Will there be a rush in the United States to start construction of new wind, geothermal, biomass and other renewable energy projects by year end in order to qualify for expiring tax subsidies? Growth in demand in electricity has slowed to just 0.7% a year. Contracted electricity prices for wind projects have fallen in some states to less than $30 a megawatt hour, but are the low prices making utilities more interested in buying long term? Many developers were keen the last three years to get as much output as possible under contract, but are they now keener to retain the potential upside if prices increase? Do low returns and low load growth still justify investment in the US or are the best opportunities in places like Latin America where prices for contracted power can be $200 or more a megawatt hour?
A panel discussed these are other questions at the 24th annual global energy and finance conference that Chadbourne hosted in June in California. The panelists are Gabriel Alonso, CEO of EDP Renewables North America, Tristan Grimbert, CEO of EDF Renewable Energy, Carlos Domenech, president of SunEdison, Christopher Hunt, managing director of Riverstone Holdings, the parent company of Pattern Energy, and Kevin Smith, CEO of SolarReserve. The panel was moderated by Evelyn Lim with Chadbourne in Los Angeles and Keith Martin with Chadbourne in Washington.
MS. LIM: Gabriel Alonso, will there be a rush at the end of 2013 to start construction of new wind farms to qualify for tax credits?
MR. ALONSO: Yes. If we look at the history the wind industry, there are clear boom-and-bust cycles. We have been here before, and we know how the industry behaves in these situations. We are hoping to cover our 2014 to 2015 business plan growth by starting construction of all 2014 and 2015 projects by the end of the year. I expect other wind companies will be trying to do the same thing.
MS. LIM: Tristan Grimbert, what else do you take into consideration, besides a desire to qualify for tax credits, when deciding whether to try to start construction this year?
MR. GRIMBERT: Ideally we would like an offtaker for the electricity. It may be possible to start construction with just a hedge that provides a floor under the electricity price. It takes longer to secure a power purchase agreement than to put in place a hedge.
MS. LIM: Chris Hunt, as a private equity investor, how willing are you to start construction of projects to take advantage of tax subsidies if there are no offtake agreements?
MR. HUNT: We are always willing to invest money if we see a return. The big question is whether the return will be there. I do not see as big a rush as some of my colleagues do. The rush at year end will be muted for two reasons. First, a lot of the utilities that were prepared to enter into long-term power purchase agreements did it in 2011 and 2012, and there will not be as many new PPAs in 2013 as there have been in the past. Second, the bigger players are just not as active in new wind development as they have been in the past. The question is then whether that will create opportunities for guys like me. There is plenty of private equity money available for investment. I think there is a shortage of projects that fit the criteria by which we invest.
MR. MARTIN: Carlos Domenech, how easy or hard is it to get a power contract today in the US market?
MR. DOMENECH: It is not easy in the utility-scale market. The market is highly saturated. We do not develop greenfield projects at the utility scale because there are plenty of quality projects to buy. We are a very aggressive buyer of companies, projects and portfolios and there are many companies that are willing to sell themselves or their development pipelines. The challenge is visibility and predictability around interconnection on the utility side. You might have a power contract, but it is subject to a utility building the intertie needed to connect the project to the grid by a certain deadline, and we see slippage on the utility side. That casts a cloud over the PPA.
MR. MARTIN: Kevin Smith, what is your experience in the US market trying to secure long-term power contracts?
MR. SMITH: The big rush was last year. Contract prices have been driven down largely because of low natural gas prices. That is hurting both the wind and solar sectors. Some companies are willing to go into construction with short-term hedges and worry about power contracts later. We cannot do that. We will see a bit of a rush, but we will not see what we have seen in previous years when programs expired.
US Versus Foreign Markets
MR. MARTIN: Chris Hunt, a Spanish solar company that visited our office in Washington last fall said that the US market no longer produces high enough returns. The company is no longer interested in doing solar projects in the United States and is looking mainly at Africa and Latin America. You sit in London and see the whole globe. Is the US now a poor market for renewables?
MR. HUNT: Foreign companies are at a disadvantage when doing business in the United States. Repatriation and other tax issues make it more challenging for foreigners to compete here. The industry is tough regardless of where you are. I would not say that Europe or Latin America or Africa is risk free.
I think there are good projects in Europe. The European market bifurcates between northern and southern Europe, and northern is probably a safer, more stable place than southern to invest right now. That said, there are perfectly valid projects to pursue in southern Europe. We are actively building wind and solar in those markets.
We are building projects in Chile where it is possible to earn decent returns.
A lot of people have been turned off by Africa. We have not chosen to pursue projects there for a number of reasons. It is a market that if you got in early and made some of the early-stage rounds, you may have been able to earn decent returns and find some decent projects, but it took a fair amount of risk to get them.
MS. LIM: Are there areas outside the United States where the spot market prices for electricity are high enough that you do not need a long-term contract to build a project? Are you finding opportunities to supply power directly to industrials inside or outside the US?
MR. GRIMBERT: The safest investment anywhere remains a wind farm in the US with the 20-year power purchase agreement.
European governments have been looking at budget deficits and cutting subsidies for renewable energy. A project with a 20-year PPA is a safe investment. It does not have to be in the United States. You can enter into 20-year PPA in Brazil, and South Africa is also a good investment. However, there is currency risk in cross-border projects. How can you rely on Brazilian reais or, if you are a European company, on the dollar-versus-euro exchange rate?
The beauty of a 20-year PPA, if you are a disciplined operator, is that even if you believe the contracted electricity price is low, the project will have a merchant tail when you can sell at full market prices.
MS. LIM: What do you do during a period like today when it is hard to get a 20-year PPA in the United States?
MR. ALONSO: It is hard, but not impossible, to find a PPA. Xcel is actively reacting to the extension of production tax credits, and there are other utilities that are also looking to enter into long-term PPAs. Now more than ever, utilities are looking for different structures. They are expecting developers to take the intermittency risk around wind. They are open to PPAs with developers whose projects are one or more states away.
There are opportunities in states like Kansas or Oklahoma where utilities are looking to enter into PPAs beyond what they are required to do under state renewable portfolio standards because electricity prices are low and the public utility commission is willing to allow prices under those long-term contracts to be passed through to ratepayers. We are seeing more industrials willing to sign long-term power purchase agreements. The industrials are not a big game changer at this point, but I hope it is the start of something that will really drive demand for our industry.
MR. DOMENECH: A lot of the recent growth in the US market has been in distributed solar. We also manufacture solar panels, and we announced a 40¢-per-watt panel with around 19% efficiency that is competitive even in Chinese terms. I would not expect a private equity fund to be able to compete in that market with tax equity as an alternative source of financing at 6 3/4% or 7%.
Frankly, we are really excited about the international market. Our goal is to have 50% US and 50% global projects. Global PPAs are a phenomenal market with great returns. In the US, non-utility-scale PPAs are really high growth for us and also have great returns.
MR. SMITH: There is a difference between your market sector, which is more residential and large commercial, versus the very large utility-scale projects. There was a big rush into large solar projects with the DOE loan guarantee program and section 1603 Treasury grants. I do not think we will see many big projects in the US solar market now that those programs are winding down.
We have a 150-megawatt power contract for our Rice project in California. We are trying to get it into construction early next year. We are in financing now. We moved overseas a few years ago. We are still active in the US market, and we just committed to a project in Arizona. Including PV and solar thermal, we have 250 megawatts under construction in South Africa. We use a developer’s model, which is that we lead the development activities, take the development risk and bring in other, largely local equity players, although Google came into our most recent deal that we closed in late May in South Africa.
We see a lot of growth in the international markets such as Saudi Arabia and Chile. We are doing things in Australia. The fact that we combine storage with solar thermal is even allowing us to engage in China. We would love to do more in the US, but in an age of 8¢ power contracts, we do not think the returns work.
If you look at all the bids in the last 12 months in California, you are lucky to be able to supply electricity at a 6% return. Such low returns will not work for the equity investors that we can find in the market. It will be interesting to see how many developers holding power contracts in California will walk away from them without building the projects.
MR. GRIMBERT: Six percent is on the high side of where some of these power contracts are being bid. Some bids in recent rounds in California were 6¢ and below. Solar companies, desperate to secure power contracts in a hard market, are underbidding each other. It happened in the wind sector. I have been in the US market for 10 years, and you have this underbidding and consolidation cycle. We are in such a cycle for solar today.
Current PPA Prices
MR. MARTIN: If solar developers are being offered 6¢ to 8¢ a kilowatt hour and earning only 6% returns, what are the current prices in the wind market for electricity and what are the returns?
MR. GRIMBERT: Too low. We are below 3¢ in the central Plains, but production tax credits add another 2.3¢ after taxes. It is a head-to-head competition in California between wind and solar, and solar is winning most of the bids.
When I was talking about a rush at year end to start construction of additional wind farms, it will be a rush to find enough equipment for delivery by year end in a market where turbine manufacturing capacity has shrunk. The size of the market has contracted. There will be a rush within that smaller market.
The key question for US developers is what is the return and how does it compare to what could be earned by deploying the same capital outside the US. The returns in the US are pretty tight, but as Gabriel Alonso said, this is a secure market with lower risk. Success is building a project that adds value. There used to be 350 gigawatts of wind in the pipeline a year ago with a build out expected of five to 10 gigawatts a year. That was 50 years of inventory. Now we have 150 gigawatts in the wind pipeline. That is about 20 years of inventory.
We have to think differently, whether it is taking some transmission rights risk or putting in storage or even developing in a difficult area. There are still very interesting projects, but you have to find them. The good news is that the pool has shrunk and a lot of players have pulled out. Some have gone bankrupt. There is still a way for the strongest to survive.
MR. HUNT: I fully agree. The phrase commodity wind or commodity solar is a good one because if you just stick to a project that anybody could do or anybody could bid, you will have a terrible return. The way to make money is to look at a project that has some differentiation.
If I were to look at the range of power prices in our current stable of power purchase agreements, there is an eightfold differentiation between the lowest and highest price. Obviously, you want to focus on the higher priced contracts. The key is to stick to fundamentals: find the best located project, the best resource, the best PPA and, if nothing good presents itself, wait. Right now, we sit on a lot of projects, and we will wait until there is a better contracting environment. In the meantime, we will continue to look for other projects. If you get lured into a commodity wind or commodity solar project, then you will get lured into an unexciting return.
MR. MARTIN: Gabriel Alonso, like many other wind companies, you have been dabbling in solar. Is that a sign that wind is not the best place to be at the moment?
MR. ALONSO: For us, wind is a better place to be. We have been looking at solar, but it is race to the bottom. The solar market is much stronger, but also much harder than what we are seeing in wind. We are late to solar, so I would not call solar an attractive space.
We did not see PV coming. We were more involved with CSP five years ago in the belief that it would be the winning technology. What we are seeing is that there are some utilities that are late to the space. They are very aggressively buying solar projects, more than wind, because they have ability currently or expect to have the ability in the future to use the investment tax credits on such projects. We do not have that ability. They feel more comfortable with the operational risks of solar versus wind so that we cannot compete. Our true equity cost is similar to theirs, but when you take into account that they can get full value for the tax subsidies on solar projects while we lose part of the benefit by having to monetize the tax subsidies, we cannot compete with them.
MR. HUNT: We have a different technology. We have storage technology that can run 24 hours a day as a non-intermittent supply. The problem in the US is that while the utilities say they love storage, no one is willing to pay a premium for storage. We are seeing international markets demand storage that don’t have quite the robust transmission system we have here in the United States. Differentiated projects in the US are really few and far between. We have a very differentiated product, but the US market is not assigning value to it right now.
MS. LIM: We understand that Puerto Rican utilities are asking for storage in connection with bids to sell electricity. How are you approaching storage and the demand by utilities to smooth out intermittency?
MR. DOMENECH: We were the first company to contract with the largest Chilean mining company, COCAM, for a 100-megawatt power contract. Chile has an issue because Argentina decided to stop sending gas to Chile; it is exporting all gas to Asia. The cost of gas is way above the cost of solar, so it creates an opportunity. We can deploy solar alongside gas and create a synthetic PPA that allows mines to lower their overall cost of energy.
Our core storage solution is molten salt storage. We are building our lead project in Nevada and have an extensive overseas portfolio. We are looking at both large-scale solar PV and solar thermal. Storage for PV is more difficult. There are some markets where there are clear requirements for storage. The mining sector is looking for electricity 24 hours a day and seven days a week. We are looking at combining solar thermal or PV and with backup diesel generators.
MR. HUNT: The storage market has been frustrating for me. I would love to do an electricity storage project. I have danced around and looked at projects over the last four or five years and have not found anything yet in which to invest. There are several reasons why.
First, the market in the US simply does not value constant power the way it should, and I cannot explain why. Solar electricity from a CPV project has a monumentally higher value than electricity from a PV project.
Second, in a period of low gas prices, it is easier for other types of generation to provide ancillary services cheaply.
Third, just as solar panel prices have plummeted, the cost of batteries is also falling. This brings the day closer when batteries can be added economically to wind and solar projects.
Fourth, I see storage as not so much an issue for solar as for wind. When you are able to sell solar during a peak period, you get a good price. It is hard to justify diverting solar kilowatt hours to storage when you can get a good price by selling directly to the grid. If you can charge a battery in the middle of the night with wind when power is virtually free, it makes more sense.
MS. LIM: Tristan Grimbert and Gabriel Alonso, have you been considering storage for your wind projects?
MR. GRIMBERT: Yes. The key question is whether to add storage at the project or the utility level.
We have been focusing mostly on the project level, and there are some wind projects where it makes sense. With wind, you get more bang for your buck at the project level.
It is very difficult today to justify solar storage at the project level. With solar, we have to look at storage at the utility level. The utilities are best equipped to balance their needs.
MR. ALONSO: I have to be frank; we are not considering storage. We have looked at storage, but the wholesale markets in the US are not favoring storage. They are solely focused on electricity prices. There are utilities asking us to deliver a product that is not intermittent, but they are not willing to pay enough for it to justify storage.
MR. DOMENECH: There are a few exceptions to that in the US. The pricing structure in California is based on time of day, so the California peak market is paying two to three times what you will get off peak, and the peak period in California is 1 p.m. to 8 p.m., so utilities will pay 15¢ per kilowatt hour during summer on peak hours and 4¢ to 5¢ for off-peak energy. Time-of-day pricing has happened very slowly over time, and we expect to see more.
The utility in Nevada is pushing our project in that state into the evening hours because that is when it reaches peak load, but there is no payout for that.
Time-of-day pricing is showing up in some of the international markets such as South Africa in the third round. Their solar thermal bids have time-of-day pricing, which is an interesting development.
MR. MARTIN: What is the current wait time for wind turbines? Have turbine prices stabilized? Do you see yourself placing another large order this year?
MR. ALONSO: Turbine prices are going down. However, we do not see a consistent behavior. Some turbine suppliers do not expect a large rush at year end in the US, so they are rushing to be the first ones to book orders for what they expect will be a small number of new turbine orders. Some others believe there is a rush coming, so they are in no hurry to sell turbines quickly or cheaply.
The larger trend is for the marginal price of turbines to keep falling as the technology keeps improving, so the cost of wind energy is coming down. How much of that do I keep for myself? Zero, because it is a market in which wind companies are racing to the bottom to secure scarce power contracts. If I can do something more special on the structures to sell the electricity, maybe I can keep a good amount of that upside, but in a commodity wind scenario, it is not something that I can keep.
We will not be placing a large order without offtake contracts behind it.
MR. HUNT: You are seeing the wind market bifurcate a bit. It is fairly clear there are too many wind turbine manufacturers in the world. Some will survive and some will fail. You are going to see a lot more price cutting by those who are less likely to survive. The tough decision wind companies must make is whether go for the lowest price when there is greater risk that the vendor will not be around in 10 or 15 years.
MR. MARTIN: There was only one Chinese turbine vendor at the global windpower convention in Chicago in May. What do you make of that?
MR. GRIMBERT: I think they are busy at home, and they do not see the US market being as interesting as it used to be. This is because, while there may be a year-end rush, there is no growth. I am not sure I agree with Chris Hunt, but I agree with Gabriel Alonso that the price keeps trending down because there is competition with half a dozen first-tier vendors. The good news is that we see the turbine prices trending down even among the survivors. It is going in the right direction, and we already placed one order for North America since the beginning of the year, and we will place more before the end of the year.
MR. MARTIN: Is that ahead of having power contracts for projects?
MR. GRIMBERT: No.
MR. ALONSO: This is a technology market, unlike the solar space. Solar panels are a commodity. I am sure the panel manufacturers are trying to change that dynamic. The wind industry has always understood that the Chinese were coming, and there was a rush to develop new technologies that would keep the US and European turbines two steps ahead of the Chinese, and that dynamic has been fundamental to get to the cheap PPA prices we have seen here. The other problem that the Chinese turbine suppliers have is that they thought they could run their businesses from China and do business in the US, and that is a big mistake.
The section 1603 program was an opportunity for Chinese vendors to deploy their own equipment in projects they were developing for their own accounts, and build a track record without the need for external financing. They did not take advantage of that window. The first question US wind companies ask is whether they can finance a particular turbine. If the turbine has no track record in the US, the answer is pretty much no. That makes the barriers to entry in the US market pretty daunting.
MR. MARTIN: Kevin Smith, what does a PV project cost per installed megawatt? What does a CSP project cost? When do you see the gap closing between solar and wind and natural gas?
MR. SMITH: I will give you the answer on the PV side. We do not like to talk dollars per megawatt with CSP because such projects operate at a much higher capacity factor, meaning dollars per megawatt are not a good basis for comparison. A CSP facility will generate two times more output than a PV facility. Our 110-megawatt CSP facility in Nevada will make 500,000 megawatt hours a year. A PV facility of that size will make half that.
On the PV side, we are active in the US even though the PPA market is very difficult. Overseas, solar panels are being offered at prices as low as 40¢ a watt. In the US, panel prices dropped into the 50¢-per-watt range for a while, and now we are seeing them trend up into the low 60¢ range. The question is whether the trend will remain up. If there are some 40¢ panels entering the market, then that is good news. We are a price taker on the panel side.
We have heard all-in prices between $1.20 a watt and $1.70 a watt for utility-scale PV projects. That is pretty competitive, but it does not really support power contracts at 6¢ or less a kilowatt hour. It is a dynamic market. There will be a lot of panel manfacturers who will not survive.
MR. DOMENECH: I was just checking the math, and I do not agree with what has been said about PV being a commodity. We sold SunEdison to MEMC, which is a semiconductor company. The good thing about the semiconductor folks is that they have worked for five decades to perfect the art of making high-efficiency wafers. The reason that we can get to 40¢ a watt is because we have a production process for polysilicon that the Chinese cannot match. We are the only remaining company today that can produce silicon. We have a joint venture with Samsung to deploy even more capital in that effort. We are projecting a levelized cost of energy of 7¢. You do not have to think too far out to see where things are going in terms of solar and what it means for the industry. We are excited.
MR. HUNT: I think you’ll see a two-stage adjustment in pricing on solar. People are selling at zero or negative margin, so that will correct when competition levels out. It is not hard to believe that through procurement, technology, efficiency and building cost, you can drive down the numbers. I expect that we will do better than 40¢ a watt.
MR. ALONSO: If the market is currently at 60¢ a watt and you expect it to go to 40¢ a watt, why would you buy any panels today?
MR. DOMENECH: I said that by 2016, we will be able to do 40¢ a watt. If a developer has a power contract for which it has to build today, it comes down to a question of profit margin. I cannot speak for people bidding to supply power at 6¢ a kilowatt hour. We have done a thousand projects, and we will do close to 500 megawatts this year and 750 megawatts next year. Our gross profit margins are in the 20% range. I know what works for us.
Today when we bid, it is really important to get into the details. It is true that there is a race to the bottom in the US when bidding into utility procurements. In almost half the situations that we see, the winning bidder bid too low a price to build the project. Someone else then came in and renegotiated the contract with the utility at a price that was economic. It happens all the time because the utilities have to satisfy state renewable portfolio standards that require they deliver a certain percentage of electricity from renewable sources.
We have not talked about it yet, but as we get into 2016 and the investment tax credit for solar drops at year end 2016 from 30% to 10% and some of the utilities are way behind where what they need to be to satisfy state RPS requirements, there will be a chaotic effort to secure additional capacity. Anyone who is long in capacity should be in a good position to arbitrage what he has and increase his profit margin.
MR. ALONSO: Then I should be bidding at 50¢ a watt and not 40¢ in 2016 since demand for solar equipment will increase, potentially driving up equipment prices.
MR. DOMENECH: I think you should sit on your current hand. You have to be patient. Why hasn’t SunEdison built out its three gigawatts of solar pipeline? Why should it? We are arbitraging on the right time.
MR. ALONSO: I am concerned that it is a very crowded market in terms of numbers of solar developers, and this will continue to drive down PPA prices to levels that make the projects uneconomic.
MR. SMITH: That is one of the difficulties. The equipment side of wind is a lot more stable than on the PV side. We purchased 96 megawatts of solar panels from Yingli for our solar project in South Africa, and we had to insure the PV supply. You are going to see that a lot. There is clearly a top tier among PV suppliers, but even they are struggling, and you are going to see some of them fail.
MR. DOMENECH: We will sell you panels.
MR. SMITH: I am happy to buy them at 40¢ a watt all day long, but I don’t want to wait until 2016.
MR. GRIMBERT: When I was talking about wind being a commodity business, I was talking about the manufacturing side.
As developers, we are in a cost-plus business. It is a race to the bottom in bidding into utility procurements. That’s why there is not a lot of money in solar for developers. The big procurement season is over for solar in the US for a little while. The key to success has been to be either clever enough or dumb enough to forecast where the costs are headed. The fact that SunEdison is vertically integrated gives it an advantage. It is much more difficult for the rest of us to predict future costs. The differentiating factor for those who make money in this business has either been to be lucky or very clever. It is that rather than the ability to develop.