Construction delays and cost increases are forcing renegotiation of power purchase agreements before renewable energy projects can be financed. Wholesale electricity prices jumped 2.5% for wind electricity and 8% for solar electricity in just the second quarter this year. Solar power prices were up 30% on average year on year. Corporate PPAs accounted for roughly six in 10 PPAs signed in 2021.
A panel talked about lessons from recent PPA renegotiations at our 31st energy finance conference in South Carolina in mid-June. The following is an edited transcript.
The panelists are Michael Alvarez, COO of Longroad Energy, Michael Rucker, CEO of Scout Clean Energy, Rebecca Cranna, COO of Cypress Creek Renewables, Tom Buttgenbach, CEO of 8minute Solar Energy, and Johan Vanhee, CCO of Origis Energy. The moderator is Caileen Kateri ("Kat") Gamache with Norton Rose Fulbright in Houston.
MS. GAMACHE: Around half the audience, on a show of hands, said it has been involved with a distressed power purchase agreement in the last two years. Michael Alvarez, what is going on? What is the distress, and how are you dealing with it?
MR. ALVAREZ: There are two basic problems. Construction delays lead to missed deadlines to start delivering electricity and spiraling project costs are making it hard to supply electricity for the prices that were promised. There is a spectrum of distress. We have PPAs where we bid into solicitations some time ago and the PPAs have not been signed yet. We have a PPA that was signed, but not yet approved by the public utility commission. There are operating projects with hedges that are no longer tenable.
MS. GAMACHE: Johan Vanhee, what can you add?
MR. VANHEE: Distress in supply chains is very much our order of the day currently, and it has an impact on project costs. PPAs are often signed years ahead of when electricity deliveries will start. PPAs in the past have had fixed or predetermined prices.
Now we live in an industry where we have the privilege to negotiate the same project PPA twice with the same customer. [Laughter]
MS. GAMACHE: Tom Buttgenbach, have you had to renegotiate any PPAs?
MR. BUTTGENBACH: Yes, several. We are currently renegotiating the timelines and pricing in several of them.
It has been an opportunity to increase value to the customer at the same time by reconfiguring. Energy storage is something that is new to most customers, certainly at the scale of hundreds of megawatt hours of energy storage. In the original PPAs that we signed a year or two ago, some of the assumptions that both sides made turned out not to be so good. It is an opportunity to deliver a better product and to deal with the force majeure issues that have affected all of us.
MS. GAMACHE: You not only reopened the PPAs, but then used that as an opportunity to add storage?
MR. BUTTGENBACH: Not to add storage as much as to modify the storage that was negotiated. The market has shifted. Some offtakers viewed storage as a nice addition to get a foot in the door. By the time we are renegotiating, they realize they need a lot more.
Storage had a lot of supply-chain issues even before the current tariff and forced labor issues that are holding up solar panels.
Reconfiguring the power plant design and adjusting how the solar and storage work together end up being a value driver, which is what everyone is looking for. Most utilities do not just want to negotiate on timelines and price. They want to see some kind of value to their ratepayers.
MS. GAMACHE: What other sorts of concessions have the group of you made as part of the renegotiations?
MR. RUCKER: We have had challenges across the whole spectrum as well. In the last three years, we terminated two hedges — a fixed-shaped product and a proxy generation swap — and restructured a proxy revenue swap.
MS. GAMACHE: Becky Cranna, anything to add?
MS. CRANNA: It might come as a surprise to all of you as fellow developers, but we were overly optimistic in a couple cases on our ability to get projects permitted and through the interconnection queues. The types of issues we have had recently have really related to timing. Our issues are less price-related and more related to milestones set out in the PPA.
MR. ALVAREZ: This isn't a concession, but we have been required to be much more transparent about our costs. When you say X went up by Y, they say show me. If you are not transparent about that, it will be difficult to get them to accept an increased price even though their own procurement departments are having the same problems we are.
MR. VANHEE: A lot of our customers want to build in more certainty. They say, "Fine, we understand. We all pay more for gas when we fill up our tanks at the gas stations. We understand there is inflation, but you are not going to be able to adjust twice for the same problems." We see a trend in renegotiations that we have to post higher security.
Utilities v. Corporates
MS. GAMACHE: Is there a difference between how utilities and corporate offtakers react to requests to renegotiate?
MR. BUTTGENBACH: Yes, to some degree. Corporate offtakers are much more commercial, but are also more demanding of transparency.
There is a significant shortage of good projects in the regions where we operate. One of the demands of offtakers has been to increase the volume. They say, "If I help you over here, then I want to see additional megawatt hours." We have been able to do that fortunately, but it is never as simple as haggling over a new price. The offtakers want concessions to make changes.
However, at the end of the day, all of the offtakers want the project. They are worse off without the project, especially in a market where it is very difficult to find additional renewable electricity.
MR. VANHEE: I don't see a difference between the type of customer, but I see a difference in level of sophistication. Some customers, whether they are utilities or corporates, are very sophisticated. They go deep by probing, for example, into whether we have covered the withhold release order risk and forced labor issues. They don't want to have to come back to the negotiating table again.
MR. RUCKER: The differences for us are driven by geography. We work a lot in WECC, for example, where we are going through classic utility RFPs that take a year to complete. In this environment with costs moving constantly, the need to bid something a year before the contract is awarded is absolutely impossible.
The utilities have not figured out a process for procuring power that works commercially in the current market. The processes are not dynamic or responsive enough.
In other ISO markets, corporate PPAs are more prevalent. Corporate offtakers are more commercial. They are more flexible about managing the kinds of supply-chain risks that we all face today.
MS. GAMACHE: Wood Mackenzie told us yesterday that, based on 20 years of data, WECC, SPP, SERC and MISO are the riskiest places to forecast what merchant power prices will be after the power contract ends. Merchant forecasts were more accurate in PJM and ISO-New England. How about during the contract term? Is there a regional winner and loser?
MR. ALVAREZ: We don't evaluate it that way. We leave a piece of projects merchant as an internal hedge.
MS. GAMACHE: Always?
MR. ALVAREZ: Not always, but where we can we do that because some of our origination people think the curve always goes up. We have never hit the curve that we started with — ever. But they see it as a fundamental opportunity to take advantage of dislocation in the market. We do not go fully merchant on anything.
MS. GAMACHE: Do you get financed on the full capacity or only on the contracted revenue?
MR. ALVAREZ: Contracted.
MR. RUCKER: We take a market approach in terms of the percentage of offtake that we want to be contracted. In a market like SPP that has a very high percentage of renewables, particularly wind, we try to get as much contract coverage as we can. In markets like PJM, we leave a merchant sliver open. We are very happy to have that right now with natural gas prices as high as they are.
MR. BUTTGENBACH: Let me go back to a point that was made earlier.
We have gone from negotiating with one party who had a well-understood process, like an RFP, followed by the need to go upstairs for approvals, to a multilayer negotiation, and that is where the big differentiation comes in between the parties. The more commercial offtakers, like corporates, have well-understood internal processes.
The regulated utilities that need PUC approval have never had to explain to a regulatory commission why they are now changing the price, how they justify it, and how they know the new price is market if it was not set by an auction in an RFP. That is what is slowing down the utility renegotiations and making them less commercial.
MS. GAMACHE: Some regulated entities may be inclined to say no to renegotiation because they do not want to have to revisit a contract with their regulators. Have any of you gotten approval for a renegotiated PPA from a regulatory commission? One head shake.
MR. BUTTGENBACH: Not yet, but in process. I thought within about three months, we could renegotiate these PPAs and then go through the approval processes. We are now nine months in, and we are not there yet.
MR. ALVAREZ: Regulators are reluctant to set a process and then change it. There are equity considerations. The power contract may have gone to the lowest bidder whose price proved too optimistic.
We had an experience where we signed a contract that over time went out of the money. We renegotiated the contract with the utility and agreed on a new price. The commission rejected the new price. We requested reconsideration. More time went by. The contract fell even more out of the money. We withdrew, and then the commission approved the renegotiated contract.
Many people in this business believe that prices fall over time. Our view is that, with a trillion dollar infrastructure bill, a war in Ukraine that is taking a lot of oxygen out of the system, fuel prices that are not going down or stabilizing and rising interest rates, this is going to be a long-term phenomenon. At least one counterparty with whom we renegotiated with is quite happy with the new price. We reset the price in January, and here we are in June and it is pleased.
MS. GAMACHE: You just brought up a topic that some in our audience said yesterday they wished we had discussed more, and that is the effect of the Russian invasion of Ukraine on our market. Becky Cranna, are you seeing an effect?
MS. CRANNA: For sure. There were issues with equipment procurement and sourcing of commodities before the war, and the war has made a challenging situation worse.
MR. BUTTGENBACH: I was going to say I was just about to file a force majeure notice when I came in late. [Laughter]
There were serious supply-chain issues on the coffee stand. [Laughter]
The war in Ukraine has wreaked havoc on the supply chain. This is just the latest in a string of difficulties, starting with COVID and the lockdowns in China.
MR. ALVAREZ: I think we have only begun to see the effect. The Defense Department is going to have a higher-priority claim than the rest of us on restocking aluminum, copper, chips, you name it, for the high-tech weapons that are being shipped by the billions of dollars.
Then there will be the rebuilding of Ukraine. We have our own trillion-dollar infrastructure bill already laying claim to construction materials. Think about how much rebar goes into bridges. It is going to be a very difficult to navigate through the next several years.
I am not sure I agree with John Breckenridge's comment yesterday about 10 years of cost increases for batteries. (See "The Evolving Energy Storage Market" in the August 2022 NewsWire.) I think the lithium market may be able to rebound more quickly than that. The government does not seem to use as much lithium as we do at the moment.
MS. GAMACHE: People thought in the past of force majeure provisions as a kind of contract boilerplate. Now such clauses are getting much more attention. What else is getting closer attention today? Put differently, what will you do differently in every PPA you negotiate in the future based on experience over the last two years?
MR. RUCKER: We look for reopeners to cover the risk of commodity price inflation. We want the ability to put through price changes between the time we sign the PPA and when we actually procure equipment and give a notice to proceed with construction. We need a reopener on price if we see completely unexpected results in our final procurement process.
MS. GAMACHE: So not necessarily an escalator, but more of a "Let's get together if this happens."
MR. RUCKER: Just a reopener, although we have also relied in some cases on indexing to major indices. Some of them are just price targets based on feedback that we get from the balance-of-plant construction contractor or network upgrade costs that we get out of transmission studies. There may be a mix of reopener triggers, with everything designed to help us contain the risk of escalating costs before notice to proceed with construction.
MR. ALVAREZ: We have had multiple counterparties ask for a two-way street on this. What goes up must also come down in theory. An example is if a tax bill passes that increases the tax credit, the counterparty wants to see a price reduction. These are difficult provisions to negotiate. It is hard to write down all of the "what ifs" about tax policy.
MS. CRANNA: One lesson is it is best to wait to lock in an electricity price, if possible, until close to when the project is ready to start construction.
MR. BUTTGENBACH: I have been trying to convince offtakers about who I am. I am a great developer, but I do not have a great crystal ball. I can't predict lithium prices, steel prices, labor shortages or how COVID will affect governmental agencies who have to approve projects and timelines. My value add is in delivering a great project, but not in predicting commodity futures.
When you bought a combined-cycle gas turbine from GE, you didn't require GE to guarantee what the gas price was for 20 years. Most offtakers would hedge the gas for five years and then report to their boards on the expected economics of the gas plant. The truth is they had no idea what the economics would be like 20 years out.
The same is true for us as developers. Our value is in knowing how to design and build a great project, but the commodity price risk needs to be taken by the offtaker.
I have found more sympathy for that argument for future projects, which is easy today in a seller's market with available projects in short supply. We will not sign a contract without an index, unless we can get suppliers to take the commodity price risk and, even then, there is a risk. We have had suppliers, including very large balance-sheet suppliers, renege on contracts. A US battery manufacturer comes to mind that reneged on contracts.
This is no different than what utilities have done for the last 50 years every time they negotiated a gas-fired power plant. Fuel prices are volatile. Commodities are volatile. The good news is that once we have built a solar project, we are pretty much done. There is no fuel cost. The uncertainty is a three-year problem and not a 30-year problem.
MR. RUCKER: I agree that the risk tied to those variable costs over time should be put on the loads. They are the ones with the flexibility in their pricing and their regulatory processes to recover the cost increases from the ultimate customers.
We are basically working with a fixed levelized cost of energy over the full term of the contract. We are lucky to get inflation adjustments, although they are now coming back into style. Historically we have had fixed-price long-term contracts, and such contracts are not manageable in the current environment.
MS. GAMACHE: Will any of you enter into a fixed-price power purchase agreement today?
MR. RUCKER: Yes.
MS. CRANNA: Yes.
MS. GAMACHE: What assumptions will you include in that fixed price?
MR. RUCKER: We do our best in our long-term models to model for inflation. What is it going to be? Forward power pricing? Forward curves? The Wood Mackenzie presentation yesterday was fantastic, but as we know historically, the consultants are always wrong. [Laughter]
MR. ALVAREZ: There are two areas that worry me.
One is the bias towards prevailing wages that is aimed at us in "Build in America" kinds of legislation. We do 30- and 35-year models like everybody else does — pick your inflation rate — but none of them accounts for how the need to pay the same wages that are paid on federal construction jobs will affect our economics.
The other source of worry is storage costs. You can build in a 35% to 40% forward price increase assumption for lithium, but no one has any idea what lithium will cost 20 or 30 years from now.
MS. GAMACHE: For those of you trying to index, what are you indexing before and after commercial operation?
MR. VANHEE: We try to keep it as simple as possible. We are going to look at commodity indexes and try to get them in the contract. If we are lucky, we may have a general inflation index, but watch out with inflation. It can work against you as well.
MR. BUTTGENBACH: We look closely at force majeure clauses in contracts from our equipment suppliers, and we also look at the choice of venue in the event there is a dispute.
Some suppliers demanding price increases say basically, "Come visit us in Shanghai. Good luck in court here. If you want panels, this is what you have to pay." We respond, "We have a contract." They say, "Yes, very interesting." [Laughter]
That was before the anti-circumvention investigation. We are much more careful today. We are trying to hedge as much as possible in the sense of buying from credible suppliers, with language that is clear about what happens if they do not perform under the contract and that matches the penalties we face if we cannot perform the PPA.
MS. GAMACHE: We heard yesterday that EPC contractors are no longer agreeing to price caps. I know many of you don't sign the EPC contract until you have a signed PPA. Once the EPC contract is signed, is there an index in it for labor costs?
MR. RUCKER: We have not had an index for labor costs in any of our EPC contracts to date.
MR. ALVAREZ: Fuel costs have moved about $1.5 million on a large solar project that we have currently under construction. The contractor is not able to hedge against fuel cost increases. In some cases, the contactor may be able to protect against such cost increases by buying fuel in advance.
MS. GAMACHE: There are various forms of electricity price hedges. One is a contract for differences, but it creates electricity basis risk. Winter Storm Uri has made people a lot more careful about hedges. (For more detail, see "How Hedges Have Changed Since Uri" in the June 2022 NewsWire.)
MR. RUCKER: We look for blowout protection on electricity basis risk in our contracts. That is a common feature in most contracts today in ISO markets. It is an approach that looks for extreme events. For a wind project, the trigger might be a price gap roughly the size of the PTC value. There may be a cap on the number of hours per year that such a provision can be invoked.
MS. GAMACHE: Is blowout protection a capped price or a switch in the hub or node where the price is set?
MR. RUCKER: It is usually a switch. You can choose a number of hours a year during which you basically have no settlement.
MS. GAMACHE: Where else are you sending lenders a PPA and they send it back and say "fix this"?
MS. CRANNA: Lenders prefer that the contract not be for more than the P99 output of the project. They worry about over-contracting.
MR. VANHEE: There were recent news reports that solar projects are underperforming. I expect lenders will require a correction there. (For more detail, see "Overestimation of Solar Output" in the October 2020 NewsWire.)
MR. ALVAREZ: Another pain point is severe convective weather. In just the last month, at least five — maybe six — solar facilities in Texas suffered serious hail damage. At least two were completely wiped out. I am talking about $100 million losses. Insurance policies have high deductibles and then a cap on payments, so lenders are basically wearing not only all of the bottom risk, but also the top-level risk as well. That is causing a severe amount of distress in areas with frequent hailstorms.
MR. RUCKER: We try to bring perfect contracts to our lenders. [Laughter]
We are seeing more use of floor pricing concepts in the last few years, particularly in markets with very high basis or co-variant risk for wind production. (For more detail, see "Covariance Risk: What Is It and How to Manage It" in the June 2019 NewsWire.) The floor price can be provided through an affiliate PPA. (But see "Section 707(b): Related-Party Electricity Sales" in the June 2021 NewsWire.) We are also seeing revenue put options. (For more detail, see "Solar Revenue Puts" in the October 2016 NewsWire.)
MR. BUTTGENBACH: On the good news front with the lenders is that they are much more flexible in terms of looking at concurrent merchant revenues. I am not talking about post-PPA, 20 years out. We have quite a few projects now with a significant portion of the project uncontracted. Two years ago, that was toxic. The lenders and tax equity investors did not even want to look at that. There has been a shift in thinking it is a good thing at the right ratio.
I wish they would take the same stance on not requiring long-term service agreements for batteries. It is crazy for me to commit for 15 or 20 years to replacing parts on my Ford Model T. [Laughter]
MS. GAMACHE: Have you seen changes in the collateral that buyers have to post?
MR. VANHEE: We try to get as much as we can in collateral, but we have not seen any changes in buyer security. If they ask me to take more risk and more exposure, it goes both ways.
MR. RUCKER: Not much here, either.
MR. BUTTGENBACH: We have seen some increase.
MS. GAMACHE: Audience question.
MR. WARANCH: Andrew Waranch, CEO of Spearmint Energy. We've had a difficult time hedging our lithium using any of the Asian markets. Two-part question. One: have you had any success in any of the Asian future markets hedging the lithium risk? Two: have you been able to transfer lithium in the PPA to others who might be able to hedge the risk for you?
MR. VANHEE: Two times no.
MR. BUTTGENBACH: Two times yes.
MS. CRANNA: No.
MR. RUCKER: We haven't bought a battery yet.
MR. ALVAREZ: We have an index, but it is operating through an integrator whose credit quality is not necessarily sufficiently sleeved to rely on yet. We try to buy direct modules and on occasion direct trackers and inverters. There may be an opportunity to go direct on battery cells in which case, there would be an opportunity to manage that risk. However, you are taking a huge amount of procurement risk when you do that directly as a developer.
MS. GAMACHE: It seems like PPA prices have been skyrocketing, but unevenly across the US. What are you seeing?
MR. ALVAREZ: I wish they were skyrocketing. They have been going up. A lot of what we are doing now is capacity-based. Solar-plus-storage is all capacity-based, and the capacity payments have gone up compared to what we were bidding on the order of around 20% in a very short period of time.
MR. RUCKER: We have seen PPA pricing going up in every market. The electricity demand from buyers is seemingly insatiable at the moment. We have been lucky during a period of a big runup in demand and inflation to be able basically to increase pre-contract bids for most of our projects. The increase is roughly keeping pace with commodity cost increases, but does not compensate adequately for the volatility risk.
MS. CRANNA: We are seeing similar trends across multiple markets. The increases are being driven by not just commodities, but also the war in Ukraine and interest rates. The increases are pretty consistent across all of the markets where we have projects.
MR. BUTTGENBACH: I believe the Clearway CFO said during an earnings call that his company has seen PPA prices increase by 30% to 50%. It depends on how old the contracts are. For a contract that I signed a year ago, prices now might be 30% higher. For older contracts, prices today might be 50% higher. This is true across the Southwestern US and Texas.
MR. VANHEE: Same trend, I think. We make a distinction between what we call "Perfect Storm 1.0" and "Perfect Storm 2.0." [Laughter]
Storm 1.0 is COVID and everything related there. That was regional and a 15%-ish perfect storm. Now we are seeing a 20% to 25% increase across the board in the second stage.
MS. GAMACHE: Another audience question.
MS. CHRISTIE: Holly Christie, general counsel of Hecate. Two or three years ago, we never would have gone back to renegotiate a power contract. Now it seems like such renegotiations are commonplace. Are you finding some offtakers are not open to renegotiation and, if so, how do you approach those relationships?
MR. ALVAREZ: The knee-jerk reaction is just to say no. You have to be persistent. There is also a bit of a flight to quality, so some of the counterparties trust some people and don't trust the market in general. That goes back to my transparency comment. But they don't really have a choice. Their own procurement departments are seeing the same cost increases. After a while, the resistance breaks down.
MR. RUCKER: We have seen a lot of cooperation, really. The offtakers need a project, and they have procurement and ESG goals. They will have to be flexible to realize them. We have not had a hard no yet. I agree that you have to be persistent.
MS. CRANNA: Relationships matter. Demonstrating that you are credible matters. There are two hurdles in any renegotiation. The first is proving you and your project are credible. You are going to be able to get the project done. The second is proving you have your equipment lined up. Price obviously matters, but it is not all about price.
MR. BUTTGENBACH: I would add to that what additional value you can provide to the customer. They have to sell the price increase internally. There has to be a bit more of a story than "We agreed on a price X, and now we are going to agree on X plus." The story has to be we are getting a better plant, or we are getting more megawatts.
They are all short electricity. The fact that they are looking at contracts that are not going to be performed is a much bigger problem for them than it is even for us. Walking away from development security is painful, but losing X% of your generation that you had planned for can be a serious problem for a lot of utilities. Prices in the resource adequacy market in California have gone up 50% easily. That is just pure shortage. We have not had a single hard no. Persistence, yes.
I remember when I got the news that a major US battery supplier reneged on its contract with us. I came up with a lot of four letter words to describe the supplier. Three months later, we were begging it for more volume. [Laughter]
I am sure the utilities go through the same kind PTSD, and they probably hate you for a little while. But as Becky said, if you have a good relationship and you make your case, we have not had a single one refuse to reopen the contract.
MR. VANHEE: There were a lot of no's in Perfect Storm 1.0. Now it is always maybe. We don't get a no anymore. If they see me show up, they know what is coming. [Laughter]
I already apologize before entering their offices.
MS. GAMACHE: We are getting the hook. Please join me in giving our panelists a big warm thank you. [Audience cheers]