Wind and Solar Valuations: Too Low, Too High or Just Right?
M&A deal volume was down about 60% in the US power sector in 2009, but it is expected to be more brisk this year driven partly by a year-end deadline to start construction of renewable energy projects to qualify for Treasury cash grants under the US economic stimulus program. Developers with too little capital to start construction of projects may be some of the prime sellers. A number of wind and solar companies with both operating assets and pipelines of projects under development are also either currently for sale or are expected to be put up for sale. At least one wind company, First Wind, tested the public equity market with an initial public offering of shares, but pulled back the offering due to poor market conditions.
Four experts from consultancies that have been advising buyers and sellers of wind and solar projects participated in an Infocast webinar in late April about whether buyers are overpaying or underpaying for such projects. The following is an edited transcript. The panelists are Ted Brandt, chief executive officer of Marathon Capital, which has run several prominent recent auctions of wind and solar portfolios, Prescott Hartshorne, vice president of Concentric Energy Advisors, Ben Jacoby, managing director of CP Energy Group, and Mike King, senior vice president of NERA Economic Consulting. The moderator is Keith Martin with Chadbourne in Washington.
MR. MARTIN: Mike King, you argue that wind and solar assets are overvalued. Why?
MR. KING: Public policy has been instrumental in making these projects profitable, but they are only profitable when one considers either the subsidies or the mandates that are placed upon utilities to buy the output from them. Few of these projects would be economic if those subsidies and mandates were to fall away. Power from them costs more than from conventional sources. If the public policy supports were to be withdrawn, the values would collapse. To the extent the prices in long-term power contracts are above market, one would expect utilities to chafe at paying such prices over time and try to find a way out of paying such prices.
MR. MARTIN: We have seen some evidence of your last point with Southern California Edison taking the position that it does not have to buy electricity under existing contracts whose price is above current market, although I think Edison has told the industry that renewable generators misunderstand its position.
MR. KING: The Los Angeles Department of Water and Power, a municipally-owned utility, is perhaps a better example where the rate path has become very significant and the utility is looking for an energy cost adjustment clause. The politics of rate increases have become so significant that the city council refused the utility any ability to raise its rates. The utility responded by refusing to pay its franchise fee to the city. This is an example of ratepayer or political backlash driving utilities to look for ways to avoid buying renewable energy at high prices.
MR. MARTIN: So what if electricity from renewables costs more today than electricity generated from fossil fuels. Do you think that is a permanent condition or do you buy the industry’s view that over time it will reach grid parity?
MR. KING: There is the larger market in which the industry competes, and there are also issues with the projects themselves. Starting with the market, new drilling techniques have dramatically increased the supply of natural gas and there is little reason to believe that gas prices will return to levels above $10 an mcf. Another market factor is electricity demand has fallen significantly but partly to a weak economy, but also to a major push by the government to promote energy efficiency. There is little reason to build new generation other than to meet the mandates of renewables themselves.
That brings us to the projects themselves. The margins in most of these projects are very thin, at least for the ones that I have evaluated and I have looked at quite a number of them. There is also a lot of technology risk. For example, many solar thermal projects are close to first-of-a-kind technology. Projected improvements in PV technology are such that if you buy today, you may regret later. There are also issues associated with resource risk. What has been observed in wind is that when wind patterns come together, they are not independent. Wind forecasts have been too optimistic. Project developers and lenders have underestimated the risk of the project themselves.
All of these factors combined can lead one to a view that some of these projects may be overvalued.
MR. MARTIN: It is very hard to predict where prices will be 10 or 20 years from now. Fuel prices go up and down. Do you buy the portfolio theory view that the greater volatility in fossil fuel prices means that utilities are better off having a mix that includes renewables? They end up paying less for electricity in the long run.
MR. KING: I agree that utilities are wise to have a mix that includes some renewables in their portfolios. It is an appropriate risk insurance. However, I also believe that these projects and these technologies will become cheaper over time as they are more are deployed. Investing today in renewables is important to drive the learning curve effect that brings down the cost of these technologies over time. That does not mean that projects being built today will see as robust economics as some people may hope for.
PPA Drives Value
MR. MARTIN: Ted Brandt, you have several large portfolios of projects in the market for sale and you are trying to get the highest price for them. How do you respond to Mike King’s critique?
MR. BRANDT: What is really driving values in the wind and solar markets are the power purchase agreements. There is very little appetite in the market for merchant projects, even though there is no variable cost in a wind or solar project. Most of the value being assigned to these projects is in the PPA.
It is not as easy as before for a developer to get a PPA for his project. A number of utilities are “full up on wind.” Others that are very much nearing capacity and cannot deal with the demand for a lot more contracts.
It is good news that the costs of wind and solar electricity are falling. There are a lot of hungry construction and balance-of-plant contractors that are bidding more and more aggressively. Current solar panel prices and turbine prices do not leave much margin for the manufacturers. These are all positive things on the cost side but, at the end of the day, the value in most of these companies is really around the power contract. Very, very late stage projects are the most likely to land contracts.
MR. MARTIN: Ben Jacoby, Mike King said that people may be overvaluing wind and solar projects because they are not taking into account the risks that public policy supports might disappear and technology might change. Ted Brandt said the value is driven by the power contracts on these projects. Where do you come out in this debate?
MR. JACOBY: I think it is important to distinguish operating projects from development-stage projects. You come to very different points on valuation and very different metrics. With operating projects, you can come to a precise value based on an after-tax weighed average cost of capital and the projected revenue stream. From my perspective, if we are talking about operating projects at a particular point in time, I do not really think of them as over valued or under valued. I think of them as valued based on current market yields.
MR. MARTIN: Prescott Hartshorne, your view?
MR. HARTSHORNE: I agree with Ben about operating projects. As for development-stage projects, there is continued demand for electricity from such projects driven by state renewable portfolio standards. Utilities are still putting out periodic solicitations for electricity from such projects, with the pricing driven to an extent by the level of alternative compliance payment that must be paid for falling short on renewables targets.
That said, there is not much value to assign to a project before it has a PPA. There is still a lot of risk that a project will not be built before it has a PPA and an interconnection agreement to allow it to connect to the grid. There is not much firmness in development pipelines.
MR. JACOBY: If the Treasury cash grant program falls away and we are back to an investment tax credit for solar or an investment credit or production tax credits for wind, there will be a significant upward adjustment in the rates of return that tax equity investors, who supply a significant of capital to this market, will require to invest. There will be a larger supply and demand imbalance than there is today. Tax equity is in short supply.
MR. MARTIN: And as a consequence, people would pay less for projects?
MR. JACOBY: Yes.
MR. MARTIN: Ted Brandt, what effect do you see falling natural gas prices having on valuations in the auctions that have you have been running?
MR. BRANDT: A significant effect, particularly if the project expects to have a significant merchant tail after the power contract ends. Most bidders appear to be assuming gas prices of $3.50 an mcf for as far as we can see. Wind has always competed with gas, but the argument the last number of years has been high volatility and high prices made wind look good. We now have wind competing with wind and now the whole class competing with gas around the presumption that we will have an unlimited supply of $3.50 gas and there id no question it will put huge pressure not only on electricity price forecasts but also on what utilities are prepared to pay for contracted power.
MR. MARTIN: Are people dropping out of auctions because of this or are they simply bidding lower numbers?
MR. BRANDT: They are bidding lower numbers. We are seeing more utilities that want to fulfill their obligations to supply a certain percentage of their electricity from renewables by owning the projects themselves. This is making the IPP model that we have had in this country since the late 1970’s more challenging.
MR. KING: Utilities look at these PPAs as liabilities on their balance sheets. This is another source of pressure for them to own projects directly rather than sign long-term PPAs to buy the electricity.
MR. MARTIN: Let me get to the bottom line. Is there a way to say what is the price today for a contracted project? Let’s say it has just been built and has just commenced commercial operation. How much are people willing to pay for that project per megawatt of installed capacity? Can anyone give a range?
MR. JACOBY: I think you can give a range in terms of weighted cost of capital.
For wind, what we see typically in this market is around 8.5% after tax through year 20. Look at your contracted revenue, which might include a forward sales contact for renewable energy credits, but would not include any revenue that is not contacted, put in your tax assumptions, and discount back the contracted revenue stream at an 8.5% rate.
MR. MARTIN: What do you do about the residual?
MR. JACOBY: In our experience, most bidders assume a zero residual.
MR. MARTIN: Does it matter whether it is already operating or just about to start construction?
MR. JACOBY: No, but if it is already operating, that means that it has already been financed, and that allows for greater precision in terms of cost of capital in the calculation.
MR. MARTIN: Where is that leading today in terms of price per megawatt of installed capacity for a typical project?
MR. JACOBY: From what we see, wind is in the low $2 million range per megawatt, but the price varies by region. The value is the spread of the after-tax cash flow over the bare cost to construct cost.
MR. MARTIN: Any other thoughts on what values buyers are placing on these projects in the current market?
MR. BRANDT: Our experience may be a little different. We always try to tell buyers that the cost of capital is 8.5%, but most buyers have been pushing back and have been thinking that the cost of capital, particularly when you throw in efficient tax equity, has been a bit higher than that. That said, costs have been coming down. They are probably down 10% in terms of the actual cost to construct a project. All of that does not translate into the bottom line given the way the investment credit or Treasury cash grant and depreciation work, but it is still a help.
Our experience has been most projects are bid around 9.5% to 10% unleveraged after-tax rates of return, and the difference between cost of capital of 8.5% to 9% tends to be between $75,000 and $200,000 per megawatt, exclusive of what it actually costs to build the project. That value tends to be available to developers reasonably efficiently in the market from a number of pretty hungry buyers that either are long turbines or short projects.
There has been clearly been a big preference in the market for projects that qualify for Treasury cash grants.
The payments tend to come partly at closing — reimbursement of costs and some of the developer fee at closing — with the balance being paid at the end of construction.
Solar is different because there has been so much movement on both power prices and panel prices. Our view there is that the range is as low as $75,000 a megawatt and as high as $300,000, depending on the profitability of the deal.
MR. JACOBY: Which in part has something to do with the quality of the resource.
MR. BRANDT: The quality of the resource, the power price, the scale of the deal, the types of panels.
MR. MARTIN: These are prices for contracted assets?
MR. BRANDT: Correct. I would not say that there is zero value for merchant assets, particularly in constrained areas where somebody has a wide-open transmission line or there are very strong solar or a wind resources. There is still a significant amount of value that the market will assign, albeit back-loaded. However, generally speaking, the market today turns on contracted assets.
MR. MARTIN: Is any value being assigned to projects that are under development but are not expected to be completed until after 2011?
MR. BRANDT: There is some value, but it tends to be contingent, back-ended and significantly less than where we were in 2006 and 2007 when there was an expectation that we were going to be the next Germany or Spain.
MR. MARTIN: So if pipeline assets — projects that are merely under development — get sold, it will be for some form of earn out as opposed to an up-front agreement on the value of such assets?
MR. BRANDT: That’s right. The general way that these deals are getting done today is reimbursement of hard expenses, some premium largely justified by the contracted assets where there is a clear path to construction or the projects have already been constructed, and that tends to be on a hard number calculating by discounting contracted revenue, and then there is some additional value, both upfront and generally contingent, that gets paid to shareholders and management teams based upon what actually gets done over the next three, four or five years.
MR. MARTIN: Prescott Hartshorne, Senators Kerry and Lieberman are angling to have a carbon control bill taken up by the Senate this summer. What effect do you see enactment of carbon controls or a national energy standard having on valuations or has the market already taken the possibility of such measures into account?
MR. HARTSHORNE: I don’t foresee an RES having a large incremental value over the existing renewable portfolio standards at the state level. The primary reason for that is the states most affected by a national standard are those in the southeast. The remaining states would still be governed by RPS programs at the state level. Those programs have some headroom remaining, but it has already been factored into pricing.
MR. MARTIN: What happens if goes Congress moves forward on carbon, about which I think a lot of people are skeptical at the moment. If it does, do you see a big boost to valuations?
MR. HARTSHORNE: Not a large boost to valuation. I think if it happened this year, it would be a big surprise, but one leading to just a small uptick.
MR. KING: Our modeling suggests that a US carbon regime would not cause an increase in the amount of renewable energy overall beyond the bit you see from the current renewable portfolio programs at the state level. Absent significantly more stringent carbon regulation that we have seen in the versions of bills that have been proposed to date, we do not see much upside from passing carbon other than to cause natural gas prices and the costs of electricity from gas-fired power plants to rise somewhat modestly.
MR. MARTIN: Ted Brandt, suppose you are looking at investing equity in a wind developer with just a pipeline of projects. You said people are not ascribing much value to pipelines, certainly not for projects that will not be completed by the end next year. How do you decide how much of a company you should receive in exchange for agreeing to put in capital in the future to build such projects?
MR. BRANDT: It depends on who is making the valuation. A European developer with a successful portfolio of assets in Europe who is seeking an American partner may have a less predatory view than a financial player. A financial player would focus on how much money has been spent and how much value created. I would never say there is no value in development rights where someone has measured the wind, controlled the land and has begun transmission studies. Generally, the market will reimburse some measure of cost plus a premium on top of that, but a strategic investor would tend to assign a greater value to the development work. A pre-construction value would be established, a new money commitment would be given and the math would lead to x percentage of the company for the investor.
The dilution a lot of times will occur at the project level as opposed to the holdco level.
Interest in Solar
MR. MARTIN: Moving to solar, most activity in the solar market lately has been rooftop solar PV installations. There has been some utility-scale PV. There are some huge solar thermal projects that will come to market later. Have you seen much consolidation of solar companies or sales of projects? Ted Brandt, I think you said you have two portfolios in the market.
MR. BRANDT: It is interesting to contrast solar to wind where there has been consolidation. The solar business has resisted consolidation. There are still lots of new startups appearing in the market. They struggle to find scale. There are a number of well-funded IPPs and utilities who are trawling the market looking for solar companies to consolidate and bring into some kind of scale. By and large, the solar developers have not been interested in being acquired. Meanwhile, the financial players have not been particularly interested in the sector and those that were interested seem to be exiting.
MR. JACOBY: Wind and solar are different products. Solar is distributed generation. The regulated utilities already have access to the customers. For example, Southern California Edison is looking at very large programs to deploy solar to those customers. The problem for financial investors is when you are talking about distributed generation, the bite-size is often too small. You typically need to have the financing commitment in place before the orders can be secured, and there is a whole credit analysis and administration of the credits that is much more cumbersome than for utility-scale projects.
MR. KING: Rooftop PV is much more expensive than utility-scale PV. That has to do with the economies of scale, the issues associated with putting solar panels on rooftops even if the roofs are over large warehouses. There are also issues about ownership of the PV systems, the attachment to property that someone else owns. It is a lot more difficult to do distributed-type PV projects as opposed to large-scale utility PV projects.
MR. BRANDT: We have seen some pretty nice margins in the distributed generation market. You are dealing with a small scale, but the electricity is sold into the retail market at a substantially higher price than the wholesale prices charged in a utility-scale project. This can make a huge difference in value.
MR. MARTIN: So that margin is also a developer’s profit. What would you say is a profit in this market?
MR. JACOBY: The point is distributed generation, particularly at the residential level, is complex. It is costly to deploy, but the residential market is a very large market. It is much, much larger than the utility-scale market will ever be for solar when taken in the aggregate. The issue is how do you best attack that, and it seems that in the long-run, the best parties to tackle that market are the regulated utilities that already have homeowner credit risk. In a place like California where the top-tier retail electricity rate is $470 a megawatt hour, deploying rooftop solar clearly makes sense.
MR. MARTIN: What’s different about valuing a wind farm or wind company versus a solar project or solar company?
MR. HARTSHORNE: Start with the primary technical differences. Wind and solar are very obviously different technologies, and you need to understand the operating and technology risks. Moving to the company level, distributed solar requires a good sales force and good contracting capabilities because you are doing the same small deal over and over again.
MR. BRANDT: A wind farm has an exponentially larger number of moving parts compared to a solar PV project. There is a general belief that what is in the pro forma for a solar project is more defensible than what has been in pro formas for wind projects, given recent operating history with wind farms and the gap between forecasted output and what has actually been produced. The wind forecasts have been too optimistic.
Solar thermal has its own challenges. You are talking about scaling something up to levels at which it has not been scaled previously.
MR. JACOBY: One of the challenges with solar thermal is you need a much longer forward commitment from the investors than you do for solar PV because you are talking about specialized equipment, a longer development cycle and a longer construction cycle.
Returning to solar PV and differences in valuations, if you look at the financing available for solar PV, it is cheaper than for wind in part due to less variability in the resource and in part due to the fact that total operating expenses are much, much less as a percentage of gross revenue for a solar PV project than for a wind project, and that means you have much less variability in cash flow.
Recent Movement in Prices
MR. MARTIN: Ted Brandt, what direction have prices been moving in auctions of wind farms over the past year?
MR. BRANDT: Slightly up, but still down substantially from where they were before the financial meltdown. We are now starting to see buyers assign some value to early- and mid-stage assets as opposed to zero. There is still a reasonable bid-and-ask spread between what buyers are saying they are prepared to pay and what sellers think their projects are worth, but the spread is narrowing and is much tighter than it was six months ago.
MR. MARTIN: When you say significantly down, are prices down 30%, 40% from before the Lehman collapse?
MR. BRANDT: You are talking to a guy that made his living on selling distressed assets last year, so I don’t think it was quite 30%. If we could sell a wind project that everybody would agree could be defensibly sold on a P50 pro forma and that was selling at an 8.5% to 9% after-tax unleveraged yield before Lehman collapsed, I would say last year we were seeing more like 11%, particularly production tax credit deals because there was such a limited audience. Yields for Treasury cash grant deals clearly have come back down, but I think I think such projects are still trading at higher than 8.5%.
MR. MARTIN: What about solar — same trend?
MR. BRANDT: Solar has really interesting dynamics in that the cost of delivering solar electricity is hitting new lows all the time. I am not sure whether it is achievable, but people are talking about installed costs of $3.50 on a fully delivered per watt basis. You can make a power purchase agreement at $140 or $150 a megawatt hour work in California at that price. There has been a move toward volume ground-mounted systems. They are more interesting to large investors than rooftop.
MR. JACOBY: We see about a 50 basis point reduction in the cost of capital for utility-scale PV compared to wind.
MR. MARTIN: So people are assuming a lower cost of capital for utility-scale PV?
MR. BRANDT: Certainly lenders are.
MR. JACOBY: You can get longer lender debt. You can get a lower coverage ratio because, on a comparative basis, the lack of variability in revenue as compared to wind and the tax equity would slightly be cheaper.
MR. KING: I wonder how much this is just an issue of lender experience and that as these projects get a few years of operating history, and the lenders will start to see what the real issues are then they may reassess risk.
MR. MARTIN: You have been the bear in this discussion. Reassess the risk — move it upward or downward?
MR. KING: Upward.
MR. JACOBY: The variability in the solar resource has been less than for wind. If you talk about the desert southwest, moving from a P50 to P90 case is a 5% swing in output. Moving from a P50 to P90 for a wind farm is more like a 25% to 30% swing.
MR. KING: That’s true but, just as in wind we had an issue where people thought that the draws from the wind distribution were independent and they are not, we know that there are cycles in weather and cloud cover that so while solar output may be less variable, whatever variability there is may come as a downside at once and affect the project pretty negatively. The other issue is water. You have to have a substantial amount of water to clean the solar panels and the scarcity of water, the price of water and the availability of water may significantly affect these projects going forward. There are risks tied to the immaturity of the projects. As we get more experience, people will reassess risk.