our business. One is the development side where we are looking at PV and solar thermal, and we also have a technology side where we are developing large-scale storage. Our Nevada project, which is a solar thermal facility with storage, is just going into operation.

We started with energy storage when the company was founded. It is a key part of our business model. The challenge is finding those markets where storage is critical and can be integrated into the grid and where we can do it at a cost that is competitive.

MR. MARTIN: Your Nevada project is a power tower project with molten salt storage. Are you planning to do storage as a stand-alone business or always in aid of solar thermal electricity production?

MR. SMITH: Putting large-scale storage facilities in the US is difficult because of market conditions, but we are very competitive in places like Chile or South Africa or Saudi Arabia where they do not have $4 natural gas and they need help with grid reliability.

MR. MARTIN: Tristan Grimbert, greatest challenges?

MR. GRIMBERT: Defining a viable business model in the distributed space is a challenge with the lack of differentiation and the repetitiveness and credit issues. A lot of people are moving into that sector. It is very difficult to figure out how to make money. That is one area with which we are struggling.

Another challenge is finding the right balance for spending on the development pipeline in relation to the size of the market when the tax incentives are always on the verge of expiring. Five years ago, there were too many projects under development. I think the wind pipeline was something like 351 gigawatts for an annual market of six to eight gigawatts, so it was 50 years of projects. Today, the number has been reduced significantly.

Lastly, it is a challenge to forecast the price and cost curves accurately. We must take a view on the future price for electricity and the future cost of solar and wind equipment and the future cost of capital. We have been talking about yield cos and their impact on the cost of capital the last couple of years, but at some point the cost of capital will start going back up. You do not want to be caught in a trap where you have offered an aggressive electricity price to win a power purchase agreement and then the cost of capital goes back up.

MR. MARTIN: It has been a good business model for the past few years to bid low electricity prices figuring that by the time the project has to be built, equipment prices will have fallen. You do not want to be caught short when the pattern reverses.

MR. GRIMBERT: More on the capital side. On the equipment side, we expect the costs to keep falling. The issue is whether you are super wise or super lucky. I think it has been a mix of both, and we are trying to be wise.

MR. MARTIN: Thomas Plagemann, greatest challenges for Vivint?

MR. PLAGEMANN: The challenge and the opportunity both are to manage rapid growth, to continue scaling up and to maintain a track record of improved efficiencies and cost reduction. That is reduction in both operating costs and capital costs. We continue to look for ways to reduce the total cost of tax equity and debt financing. On the operating side, we are using software to reduce timing between different stages in the process, to reduce errors, to reduce rework, and ultimately to reduce costs. We are using technology, too, to reduce costs.

MR. MARTIN: The technology you envision using is . . . ?

MR. PLAGEMANN: We are working with our vendors to try to reduce the all-in cost of equipment. There is an operating side and a process side.

MR. MARTIN: Interestingly, none of you mentioned this. We are all in the business of selling electricity, and demand for electricity is barely growing. Isn’t that a challenge?

MR CHERRY: It has always been like that, and it is always going to be like that.

MR. MARTIN: It is just life as we know it?


MR. SMITH: Except that it varies by market. Certainly in the US, growth in electricity demand has been slow for a decade and the forecast is it will remain slow for another decade, but older generating capacity is retired and must be replaced. In certain international markets, electricity demand is growing by 6%, 7%, 8% a year.


MR. MARTIN: Something like 38% of US electricity supply is from coal. Consultants expect a third of that to be retired between 2017 and 2020, but there is a debate about whether that creates a lot of opportunity to replace that capacity. Does anyone think this is a great opportunity?

MR. CHERRY: It is unclear whether all that base-load generation can be replaced in the time frame that is being discussed, but it is helpful for us as a hydro owner and operator.

MR. MARTIN: Because you are a form of base-load generation that can replace coal? These other guys with wind or solar do not have the same opportunity?

MR. SMITH: Unless we have storage.

MR. GRIMBERT: There is room with or without storage. The coal retirements will allow us to keep a market in the range of five to 10 gigawatts of new wind capacity additions a year, and that is critical. You do not need a lot of storage to allow much more penetration of wind and solar. The coal retirements driven by the Clean Power Plan will allow the utility-scale wind and solar markets to continue adding capacity over the next 15 years at the current level. It was suggested earlier that the growth rate is accelerating. I do not think we have an acceleration of the growth rate, but I think we will have stable growth.

MR. MARTIN: The mood this morning is one of optimism. Let’s probe on storage. Many people say the widespread adoption of batteries will lead to a fundamental change in this market. Do you agree? When do you see that happening?

MR. SMITH: I am a bit biased because we have an alternative to batteries, and the cost of batteries is pretty outrageous. Our molten salt facility in Nevada has 1,100 megawatt hours of storage. I think the largest battery storage facility is 50 times smaller than that and 10 times the cost.

MR. MARTIN: Into how many hours of storage does that translate?

MR. SMITH: We have up to 10 hours of storage for about 110 megawatts. This is a tremendous benefit in places like South Africa and Chile where they need help with the grid. The outlook for storage in the US is a little less clear. Various pilot projects are underway.

I agree with Tristan that not much storage will be needed to facilitate more wind and solar capacity additions. At some point, a tipping point will be reached where we will need a lot more storage, but in the near term. California has storage requirements, but without a lot of teeth behind them. Turning to batteries, Tesla has sold out for a couple years on batteries because a lot of people decided that having a battery is the fashionable thing to do.

MR. MARTIN: What do you mean Tesla sold out?

MR. SMITH: Reports in the trade press are that Tesla has already sold two years’ of production.

MR. DE PASS: We have a different perspective from Kevin because of the potential scale of the storage solution. We are focused on batteries. Conergy has an R&D lab focused on storage in our headquarters in Hamburg because we think it is critical to integrate storage into our system offering in the medium term. Our R&D specialists in storage used to think it would take four or five more years to become economical; we see the trend accelerating to a point where we now expect batteries with a couple hours of storage to become economical in the next two years.

In Germany, solar kits are offered today with storage. This makes sense in Germany because there is no residential net metering. We have pilot projects that are relatively small for the use of lithium ion batteries for small utility-scale solar projects. In Australia, we have a 13-megawatt project we are developing, and funding that will be an important global pilot for the use of storage.

MR. MARTIN: You are installing a 13-megawatt lithium ion battery?

MR. DE PASS: The solar project as a whole is 13 megawatts. The battery is relatively small compared to the total system size. The economics make sense for us because we have a government grant for 50% of the capital cost to demonstrate that this works.

MR. MARTIN: Peter Rive of SolarCity says it costs about $5,000 to install a battery with a rooftop solar system, and the homeowner gets about $500 of that back in time-of-use arbitrage. The battery does not seem economic at the moment, yet you think within two years . . .

MR. DE PASS: I was commenting on Germany. It is hard to generalize across the globe. In places with time-of-day pricing where a homeowner can capture that arbitrage, batteries may become economical sooner than in other markets without this form of pricing.

MR. MARTIN: Thomas Plagemann, when does Vivint see itself installing batteries routinely with rooftop solar?

MR. PLAGEMANN: The economics of the battery are entirely driven by the regulatory structure and rate framework in a region. It does not make economic sense today so, as Kevin says, it is currently a customer choice. The batteries that are being marketed today for residential use are really for backup. They are not really for cycling. We will watch the market evolve. We continue to work on developing battery solutions with our vendors. We are not in the manufacturing business. We will find the best vendors to partner with and offer the solutions that customers want when it makes sense.

MR. MARTIN: When do you expect it to make sense?

MR. PLAGEMANN: It depends on what happens on the regulatory side. If batteries were $500 tomorrow, then people might buy them today as a hedge against some kind of demand charge being imposed in the future, but as long as the cost remains $5,000, it is a completely different economic question.

MR. MARTIN: So Andrew de Pass is the biggest optimist in terms of when we will start to see widespread installation of batteries, but he has a global perspective and may not see them so rapidly in the US. Kevin Smith and Thomas Plagemann, you think it will take longer.

MR. SMITH: You have to ask the question market by market. Germany has different issues certainly than the US. If Germany had residential net metering, then homeowners might be more inclined essentially to use the local utility for storage than to install a battery.

MR. MARTIN: Tristan Grimbert, some of your competitors — Duke, AES, First Wind, which is now part of SunEdison — have installed 20- or 30-megawatt batteries with wind farms. Do you see EDF going in that direction?

MR. GRIMBERT: We are already. We are building a 20-megawatt battery storage project right now in PJM, and we have more in development.

Storage is a diverse universe. We can talk about a battery bought by a residential customer all the way to a pumped storage hydroelectric project or thermal storage facility for a city that is huge in scale. I think it will be all of the above. You need to manage the grid in a way that you can provide some load-shifting equipment or load-following equipment.

The question about battery storage is the timing. The timing depends on the transition to distributed generation. Battery storage at the residential or commercial level is only viable if there is no net metering. Net metering is not viable above a certain percentage of distributed generation because it imposes a cost on the utility. Someone has to assume the storage. If distributed generation grows quickly, then we will reach the ceiling for net metering and any additional storage will have to done by the customers.

Storage will happen; there is no question about it. Whether it happens in three, four or five years depends on the market.

Residential solar is more of an equipment business. It is not a capital business. You are mostly just selling equipment, and, honestly, that is not a business in which we are really interested.

MR. MARTIN: You are installing a 20-megawatt battery currently in PJM?

MR. GRIMBERT: Correct.

MR. MARTIN: Why is that economic to do? Will you earn enough revenue from providing frequency regulation and other ancillary services to cover the cost?

MR. GRIMBERT: Yes. PJM has opened a new tariff for ancillary services, and quite a few players — you named some of them — jumped on it. We built the project. PJM does not need a lot of storage in order to be able to manage the intermittent generation on the grid, so that market reached saturation quickly. Keep in mind, the potential storage market is about a tenth of the wind capacity: rough calculation, back of the envelope, you need an order of magnitude less capacity in storage than you need in intermittency.

So, yes, storage is a market for us, and we are in it, but it is a small fraction of the potential market in terms of capital deployment as the solar or the wind market itself.

Fundamental Change?

MR. MARTIN: Will storage cause a fundamental change at some point in the power market? Is it a potential game changer?

MR. SMITH: We have a tendency on this panel to talk about all markets at the same time.

MR. MARTIN: You and Andrew de Pass are more globally focused.

MR. SMITH: Yes, and not only in terms of geography, but also focused on residential all the way to utility scale. There is no question that storage has value in load shifting and time of day. In California, the peak load is up to 8 o’clock at night. If you dump a bunch of PV into the grid in the middle of the day, you are going to have issues. Then you can go in the other direction into South Africa where the capacity margins are less than zero, so they are having blackouts, and most of the blackouts are 5 p.m. to 10 p.m. at night, and so storage is of massive value in South Africa because it will help to meet load. The Chilean market is a 24-hour-a-day market, with a lot of mining sector customers. A few merchant PV projects have been built in Chile, but you are not going to be able to compete in that market without storage.

MR. MARTIN: So storage may be a game changer, but not as much in the US? Look first to South Africa and Chile?

MR. SMITH: Battery storage in the US is more of a niche market. We believe that large-capacity storage will ultimately be required in these markets. The US is not pricing storage into the model today. In other markets, it is being priced today into the model.

MR. GRIMBERT: Keep in mind that storage is a transmission asset. The more reliable and the more structured the grid, the less you need storage. Storage is a market today in Africa. If you do not have a functioning grid, you need storage, period. The European grid is very solid; you need less storage. It can absorb up to 40% intermittency in some cases with limited issues. The US grid is not as strong because it is more spread out than the European grid.

MR. MARTIN: Will storage bring about a fundamental change in the US power market? How will it affect developers? Thomas Plagemann, for Vivint it probably accelerates growth for rooftop solar and allows customers with rooftop solar systems on their roofs to disconnect completely from the grid.

MR. PLAGEMANN: I don’t know that residential homeowners are going to start disconnecting from the grid because batteries are available.

The speed of broad adoption has to do with the rate at which intermittent renewable resources penetrate the market and create the need for some solution, whether that solution is transmission or whether it is storage, how the regulatory environment reacts to it and what kind of rate structure is imposed to compensate the players. All of these issues remain unresolved in the US market. They are what will drive the ultimate outcome.

MR. MARTIN: Will storage bring fundamental change? If so, how are you affected?

MR. GRIMBERT: No, it is not a fundamental change. It is a relatively small addition to the grid. It is one way to manage a grid. It is one of the many pillars that you need to support the grid.

MR. MARTIN: Not a game changer?

MR. GRIMBERT: It is another market.

MR. MARTIN: Kevin Smith, not a game changer?

MR. SMITH: No. The increase in storage is accelerating pretty dramatically from a small base, but it is like all these other markets. There will be continuing growth, certainly in the US and pretty dramatically in the international markets because of grid issues. It will become a bigger market over time, but it will not cause a fundamental change in the power business.

Carbon Tipping Point

MR. MARTIN: Let me take this in a different direction. Tristan Grimbert said one difference today compared to two years ago is there is a public conversation again about carbon pricing. I was thinking about how rapidly US public opinion has shifted on two issues recently: gay marriage and symbols of the Confederacy. Opinion shifted on both issues almost overnight. Bud Cherry, is there the potential for US public opinion to shift just as dramatically on carbon?

MR. CHERRY: Renewable energy has always been an area with a lot of politics. Every one of these renewable technologies has its group of advocates, and there are also opponents on the other side.

MR. MARTIN: Andrew de Pass, do you think we will see an abrupt shift in public opinion on carbon in this country?

MR. DE PASS: I do. We have to create a level playing field and simplify. When you compare the US to other markets from a regulatory and incentive standpoint, this whole tax equity thing is a nightmare. ITC and PTC: they are a nightmare for developers and operators to understand. W