The California utilities are putting out requests for proposals, but they do not need the electricity until 2019 or 2020 and are asking for power purchase agreements of only 10 years. Solar, wind, geothermal and biomass projects must be in service well before then to qualify for large federal tax credits. For example, solar projects must be in service by December 2016 to qualify for a 30% investment tax credit. Is there a way to bridge the gap so that a project has enough revenue, while waiting to start sales under the power purchase agreement, to be financed?
A panel talked about various ideas at the Infocast utility-scale solar summit in San Diego in late September. The panelists are William Cannon, vice president of Sumitomo Corporation of America, an equity investor in projects, Arleen Spangler, a principal at The Carlyle Group, a project lender, and Arlin Travis, an independent consultant with 25 years of experience in electricity trading. The moderator is Keith Martin with Chadbourne in Washington.
MR. MARTIN: We need to have a project operating in 2016, but the utility is not ready to take the output until 2019 or 2020. Arlin Travis, you said there is a solution to this problem of how to earn some revenue in the meantime to allow the project to be financed. It is a financial hedge. It does not exist yet. Describe what the market needs to do.
Hedged Spot Sales
MR. TRAVIS: We need to think about 2014. Are there deals we can close in 2014 for a start of 2015? If we can do a 2015 start, then we can clearly do a 2016 start.
You have to connect to an ISO so that the project is in a position to sell into the day-ahead market, and then you have something that we can write a swap against. When we were writing swaps for wind farms, we were writing them on a P90 or a P95 output case. What that meant was that if we had a 90% or 95% probability that the wind farm would produce this amount or more of energy in a given month, then we could write a swap against it, and those swaps got financed. You need a liquid market for the electricity before you can write a swap.
You could write a swap today against the California ISO. It trades two years forward, which means you could probably do a stack and roll to get yourself a four-year energy hedge. Is it going to be brilliant? Are you going to love the amount of money you make? No. But it is something that will be part of your financing package along with monetizing the tax credit.
MR. MARTIN: So the key is to make spot sales. Someone will write a swap to bet on what the minimum price will be in the spot market. You think that a two-year swap is the farthest the market will go in California, but you can get to four years by doing stack and roll. What is a stack and roll?
MR. TRAVIS: A stack means that I take the amount of energy that the project is expected to generate over four years, and I hedge the front two because that is the tradable portion of the curve. Then I keep rolling my hedge forward under the theory that the third year is going to trade in relation to the second year, and the fourth year will trade in relation to the third year.
MR. MARTIN: But the price that the hedge or swap sets is effectively reset after the two-year period, correct?
MR. TRAVIS: I don’t think you have to do that. When we were writing wind hedges on California projects, we did not require the wind farm owner to be exposed to that price risk.
We need some new entities in the marketplace to step forward and start writing these types of contracts. The risk exposure is part of the reason why these institutions do not exist today. The banks are in flux right now. The Federal Reserve Board is considering to what extent bank holding companies can trade commodities. The banks have their heads pulled in like turtles, and are waiting for things to clear up.
MR. CANNON: I agree that the only realistic way to go forward would be to enter into a hedge with a financial institution or some other entity that is willing to provide such a hedge. I am bullish in believing you could probably get a four-year hedge. The concern that an owner or developer will have is that the hedge will be an energy-only hedge. You will not be able to hedge your capacity or renewable energy credits, which are material parts of the revenue stream for the project.
The reason why the utilities are signing power purchase agreements to buy solar electricity at above-market prices is they need the renewable energy credits to meet renewable portfolio standards.
MR. MARTIN: So the project will earn what it can from spot sales during the four-year interim period. What are current spot prices in California?
MR. CANNON: They are $42 to $44 a megawatt hour.
MR. MARTIN: What electricity price will the winning bidders bid to win these RFPs? At what minimum price will solar developers have to bid to have an economic project?
MR. CANNON: It is easier to say what has won before. It is a price in the mid-$70-a-MWh range. That leaves a significant gap. How do you start off at around $40 for four years increasing to $70 for the next ten years, and how do you shape the repayment schedule on the project debt? Perhaps a lender could do it, but it has not been done yet, and the first one will be challenging to do.
MS. SPANGLER: You can view it as an opportunity for the marketplace. I think what we really need is the development of an unbundled REC market. That unbundled REC needs to trade at such a value that it makes it competitive for a solar project to build before having a long-term PPA. Right now, RECs are trading at around $1 to $2 a MWh in California. We will need something more like $30 a MWh, and there is no unbundled REC market today that supports that.
MR. MARTIN: So we need a policy change at the California state level, and we need the Federal Reserve Board to allow banks to continue serving as counterparties on electricity price hedges. Are there short-term PPAs available in this market?
MS. SPANGLER: There may be some municipal utilities or electric cooperatives that are looking for short-term PPAs to bridge some of the gaps they have in meeting their compliance targets under the state renewable portfolio standard. Industrial customers are another possibility, although the project would have to be on the industrial site to avoid violating a bar in California against retail sales. It is an opportunity for the solar industry to try to find those outlets and, as a financier, we will be there to help you. We are flexible enough to look at all sorts of structures and counterparties.
MR. MARTIN: Bill Cannon suggested that a developer would need a repayment schedule that probably requires payment of interest only, and maybe a little bit of principal, for four years and then starts to repay principal. Does that work for a lender like Carlyle?
MS. SPANGLER: Yes. We need some current return, but we would be able to push some of the return to the back end. As a private equity fund, we do not want a long-term financing. We want to be out in five to seven years, so the loan would have to be structured so that it can be refinanced in the bank or bond market at a lower cost of capital. We would be a source of bridge debt whose loan would be taken out in the bank market or capital markets later.
MR. MARTIN: What about using PURPA, the Public Utility Regulatory Policies Act, which requires utilities to buy electricity from solar projects that are less than 20 megawatts in size. Has anyone tried this?
MR. CANNON: We have seen developers try a PURPA put on wind projects in Texas. I have not seen that approach used in California. The typical commercial bank will not touch that type of structure because there is no guaranteed level of revenue for the first four years. You would have to go to a Carlyle to work with it, but you will have refinancing risk in as soon as five years.
MR. MARTIN: Under PURPA, you are only assured of the avoided cost to the utility, which is probably around the spot price, so you have not really advanced the ball. Is it possible that another developer might have spare capacity under an existing power contract that could be used by another project? Have you ever seen that work?
MR. TRAVIS: Municipal utilities, electric cooperatives and direct access providers all contract on a short-term basis. Those are your primary targets. The hedge is a way to lock in a floor price. If you can combine a hedge with selling to a muni, a coop or a direct access provider at a floating price and some premium for the RECs, then you will have a premium product.
Another strategy is to store the RECs and sell them in the future. This will not help bridge the four-year revenue gap at the front end, but it might enhance the potential revenue from the project once electricity sales start under the power purchase agreement.
Bucket-one RECs from projects that are connected to the CAISO and tied to power contracts of at least 10 years can be pushed into the future. As the law is set up today, a utility buying renewable electricity can claim only 50% of the electricity from a bucket-one project as a renewable energy credit against its state RPS target, but in the future, the percentage will drop to 25%. Over time, the utility will need to buy more and more actual RECs. This suggests that the price of RECs will increase over time. So pushing a bucket-one REC into the future is probably a good strategy.
MR. MARTIN: “Bucket one” is a state regulatory classification. Does it mean the power plant generating the electricity is inside California?
MR. TRAVIS: It refers to generating facilities that are connected to the CAISO grid. A facility does not have to be in-state, but it has to be connected to the CAISO.
MR. MARTIN: Arleen Spangler, I assume the tax benefits are valuable enough that it is worthwhile to try to finish a project by 2016. When you include accelerated depreciation as well as tax credits, they amount to at least 56% of the project cost. What about having the project owners who take the tax benefits make ongoing capital contributions to the project company for a large fraction of the value? That would provide additional cash with which to pay debt service in the short term.
MS. SPANGLER: The tax benefits are very important for the project. It behooves the developer to put the plant in service as soon as possible to get the tax benefits.
MR. CANNON: We own a fairly large solar project that comes on line over a two-year period. We are selling to the utility today even though the full project will not be on line until 2015. The utility is not paying full price for the electricity it takes today, but it is taking the power and its obligation to do so is contractually driven so that makes the lenders happy. Perhaps the way to go is to get a clear right in the contract to sell test energy at a reduced price until the contract kicks in.
MR. MARTIN: Four years of test energy sounds like a long time, but it is a good thought. You would need to compare the price that could be earned in the spot market after taking into account the cost of a hedge. You would still need a hedge unless the test energy price is fixed.
MR. TRAVIS: You are producing zero carbon energy. There is a value to that, and it is at least $5 a MWh. So you tell the utility that I am not just giving you energy, I am giving you zero carbon energy. It may not be a $30-a-MWh REC, but it is more than the $1 a MWh that is being paid for RECs in the market now.
MR. MARTIN: Are there counterparties for financial swaps besides banks?
MR. TRAVIS: Absolutely. Twin Eagle, EDF and Shell will all write a swap. BTG Pactual, a new Brazilian bank, is gearing up to write swaps and do financings for these kinds of projects. There are new people moving into the space that is being vacated by the American banks.
Financeability of Merchant Projects
MR. MARTIN: Can merchant power projects in California be financed?
MS. SPANGLER: Yes, we definitely have appetite for merchant projects, but the financing structure will be project specific. Merchant projects can be financed in parts of the country where there is a deep liquid market for the offtake and where it is possible to get a long enough term hedge to set a floor under the electricity price for the debt term. California lacks the REC market that you would need for solar. In other markets, particularly in the northeast where RECs are a lot more expensive, you may be able eventually to finance something on a merchant basis. Texas is a market where merchant financing is possible today. A few gas—fired power plants have been financed on a merchant basis. They have hedges at the front end to give more predictability to the cash flows.
MR. MARTIN: ERCOT and PJM are the two markets where gas-fired power projects and some wind farms are being financed on a merchant basis. Is there something different about utility-scale solar that makes it tougher to finance that way?
MS. SPANGLER: The difference is that the markets in which they happen to be dominant do not have the same liquidity. There is no capacity market. There are some must-run contracts in California, but they are not very common.
MR. MARTIN: California is tough, but what if you have a large utility-scale solar project in Texas? Is it possible to finance a solar project on a merchant basis in Texas?
MS. SPANGLER: We would be willing to take that type of merchant risk, but we would not take 100% merchant risk; there should be a hedge. You have ultimately to get to the load. Is the load willing? The market is more deregulated in Texas than anywhere, so there are lots of retail players.
We would prefer a hedge for some period of time. In the projects in which we have invested, there is a hedge for a time after which the project is purely merchant. We are taking risk that the hedge can be replaced in time, but looking at market prices for electricity in the out years. If there is a liquid market, then we assume the hedge can be replaced.
MR. MARTIN: Bill Cannon, many people are skeptical about the ability to finance a utility-scale solar project on a merchant basis. Gas seems to work a lot better, wind maybe. What do you think?
MR. CANNON: ERCOT is obviously the easiest example to give because it is a liquid market and there are so many hedge providers. Gas is on the margin there, so you can easily do a merchant gas project and get it financed or have a hedge in place. Wind has reached grid parity in parts of Texas. With production tax credits of $23 a MWh, a project is close to grid parity in Texas if it is in an area with strong wind and can operate at capacity levels in the 40% to the lower 50% range. Such projects can be financed with just a hedge.
Solar is still materially more expensive than wind and gas. Solar qualifies for investment tax credits, but there is not enough juice between the tax credit and spot electricity prices for the developer to make the fair return.
MR. MARTIN: So banks don’t like to finance an uneconomic project.
MR. CANNON: The equity tranche would be left with negative yields.
MR. MARTIN: If you put on a hedge or swap, some of the electricity revenue will have to be used to pay for it. What does a hedge or swap cost? If the project is earning $44 a MWh, how much would go to the price protection?
MR. TRAVIS: Ten percent.
MR. MARTIN: The utilities in California are offering 10-year power contracts so you not only have a problem at the front end, but you also have one potentially at the back end. The project has a long merchant tail. Arleen Spangler, you are lending for five to seven years. Do you worry about take-out risk?
MS. SPANGLER: Yes. We need to be taken out after five to seven years. Merchant risk at the back end could make a takeout harder to arrange. On the one hand, tail merchant risk is somewhat easier to address because the project will have operated for a number of years by then. On the other hand, you will have an older project competing with newer technologies, so there is obsolescence risk to take into account. That is a key risk for solar. The panels keep getting better and better.
MR. TRAVIS: Let me make some observations about the ability to hedge in different markets. PJM was liquid and the deepest electricity market, and it was a bank-driven market where the banks were in their comfort zones. ERCOT is very much an energy-company-driven market. California is a regulatory-driven market, and you have had people simply vacate California and not trade.
What we see happening now is that the liquidity is declining in PJM. Liquidity is increasing in ERCOT because the energy companies are trading, not the banks. California is a volatile market today. The San Onofre nuclear generating station is being permanently shut. A carbon cap-and-trade system is being implemented. In 2016, the transportation sector will be invited into the carbon market. All of this is stirring the pot. Wherever there is volatility, you will find traders. We are seeing liquidity coming back into California as a result. That makes me think that you can get your projects financed in 2016.
MR. MARTIN: You see an opportunity for traders to profit. Is that also an opportunity for developers to get financing?
MR. TRAVIS: As we bring more players into the market, that is where these guys are going to have their opportunity to get financing.