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As it becomes harder to find utilities willing to enter into long-term contracts to buy electricity, renewable energy developers have been signing power purchase agreements to sell electricity directly to large corporations. Several thousand megawatts of corporate PPAs are expected to be signed in 2016 in the US market. Some of the contracts are for physical delivery of electricity. Others are virtual PPAs that are swaps of fixed-for-floating payments around the electricity from a project.
Two corporate buyers of electricity and two renewable energy developers talked at an Infocast conference in late September in Washington about the main issues that must be addressed before such a contract can be signed. The room was standing-room only. The buyers are Anthony Davis, project manager for renewable energy, global environmental compliance sustainability group, General Motors, and Renée Morin, living progress-stakeholder relations, Hewlett Packard Enterprise. The sellers are Ted Romaine, director of origination for Invenergy, and Jacob Susman, vice president and head of origination for EDF Renewable Energy. The moderator is Keith Martin with Chadbourne in Washington.
MR. MARTIN: We will do two things this afternoon. First, there are a number of general questions listed on the program and, in case you have come to hear those answered, we will answer them first. Second, we want to show you what happens when the two sides sit down to negotiate a corporate PPA. We have two buyers and two sellers. We want to talk through what issues need to be resolved to give you a feel for how they might settle.
Starting with the general questions, Jake Susman, are there enough renewable energy projects to meet corporate demand in 2016?
MR. SUSMAN: In a word, no. Development pipelines have thinned. Many developers, especially in wind, are in the process of rebuilding them. If you look under the hood of a lot of projects today, they are still somewhat early stage.
MR. MARTIN: Developers thought 2016 would be the end of the market before Congress voted late last year to extend renewable energy tax credits. Ted Romaine, what do you think about 2017 and beyond? Will there be enough projects to serve the demand?
MR. ROMAINE: I think there will be. I think Jake is right. We are rebuilding pipelines. We heard from some panelists this morning that it is really a buyer’s market. Looking forward to 2017 and 2018, more projects will be nearing completion.
You have the production tax credit for wind starting to phase out next year. That will affect what people do in the short term. There will be greater interest in wind farms that qualify for full tax credits. There is a little longer runway for solar. Developers like EDF and Invenergy will work very hard to bring up our pipelines and make sure we have enough capacity to satisfy the market.
MR. MARTIN: So Jake Susman, Ted Romaine said it is still a buyer’s market this year, even though development pipelines have thinned. How can that be?
MR. SUSMAN: It is a question of timing. We had a lot of end-of-year demand last year when people thought we could be nearing the end of tax credits for wind and solar. Wind got only a four-year extension, but there is favorable IRS guidance around that extension.
That basically caused people to pause to think about how they want to do their procurement over the next couple years. We are feeling the demand ramp back up in real time, but it will take some time for demand to ramp back up to match supply. Call it 12 months. I think you will then start to see people realize their pipelines are a little thin.
MR. MARTIN: Here is another general question for our two sellers. There were predictions as recently as June that the corporate PPA market would reach 4,000 megawatts this year. From where you sit, does that seem right?
MR. SUSMAN: I think we are going to fall a little short of that. I think there was a real push at the end of last year to get those projects done with the tax-credit cliff hanging over our heads. I don’t know exactly where the figure will end up this year.
MR. MARTIN: Let’s move to the buyers. Renée Morin, how are buyers like you finding the right opportunities for your companies?
MS. MORIN: Speaking for Hewlett Packard Enterprise, we have one deal that has already been concluded and is in Texas. For that deal, we enlisted the services of a third-party consultant, Schneider Electric, who helped us through that process. It was a steep learning curve. It was the first time for us. We also had to enlist the help of a lot of others within Hewlett Packard besides our sustainability group. We got our local real estate people, procurement department and data center team involved. We need the outside help to make sure we could get it done.
MR. MARTIN: It sounds like a long process.
MS. MORIN: Yes, but we hope the second time around will be quicker.
MR. MARTIN: Anthony Davis, how does General Motors find sellers?
MR. DAVIS: The second time around is never quicker and I say that from GM’s experience. [Laughter.]
MS. MORIN: Maybe less painful?
MR. DAVIS: It does get less painful.
MR. MARTIN: How long is it just as a point of reference?
MR. DAVIS: We are on our third time around at General Motors. We hope to be able to announce our third PPA before the Business Renewables Center gathering in November, which will be at General Motors headquarters at Detroit. That is a shameless plug. [Laughter.]
So, yes, it takes a while because there are a lot of people who have to get involved.
MR. MARTIN: Six months? Eight months?
MR. DAVIS: Six to eight months has been the norm for the last two. It takes that long because we are not renewable energy companies. We are car companies and enterprise data companies. We are everything else except for renewable energy.
It takes time to get people on a call or to respond to emails so that we can respond as a company to an issue. Then it takes more time for the developer to respond. It is a rambling sort of back and forth. It would not take so long if you could lock everyone in a room and say, “Don’t think about your normal day job for a week.”
There is definitely an appetite for these PPAs among corporations. We signed onto a 100% renewable energy goal. We just have to get to a point where we are more efficient at execution.
MR. MARTIN: How do you find the sellers? Do they come to you?
MR. DAVIS: We also have a third party, Altenex, that helps us identify available projects and developers and come up with a set of criteria. We also have a lot of good relationships from the different conferences that we attend from Solar Power International to forums like this. We have made a lot of good contacts.
MR. MARTIN: Let’s move next to where the rubber meets the road. We plan to drill down and see whether we can get to a deal between these two groups. We have two buyers and two sellers. Just to frame the discussion, we are talking about a 100-megawatt project for what could be a contract for physical delivery of electricity or a virtual PPA.
The points we will hit are pretty much the different sections in a term sheet.
Let me start with the buyers. Renée Morin, do you care whether the power project is wind or solar?
MS. MORIN: That is generally not one of our criteria.
MR. MARTIN: You have signed one contract to date. That project was wind?
MS. MORIN: It was wind. Anthony Davis, do you care?
MR. DAVIS: Not necessarily, but I think we would lean more toward wind because of the better economics that you get from wind technology versus solar. While we are open to all technologies, the prices for wind electricity are usually lower than for solar.
MR. MARTIN: Do you care about the credit-worthiness and the experience of the seller?
MS. MORIN: Our procurement department does.
MR. DAVIS: Yes. Very much so.
MR. MARTIN: What does somebody have to bring you in terms of credit-worthiness and track record?
MR. DAVIS: The developer must be able to post a letter of credit or a credit-worthy parent guarantee to cover damages if the project fails to move forward after we sign the contract. Developers ask us to post a letter of credit as well. There were questions around GM’s credit-worthiness when the company was coming out of bankruptcy.
MS. MORIN: Concerns about credit-worthiness and the need for security to ensure performance are a two-way street.
MR. MARTIN: Anthony Davis, how large a letter of credit do you require of the developer, and how long does it have to remain in place?
MR. DAVIS: I would say large enough that we need to get a lot of people to sign off on it before the PPA can be signed. I can’t give any numbers because I am not sure whether GM would consider the number confidential.
MR. MARTIN: Is there a relationship between the size of the letter of credit and the value of the project or the value of the power contract?
MR. DAVIS: Yes.
MR. MARTIN: What is it?
MR. DAVIS: I don’t know the exact relationship. It seems linear so far based on the two to three that we have done. The larger the project, the larger the letter of credit that is required. Our treasury group crunches the numbers to determine what security we need, and we also get input from our consultants at Altenex. MR. MARTIN: Do you release the letter of credit or other security once the project is operating?
MR. DAVIS: Yes. We require the letter of credit to be posted 10 days after we sign the PPA.
MR. MARTIN: Sellers, does that work for you?
MR. SUSMAN: Your credit is looking a lot better recently, Anthony.
MR. MARTIN: We have learned that corporations can disappear almost overnight. Think of Enron or SunEdison.
MR. DAVIS: GM is not going anywhere.
MR. MARTIN: It almost went somewhere. Sellers, you need to finance the project based on this power contract. What sort of security do you need and for how long?
MR. SUSMAN: We focus on things like percentage of the over-all investment in the project on a dollars-per-kilowatt basis or maybe a total-number-of-years-of-revenue type of measurement to establish a minimum amount of security we need posted to ensure the buyer will pay for the electricity we are delivering.
MR. MARTIN: Should the amount of security be tied to the amount of debt you have to repay or the amount required to enable the tax equity investor to reach its target yield?
MR. SUSMAN: Think about it. We are going to invest hundreds of millions of dollars to build the project on the assumption that HP or GM will be around to pay for the output for 20 years. If something goes sideways, we need some time to be able to establish a plan B. So you want to make sure that you have enough credit to cover the gap until plan B can be implemented.
MR. MARTIN: Does it have to be an LC or will you accept a parent guaranty?
MR. ROMAINE: There is a range of options for the security: an LC, a funded reserve account or security deposit, a parent guaranty.
MR. MARTIN: Buyers or sellers, where is the delivery point for the electricity or, if we are doing a virtual PPA, the settlement point where the market price is set for the electricity?
MR. DAVIS: We have been told over and over again never to settle a deal at the bus bar, so I will never settle a deal at the bus bar, only at the hub. I still do not know how to explain why in less than two minutes.
There is a lot more risk to signing a deal to take or price electricity at the bus bar than at the hub. By settling at the hub, the basis risk is on the developer. That seems appropriate because the developer understands that part of the business better than the buyer does. It should be better able than HP or GM to manage and mitigate the risk.
MR. MARTIN: Ted Romaine, what risk is he pushing off on you, and are you willing to accept it?
MR. DAVIS: Just say yes. [Laughter.]
MR. ROMAINE: Always, always. We have announced four deals with corporate customers. We have done both bus bar and hub. We have been successful at getting all four deals financed. The risk that we take with the hub-settled deals is the congestion and price difference between the bus bar and the hub.
I understand from GM’s perspective why it is interested in a hub settlement, especially if GM plans at some point to trade around the position. It makes sense to price at the hub because there is a more liquid market there.
At the same time, I encourage buyers to look at it on a project-by-project basis. I think buyers could be better off staying at the bus bar depending on the project. I do not think there is necessarily a right or wrong way to look at it. I would not make it as absolute as everything has to be at the hub.
MS. MORIN: We have considered both in our evaluations.
MR. SUSMAN: I appreciate the buyers’ arguments, but I think it is a little less black and white than they lay out. I think there is a lot more value to be garnered by doing one of these deals at the bus bar and, of the six that we have done, some have been bus bar, some have been hub, and it all comes down to a question of the sophistication of the buyer to some degree and its ability to analyze and price the risk of being in one location versus another. I usually tell customers you will get better value if you trade with me at the bus bar.
MR. MARTIN: Why is the electricity price different at the bus bar than at the hub?
MR. ROMAINE: I can only go so far into this, but the grid operator in an organized market will run a security-constrained economic dispatch model that will determine pricing at all of the nodes in the market, and that will take into account the physical constraints of moving electricity between pricing nodes. When the computer crunches the numbers and generates a price at each point, the difference in price between two points is basically the “basis.”
MR. MARTIN: Why isn’t the price at the bus bar the same price as at the nearest pricing node on the grid?
MR. SUSMAN: There are lots of different wires, or “pipes,” that are set up to move power around the system. Some are really fat, and some are really skinny. Sometimes new power plants get built. Sometimes power plants get retired. Sometimes people use a lot of electricity in certain places. In other places, people use little electricity.
This all happens at different times of the year and different times of the day. You have to look at a model and decide how your new project will be able to fit the output through the nearest pipe when there are 12 other projects, and some additional ones planned, competing for the same piece of pipe. People assess the risk. They may say it is safer at point A on this side of the pipe than point B on that side of the pipe.
MR. MARTIN: So sellers, you have told Anthony and Renée that they will get a better deal if they buy at the bus bar. I don’t know if you persuaded them.
MR. SUSMAN: If you are a particularly savvy buyer of energy, you will see that I have to finance my project and raise money from tax equity, and the financiers will take a very conservative approach to basis risk. It will cost me an extra X percent for tax equity.
If you have an appetite to share some of that risk or even take it all on yourself, then you reduce my cost of capital and you make it possible for me to give you a lower price for electricity.
MR. DAVIS: Doesn’t that expose me to more price fluctuation at that local bus bar location versus a more smoothed-out price prediction at the hub, where the greater liquidity makes the pricing a little more stable? My CFO and treasurer want to be in a better position to predict our future cash flows.
MR. SUSMAN: 100%. Let me key in on the word “value.” If safety is the only thing you care about, then the hub is probably the better place for you. If you are fairly sophisticated and savvy and you also see an opportunity to create some value by wearing a little bit of risk, then you might want to share some of that risk with me to get to the higher value.
MR. MARTIN: So sellers, let’s say we have not made the sale here. Our buyers are going to set the price at the pricing node on the grid. The relevance of this, correct me if I am wrong, is our buyers are actually going to pay a fixed price for the electricity, and you will give back the settlement price at the grid node. I am thinking this is a virtual PPA.
MR. SUSMAN: Correct.
MR. MARTIN: What happens if the grid node price is below zero?
MR. SUSMAN: That will be a negotiated term in the contract. For some folks in the audience who may be unfamiliar, if we do not get paid for our generation at a certain hour and decide, as a consequence, not to generate that hour, then we also lose the production tax credit which has a pre-tax value that is actually higher than its face value of $23 a megawatt hour. So this is often a hotly negotiated topic.
MR. MARTIN: So you want to keep operating.
MR. ROMAINE: It depends on the technology. Wind and solar are different beasts because one has production tax credits that depend on electricity sales and the other has an investment tax credit that does not. Economically speaking, it makes sense for a wind farm to operate all the way down to the negative value of the grossed-up PTC. Solar is not like that.
MR. MARTIN: How do you settle in that case? You have to pay Anthony or Renée the market price for the electricity in exchange for the fixed contract price. The market price is negative. Do they owe you the negative amount?
MR. ROMAINE: Yes.
MS. MORIN: That can happen.
MR. ROMAINE: That’s pretty much the crux of the PPA. It is a swap of the fixed contract price for the floating market price.
MR. MARTIN: Renée Morin, how long a term of contract would you be willing to sign?
MS. MORIN: Our current one is 12 years, which has opened the door for our internal folks to feel a bit more comfortable about a longer term. That is not typically how they contract for other goods and services. They feel uncomfortable about anything over three to five years, so 12 is a hurdle, but they understand this is a different market. We may even be able to go longer on our next deal.
MR. MARTIN: Anthony Davis, how long will you go?
MR. DAVIS: We have only signed PPAs that are five years long. I am just kidding. I wanted to see if people would go, “What?” [Laughter.]
MR. MARTIN: We are getting some uncomfortable laughs out here in the audience.
MR. DAVIS: So . . . .
MR. SUSMAN: You are uninvited to dinner. [Laughter.]
MR. DAVIS: Fifteen years is good. The main consideration for us is the car model years and how long the plant will remain in the area producing a particular model. That is typically a 12- to 15-year period.
When sellers first proposed 20 to 25 years, GM was like, “No way. Get it down.” So we got it down to 15. Last year we signed a 14-year contract, and now we are working on a 12-year deal. It is coming down, but I think we are in our comfort zone where our finance folks feel comfortable with the market projections and our treasury feels good with the term of the LC that will be required.
MR. SUSMAN: This is another one of those safety-versus-value questions. Folks who are doing their first deal tend to want the shorter tenor, and they tend to want to transact at the hub. But as they get a little more used to it, they start to realize that the value in these contracts is in going out more years. The longer tenor implies more risk, but we think there is more value to be had for the buyer.
MR. MARTIN: The longer tenor is an insurance policy against rising electricity prices. Somebody from Bloomberg New Energy Finance said at a recent conference that he thinks many corporates are not signing up for PPAs currently because they believe electricity prices will fall in the long run. Anthony Davis, you are nodding yes.
MR. DAVIS: Yes. At least from my point of view, I see prices falling. Falling natural gas and oil prices continue to depress the market. I am also of the view that as we put more renewable energy on the grid, the basis for pricing in regional markets will shift to renewable energy rather than natural gas, coal or oil.
Once we move completely out of coal, coal will no longer be a metric in any market. It will really be natural gas, and natural gas is cheap and abundant right now, so why would the electricity price go up? I understand there are a lot of counter-arguments to that as well.
There are other countries besides the US that will continue to rely on natural gas and coal. India is one of them that relies heavily on coal, and local coal prices are still rising.
MR. MARTIN: Ted Romaine, we are going to offer the buyers a fixed price. How do you arrive at the fixed price?
MR. SUSMAN: What would you like?
MR. ROMAINE: Always start with the customer.
MR. DAVIS: Free would be great, but . . . .
MR. ROMAINE: We finance everything on a project finance basis, so we will need to raise the money to build the project and we are not shy about saying we like to earn a little bit of money along the way as a reward for our trouble. We run an internal model to determine the price. It is a discounted cash flow model that I am sure almost everybody in the industry uses, with slight variations on capital stack, from one seller to the next.
That is one piece of the equation. Then there is understanding the market, the customer, and the terms and conditions. We never separate price from terms and conditions.
MR. MARTIN: Renée Morin, Ted Romaine has come in and offered you a fixed price. Jake then comes knocking at the door. Do you tell him, “You have to beat X price to be in play?”
MS. MORIN: No, no, no. We cannot disclose certain attributes of the deal like that. We work with our developers individually because each deal and project is different. The finances are not necessarily apples-to-apples. I think the terms and conditions are also important.
MR. MARTIN: Name one big term and condition that is as important as price.
MR. DAVIS: Price. [Laughter.] That is really what it comes down to. Other than the term, which we have kind of hammered out, price is going to be important. We have to feel happy with the initial PPA price and the escalator.
MR. MARTIN: If there is an escalator.
MR. DAVIS: Yes. If there is one, the price has to remain below the projected market price. We have external analysts that are running low-, base-, and high-cost projections and we also just look at it bare bones, take inflation into account from an internal GM perspective with a very conservative market price escalation, to see what the net present value of the contract will be.
The PPA price and the escalation are the two biggest things for us.
MR. MARTIN: Ted Romaine, how hard can this be? He is looking at a retail price and you are offering wholesale.
MR. ROMAINE: Yes, we should be able to charge a lot more. [Laughter.]
MR. MARTIN: Anthony Davis, is it true that you are comparing a retail price to a wholesale price on offer from our sellers?
MR. DAVIS: No. We are looking at the hub market price. For example, one of our two existing PPAs settles at an ERCOT hub. That is our benchmark for testing where we are being offered a good deal rather than the retail electricity price paid by one of our facilities.
MR. MARTIN: Renée Morin, do you care whether the power plant from which our sellers are proposing to sell electricity is already in operation?
MS. MORIN: We want additionality as one of our criteria from the sustainability perspective. We have not been offered one that is already in operation to my knowledge. We typically contract for the output before COD.
MR. MARTIN: Anthony Davis, you are nodding yes. You agree?
MR. DAVIS: Yes. Additionality is important to us as well. We recognize that there are a lot of projects already, but as part of our sustainability goals and wanting to put more renewables onto the grid, we like to see new projects and we like to feel like we have had an impact.
MR. MARTIN: How long are you willing to wait for this power to start flowing?
MR. DAVIS: Forever. [Laughter.]
MR. MARTIN: Can the project be one year out? Two years out?
MS. MORIN: You can work it out so we have the bridge RECs. Once the deal has been signed, maybe we are 18 months away from the commercial operation date, depending on how far along you guys happen to be. We are flexible as long as we receive bridge RECs.
MR. DAVIS: We are comfortable with a developer who is trying to complete his facility within the next two years. That works for us for the most part. We only look for the RECs that come from this project, so we are willing to wait and we are patient.
MR. MARTIN: Renée Morin, bridge RECs sounds like testimony from the Chris Christie George Washington bridge trial. [Laughter.] What are they?
MS. MORIN: I don’t know who coined the term, but once the PPA is signed, it will have an expected operation date of 12, 18 or 24 months. We need the ability to receive RECs . . .
MR. MARTIN: . . . after the guaranteed commercial operation date?
MS. MORIN: They need to be green E-certified equivalent RECs.
MR. MARTIN: Jake Susman, where will you get those RECs?
MS. MORIN: Not everybody will do this.
MR. SUSMAN: Before I answer your question, Keith, I think the bridge REC concept is something that is good for the planet, and let me see whether I can make that linkage. There are enough companies now that have made sustainability statements about what they are going to do and by what date. They find themselves signing up to contracts for projects that may not, in fact, start operating until 2018 or even beyond.
But they have made those statements, and their shareholders are still holding them to account. Environmental organizations may also be holding them to account, so in order to honor their commitments, they procure a certain amount of RECs, either in the market or from some other project.
MR. MARTIN: Is your obligation to deliver bridge RECs in lieu of delay damages if the project is delayed?
MR. SUSMAN: It is possible to see both.
MR. MARTIN: Anthony Davis, do you have a guaranteed commercial operation date in the contract, and how do you define “commercial operation”?
MR. DAVIS: Yes. Commercial operation is when everything is pretty much brought on line. There might be a few terms in there that allow for maybe temporary . . .
MS. MORIN: . . . testing.
MR. DAVIS: Yes, some temporary testing or some equipment that might not be final, but typically commercial operation means the project is running full bore. We have not signed any contracts that define commercial operation as something less than 100% of capacity. For us, it has been everything or the project is not at COD yet.
MR. MARTIN: Ted Romaine, you are shaking your head no.
MR. ROMAINE: I do not think it needs to be at full capacity operation. We have signed contracts where we are able to declare COD if we are almost at full capacity. You still have to meet certain technical requirements of turbines installed, commissioned, gen-ties done, capable of generating and putting electricity on the grid.
We do not want to be declared in default where we are close to full capacity.
MR. SUSMAN: There is some fine-tuning that goes on during development all the way to the bitter end of construction. You could find yourself in a situation where you and the customer are better off if the project is a little smaller or maybe even a little bit bigger. So hitting it exactly 100% on the nose is not necessarily the best outcome.
MR. DAVIS: Usually we are signing deals that are for a percentage of the output from a large wind farm. For example, we may contract for 30 megawatts from a 200-megawatt wind farm. In that case, I am going to expect all 30 of those megawatts. That seems only fair to me.
MR. MARTIN: What happens if the project is delayed? It is not in commercial operation by the guaranteed date.
MR. DAVIS: Then there are delay damages. The amount is negotiated.
MR. MARTIN: If the contract is for 100 megawatts, how would the delay damages per day be determined?
MR. DAVIS: They are typically an amount per megawatt. I don’t know the typical equation. The developer provides it, so maybe our sellers have any insight from the developer side.
MR. MARTIN: Ted Romaine, do you have a number for us?
MR. ROMAINE: It is a negotiated amount.
MR. MARTIN: Is there a cap on the total delay damages?
MR. DAVIS: Yes, and that is another thing that is negotiated. It is usually a dollar amount per megawatt of capacity. Delay damages might run for a certain number of months, after which we would have a right to terminate the contract.
From a buyer’s perspective, we need delay damages to ensure the expected energy savings are received. We put the savings into our earnings forecast models. The CFO will be very unhappy if we don’t hit our targets.
MR. MARTIN: Jake Susman, does it sound like a deal is possible here?
MR. SUSMAN: I think we are very close to a deal, guys. I am pleased with the direction of the negotiation.
On Anthony’s last point, there are two kinds of natural governors on how far the contract can go with any kind of damages, delay or otherwise. First, there may be a seller letter of credit in place. Second, the buyer usually has a right to terminate before the numbers get too big.
MR. MARTIN: So the point about the seller letter of credit is the buyer will draw on the LC up to the face amount.
MR. SUSMAN: That’s the idea.
MR. MARTIN: Buyers, are you offering our sellers a delay in the guaranteed commercial operation date and start of delay damages if a force majeure event happens, and for how long?
MR. DAVIS: Yes. There is a force majeure out. Both what constitutes force majeure and the permissible delay are negotiated. I think we have been fairly lenient and understanding of what is considered force majeure.
MR. MARTIN: Sellers, are all the customary events considered force majeure for this purpose, or have you found buyers being stingy?
MR. ROMAINE: We do not find buyers pushing back on the force majeure definition. It has been pretty easy to reach consensus on that. We will require day-for-day extension on delay damages.
MR. SUSMAN: As wind and solar development has matured, sellers are less likely to take crazy technology risks or build in crazy places. The possibility of force majeure outcomes has narrowed pretty dramatically as the industry has matured.
MR. MARTIN: Ted Romaine, in order to win this contract, do you offer a guarantee that the project will be available at some capacity?
MR. ROMAINE: Absolutely. We are an owner-operator. We are really good at that.
MR. MARTIN: What is your guarantee level?
MR. ROMAINE: It is another point to be negotiated in each contract, but typically we will start out at a percentage in the early part of the contract and step that up after, say after one year. We like to have the first year to work out any kinks.
MR. SUSMAN: Here is another instance where the maturity of the industry helps and the science is so good now. Our predictive capabilities are so good. I think our customers can rely on us to produce, and we can be held accountable.
There needs to be some smoothing as you could have a bad wind year or a month or two when a couple of turbines are having issues. You want the ability in that case to smooth the availability over a longer period of time.
MR. MARTIN: So your guarantee period is one year, two years, longer? You get credit if you produce over the availability number to offset shortfalls later?
MR. SUSMAN: We want at least two years to smooth it out.
MR. MARTIN: I think Anthony Davis is saying no.
MR. DAVIS: I am just basing that view on the contracts I have seen. I know there is an availability guarantee. We see them today at a 80% to 90% level. But there are clauses to cover situations where a turbine needs to be taken down for maintenance and similar events that are also in the contract.
Every year there is a guarantee that says the seller will provide some percentage of the electricity it promised for that year.
MR. MARTIN: Will the seller’s availability guarantee have to run for the full term of the contract?
MR. DAVIS: Yes.
MR. MARTIN: We are down to our last five minutes. Audience, this is your chance to participate.
MR. BARCLAY: Buz Barclay from Rimon PC. Are there practical problems that arise with the project lenders when each buyer is taking only a fraction of the output?
MS. MORIN: I think it comes up. This is a negotiation, and we are both trying to get to an endpoint together, so there is give and take.
MR. ROMAINE: It is a high-wire act for us. We have done club deals. The onus is on us to make sure that we negotiate terms and conditions that are financeable for the lenders.
MR. SUSMAN: Three of the six corporate PPAs that we have signed have been multi-party projects. That is why I always encourage customers to be the anchor tenant. Be the first to sign up because you will get to dictate the lion’s share of the contract terms. That will also facilitate an easier financing.
MR. HAUG: David Haug from Arctas Capital. I am curious whether GE and HP are buying the full output of the plant or a pro rata 30 out of 200 megawatts or are they buying P50 or P90 or some other negotiated amount?
MR. DAVIS: We are buying a notional amount. If it is a 200-megawatt project, and we are signing up for 30 megawatts, we are hoping to get whatever is produced from that 30 megawatts of capacity. The availability guarantee says the seller will deliver at least 80% or 90% of that each year.
MR. ILLERS: Brett Illers with Yahoo. This is for the sellers. As utilities come back into the market for long-term PPAs because they have to meet rising RPS targets, how will that affect my ability to negotiate a corporate PPA?
MR. ROMAINE: Great question. Someone put up a slide this morning showing utility PPAs and corporate PPAs. The piece that was missing is what the utilities are doing on acquiring projects. That is a very active space right now for utilities as they look for assets to put in rate base. There is a robust utility market today if one looks at this larger picture.
MS. MCCAIN: Shelley McCain with Shell Energy North America. This question is for the buyers, and it is twofold. When you quantify savings, against what baseline are the savings measured? Brown power, retail, wholesale? My second question is when you make concessions in your terms and conditions, all the ones we just went through, what are the general concessions that you are willing to make?
MR. DAVIS: We measure savings against the wholesale hub price. We look at the net present value of the savings.
We are getting to a point where the PPA that GM likes is becoming set in stone because all our legal, technical, accounting and finance folks have weighed in. We give our terms to the developer and see what we need to fine tune.
MR. STEVENS: Bill Stevens with NJR Clean Energy Ventures. We are a long-term owner and operator. Question for the buyers: do you prefer a lower starting price with an escalator or a levelized price without any escalator?
MS. MORIN: An escalator is harder for us to put in front of our finance people.
MR. MURCHIE: Colin Murchie with Sol Systems, a developer and asset owner. For the buyers, you have gone through a long negotiation, six months, and you put up an LC. There were a lot of late nights. You are on the hook for a multi-million dollar contract. Let’s say the RECs are gone for the first few years of the project, and certain claims have gone with them.
Are there some claims that you would still feel comfortable making? Would you say this project would not exist but for us, or would you make a narrative claim where you detail the RECs went here, the energy went there, here is everyone’s role?
MS. MORIN: The RECs were gone, meaning . . . ?
MR. MURCHIE: Already sold to someone else.
MS. MORIN: I don’t think we would have gotten into the deal.
MR. DAVIS: We do not do the deal unless the RECs are a part of it.
MS. MORIN: We are not doing pure financial plays at this point. I know some companies do.
MR. HESSE: Balduin Hesse, Frontier Renewables. Question for the sellers: on the hub deals, when you go to finance the project, do you make an assumption around historical basis differential or do you buy a hedge? I am guessing you will get walloped for that risk to a certain extent when you go to finance the project. How do you fix it or do you just make an assumption around a certain differential?
MR. SUSMAN: In our case, that is what is nice about having a department of professional analysts. We have an internal view that we just take, and we decide how we want to price risk.
On July 27, 2017, the FCA announced that they would no longer compel or persuade banks to make submissions to LIBOR as from the end of 2021.