Google signed long-term contracts with NextEra Energy to buy electricity from wind farms in Oklahoma and Iowa. It cannot use the electricity directly legally so it resells the electricity into the wholesale market, making the arrangement a form of hedge. The company is a large electricity consumer in both states because of its computer servers. Does this suggest another avenue for project developers? California is moving to allow utilities to halt electricity purchases during periods when contracted prices are above the current market price for electricity. How will California projects get financed? Why are utilities insisting that they have to treat long-term power contracts as leases of the power plants selling them the electricity? Does it matter, and can developers do anything about it?

A panel discussed these subjects at the annual Chadbourne global energy and finance conference in June. The panelists are Ken Davies, program manager at the time of Google Energy, Bob Shapiro, a partner in the Chadbourne Washington office, Bill Monsen, a principal with California-based consultancy MRW & Associates, Inc., and David Wittenburg, a director with Deloitte in Dallas. The moderator is Keith Martin with Chadbourne in Washington.

MR. MARTIN: We have three focuses of this panel, one of which is some very interesting news about two contracts that Google signed with NextEra Energy to buy electricity from wind farms that NextEra is planning to build in Iowa and Nebraska. Ken Davies, how long will the contracts run?

Google Contracts

MR. DAVIES: Both are 20-year contracts. We see value in getting a long-term embedded hedge. We want to lock in the current electricity price for 20 years. We are making capital investment decisions on the order of 15 to 20 years. We would like to lock in our costs over the same period. Electricity is our number one operating expense after head count.

MR. MARTIN: Can you say what the price per megawatt hour is in the two contracts?

MR. DAVIES: Unfortunately, I can’t, but it is discoverable through our public filings.

MR. MARTIN: So there is a website where we can get this information by doing a Google search?

MR. DAVIES: You can even use Bing.   [Laughter]

MR. MARTIN: You have very large servers in Iowa and Nebraska that use a lot of electricity, but you are not able to use the electricity you are buying by law because retail sales are not allowed in those two states, so you have to resell the electricity. How exactly do these contracts work as hedges for you?

MR. DAVIES: We are buying at the bus bar at a fixed or sometimes escalated price and then selling into MISO and soon to be SPP, respectively. We are getting exposure to the spot price, and we see that as a hedge to the price that we are paying at our data centers.

MR. SHAPIRO: You are selling at a wholesale spot rate and buying back at a retail rate?

MR. DAVIES: Yes. We are being charged a retail rate for what we actually consume, but we are often able as a large energy consumer to negotiate for a much lower retail rate than is paid by the average consumer. In many cases, what we are paying for the retail power is lower than what we are paying for the renewable electricity even today in a soft market. We are signing contracts with three to five years of fixed pricing, but over the life of the data center, those will reset. We are short-term fixed and long-term floating, so it will not be a perfect hedge in the near term. We are less concerned about hedging our cash flows on a quarter by quarter basis. We are more concerned about the long term.

MR. MARTIN: Both contracts are expected to cause Google to lose money on buying and reselling, at least in the short term, but you expect them to turn around over time and turn a profit over the entire contract term of 20 years. How do you protect yourself against the contracts ending early so you get the full benefit of your bargain?

MR. DAVIES: That is one of the things that we were very concerned about during negotiations. It is also one reason why we teamed up, at least for these first two, with NextEra, an experienced developer.

Most offtakers committing to buy electricity under long-term contracts will be concerned about what happens if the developer fails to finish the project or runs into difficulties after the project is already operating. Utilities are better equipped to step in and take over if the developer fails. We do not want to be in that position.

We are frankly less concerned about whether the project is built and operates during the early years. If the project falls behind schedule and we receive no power for the first five years, that might actually be okay with us. We are losing considerable amounts of money on every megawatt hour. We just want to ensure the project is there in the later years. We pay a lot of attention to counterparty risk and the credit support.

MR. MARTIN: Do the contracts have a notional account to track how far behind you are and how much ground you have to make up. Does NextEra guarantee payment of whatever the remaining balance is in the account if the contract ends early?

MR. DAVIES: If the contract were to end early, then there are obviously penalties. In terms of volumes, we stay completely away from any sort of notional volume. I see some on the panel nodding, and I think they understand that this is so we can avoid the need to mark the positions to market.

MR. SHAPIRO: I read that you are retiring the renewable energy credits or RECs rather than trying to get value for them. Why do that?

MR. DAVIES: We purchase carbon credits. We have been doing so since 2007, and Google is a carbon-neutral company. We would like to move away from carbon credits because they are a pure tax on us. So we have a shadow price of carbon. Every REC that we retire means we can buy fewer carbon credits on the spot market.

MR. SHAPIRO: So it is part of being a good corporate citizen in the environmental area.

MR. DAVIES: Yes.

MR. MARTIN: Since you expect the contracts to turn around but you are losing money at the start, what are wholesale
electricity prices today in the two states and how much do you expect them to increase over time?

MR. DAVIES: In MISO and SPP, wholesale prices are currently around $25 to $30 a megawatt hour. In some places, it is almost as if coal is still on the margin. These are very low prices, but we expect them to increase. When we started this a year and a half ago, we had a carbon assumption baked into our forward price curves. We no longer have that. But even removing the carbon tax, we still think the contracts will be profitable in the long term.

MR. MARTIN: The bank and tax equity markets are not keen merchant plants, and yet Google seems to be taking that risk.

MR. DAVIES: For us, it is a form of support for renewable energy. We have the ability to do what very few other people are willing to do in the market.

MR. MARTIN: How much capacity does Google have to enter into similar arrangements with other developers? I think you told me earlier you are prepared to enter into similar contracts in five or six states.

MR. DAVIES: We are not allowed to disclose our actual footprint. That said, it is public knowledge that we have data centers in the Carolinas, Iowa, Oklahoma and Oregon. So that is five. We have done two contracts, and I think everyone can do the math and figure out how many more we might be likely to do in the US as an initial matter.

MR. MARTIN: You said it was important to have an experience developer as the counterparty. How important is it to have a developer with a large balance sheet?

MR. DAVIES: Very important. We would like to be able to
support smaller developers, but we worry about their staying power over 20 years.

MR. MARTIN: So you will take merchant risk but not credit risk. Would you consider contracts with other energy sources — for example, solar, biomass, geothermal, fuel cells?

MR. DAVIES: Absolutely. We have both fuel cells and solar panels on our campus in Mountain View. The problem is that they are competing here against high PG&E retail rates while in Iowa and Oklahoma, they would be competing against industrial rates in cold states. They may make sense here. It might be a little longer before they make sense for our data centers in other locations.

MR. MARTIN: Google will only do agree to long-term contracts in states with an active spot market, correct?

MR. DAVIES: Right now, yes.

MR. SHAPIRO: Did you explore trying to make direct sales to your buildings by having a utility wheel the power to them?

MR. DAVIES: We are always in conversation with our utilities, and that is one of the subjects we have explored. The utility model is still to apply a large retail markup in most cases. As for wheeling, it is a little more than we want to take on.

MR. MARTIN: Ken Davies, thank you for joining us.

MR. DAVIES: It was a pleasure. If you want to know more, I encourage you on our www.google.com/green website, we have a full-length paper explaining what we are doing and the full rationale behind it.

California Curtailment

MR. MARTIN: Bill Monsen, you wrote in the Project Finance NewsWire in June about changes in market rules in California. The changes were approved by the California Public Utilities Commission and affect the forms of power contracts that utilities use with independent generators. You said these changes will have two effects. One is that renewable energy projects will be more likely to find their projects curtailed or knocked off the grid during periods when market prices for electricity are below what the utility promised to pay in the long-term power contract. In what circumstances will utilities have a right to cut somebody off like this?

MR. MONSEN: These are new rules. The contracts that will allow this curtailment are just being bid for in utility requests for proposals.

MR. MARTIN: So this form of economic curtailment is a risk only in new contracts. It does not affect any existing contracts?

MR. MONSEN: One California utility, Southern California Edison, contends that it has a right under its existing contracts to curtail projects when the contract price for electricity exceeds that it can pay in the spot market. The California Public Utilities Commission pretty much said, “We are not going to get in the middle of a contract interpretation issue. There are dispute resolution mechanisms in the contracts. If Edison does something that a counterparty does not like, then the parties can settle through those mechanisms.”

MR. MARTIN: That sounds like it will land eventually in court.

MR. SHAPIRO: Edison has been known for pushing the envelope. It is the biggest game in town. Its contracts have a provision that most people interpret as permitting operational curtailment and not economic curtailment. Edison then changed its form of contract to make its position more explicit. It basically said to the commission, “Oh, by the way, we have same right in our existing contracts.” This has put some stress on financing projects. The better view is existing contracts are not affected.

MR. MARTIN: In what circumstances can a project be cut off under the new form of agreement?

MR. MONSEN: Under the new rule, or the new proposed contracts, the utility will have the ability to curtail a project for economic reasons for up to a fixed number of hours.

MR. MARTIN: Per month? Per year? Per day?

MR. MONSEN: It is per year. However, the utilities are asking in their solicitations for generators to provide pricing for different levels of curtailment. They want generators bidding to supply electricity to indicate in their bids how many hours of curtailment they are prepared to accept, whether they require compensation for production tax credits during periods when the project is curtailed, and whether there is curtailment in both on- and off-peak periods.

At the end of the day, the utilities will want to curtail when the CAISO price for electricity is significantly less than the contract price.

One of the drivers behind the utilities wanting the right to curtail is the independent system operator is proposing to reduce the floor price for electricity from negative $30 to negative $300 per megawatt hour.

MR. MARTIN: What does it mean to have a negative price?

MR. MONSEN: It means the generator must pay to deliver electricity.

MR. MARTIN: Is there a cap on the quantity of electricity that can be curtailed?

MR. MONSEN: There is no cap on quantity under the solicitations. It is a cap on hours. The Public Utilities Commission said about 5% would be a reasonable number, but the utilities, other than San Diego Gas & Electric, went in another direction. They are asking generators how much the utilities have to pay to the generator to retain a right to curtail for up to X number of hours. For example, what is it for 50 hours? What is it for more than that?

MR. WITTENBURG: The generator will have the option to sell directly to the grid as opposed to a utility if the pricing is advantageous, correct?

MR. MONSEN: A generator could try to do that, but I don’t think its contract with the utility will allow it.

MR. WITTENBURG: I was being fascetious. It seems like a one-sided cap.

MR. MARTIN: Bill Monsen, what is the status of this rule? Is it final?

MR. MONSEN: Yes. The Public Utilities Commission issued a decision in April, and there have not been any applications for a rehearing. As a result, it is moving forward.

MR. MARTIN: So every new power contract signed in California will be subject to economic curtailment?

MR. MONSEN: Potentially. It is a form contract, and generators can try to negotiate away those curtailment rights, but I do not see the utilities willing to give much ground.

MR MARTIN: Is there any difference between how out-of-state generators and in-state generators will be treated?

MR. MONSEN: The out-of-state generator is covered if it has either a direct connection into the California ISO or does something called dynamic scheduling that makes it effectively a generator within the ISO system. An out-of-state generator who is selling electricity that is ultimately shaped and firmed would probably not be covered.

MR. MARTIN: Let’s move to the other effect of this rule change. The other effect is to expose renewable energy projects to potential penalties if they deliver more or less energy than is scheduled for a particular hour. How do the penalties work?

MR. MONSEN: It is not literally a penalty. The rule basically treats renewable generators more like traditional generators. If a renewable generator delivers more electricity than it was scheduled to deliver in a particular hour, then it is paid a different price per megawatt hour. If it delivers less than scheduled, then it has to compensate the ISO.

MR. MARTIN: It makes the revenues from a project less
predictable.

MR. MONSEN: That is exactly right.

MR. MARTIN: What is the potential swing in revenue for a typical project?

MR. MONSEN: The California ISO did some analysis. It concluded that if the rules had been in effect in 2009 to 2010, the swing would have been around $1.30 a megawatt hour. It is a small number. The swing would have been larger before 2009 because forecasting tools were not as good then. Generators can predict more accurately today what they are likely to deliver for purposes of scheduling.

MR. MARTIN: Wind projects are probably at greatest risk because it can be difficult to predict wind speeds. Do you know how much of a swing there is within an hour at a typical wind farm between what was forecast and what was delivered?

MR. MONSEN: It obviously varies by location, but a general rule of thumb might be between 3% and 5%.

MR. MARTIN: I was thinking that these penalties would push more wind farms and perhaps solar projects to install large storage devices, but the swings you are suggesting may not be large enough.

MR. MONSEN: That is exactly right. The cost of storage is still too large in relation to the potential hit to revenue. However, views could change over time if we see significant amounts
of curtailment as has happened in the Pacific Northwest this summer.

MR. MARTIN: What caused the curtailments in the Pacific Northwest?

MR. MONSEN: It has been an amazing hydro year in the Pacific Northwest, and electricity prices are in the toilet.

MR. MARTIN: Bob Shapiro, given what you have heard, what would you advise developers about their ability to finance California projects?

MR. SHAPIRO: The bottom line for lenders has always been that they can finance something if they can quantify the risk. To the extent that negotiated contracts have a maximum number of curtailment hours, lenders can evaluate that. They will probably use the maximum number as the base case, but the project should be financeable.

Of course, the higher the number of allowable curtailment hours, the smaller the amount of debt that a developer will be able to borrow to finance his project.

The big issue that Edison had when talking about existing contracts is “negative avoidance costs” - having to pay money to get rid of electricity. Edison made noises about trying to come up with a global settlement with existing projects. Its offer was that there would be no economic curtailment as long as the ISO spot price is a positive number. I don’t know whether it got many takers for existing contracts, but that may be a way to limit the curtailment risk. A generator could get an outside consultant to analyze how much risk there is of negative avoidance costs based on the project location.

MR. MARTIN: It sounds like the CPUC was wise to stay out of the middle of the dispute between Edison and generators. It sounds like abrogation of an existing contract for Edison to say, after the fact, “By the way, we can cut you off if we don’t like the price.”

MR. SHAPIRO: It is only wise if it does not affect the ability of projects to go forward. I think so far it has not, but the commission has never hesitated to intervene when needed, so although its current public position is it does not want to
get involved, if there is a hiccough, the commission might reconsider.

Power Contracts as Leases

MR. MARTIN: Let’s move to David Wittenburg from Deloitte. Utilities sometimes insist that they must treat power contracts with independent generators as leases of the underlying power plant for book purposes. Are the utilities correct, and what difference does it make?

MR. WITTENBURG: A PPA could take a number of different forms. The utility might prefer to treat the arrangement as a lease of the power plant in order to add its spending to rate base so that it can earn a return.

MR. MARTIN: So a utility might prefer to treat the arrangement as a lease. Doesn’t that then require the utility to show the obligation to pay ongoing rent as a debt on its balance sheet?

MR. WITTENBURG: Yes, if it is a capital lease. If the utility can structure the arrangement so that it is an operating lease, then the obligation to pay future rents does not show up on the balance sheet.

MR. MARTIN: An operating lease is what you have when you walk up to a Hertz counter at the airport and rent a car, and a capital lease is closer to borrowing money?

MR. WITTENBURG: The current state of the lease accounting rules is form driven and an operating lease and a capital lease are not terribly different in terms of how they are structured. But in terms of describing it, you got it right. Operating leases are currently off balance sheet, but there is a 99% chance that will change in the near term. Capital leases are on balance sheet, similar to debt.

MR. MARTIN: Is it possible today for a utility to have the best of both worlds by treating the arrangement as an operating lease, but also have a rate-based investment? Is that possible, or does one need a capital lease to have a rate-based investment?

MR. WITTENBURG: It depends on what the state regulatory framework where the utility is located, but we have seen a number of utilities take the position that power contracts are operating leases.

MR. MARTIN: What must be true of the power contract before a utility can legitimately say that it is leasing the power plant?

MR. WITTENBURG: Under the current rules, but without getting into all the technical detail, the power contract is a lease if the utility has a right to use the asset, either via hiring and firing decisions, making operating decisions or because of the pricing in the contract itself. I emphasize “current” rules because the Financial Accounting Standards Board is in the process of rewriting them.

MR. MARTIN: What do you mean by “the pricing in the contract itself”?

MR. WITTENBURG: The contract is more likely to be classified as a derivative or power contract, rather than a lease, if electricity is priced in a way that does not transfer any risks or rewards of owning or operating the facility to the utility.

MR. MARTIN: If the power contract has a capacity payment as well as an energy payment, is it more likely to be viewed as a lease? If it has only an energy payment, is it less likely to be a lease? Does it matter whether the utility has an option to purchase when the contract ends?

MR. WITTENBURG: Not necessarily. A purchase option could affect the accounting in other ways. For example, it could require the utility to have to consolidate the project company on its books. The consolidation rules under US GAPP are very complicated.

MR. MARTIN: Power contracts for wind and solar projects usually require the utility to pay only for energy and not also for capacity. When would a utility entering into such a contract take the position that it is leasing the wind or solar facility?

MR. WITTENBURG: When it has effectively a right to use the facility. It would probably take that position if another entity does not have a right to use a significant amount of output from the facility. It is more likely to be viewed as a lease if there is a capacity payment.

MR. MARTIN: So the key is whether the project is effectively dedicated to the utility. Does the term of the power contract matter? For example, what if the facility is expected to last 35 years, but the power contract is only for 10 years?

MR. WITTENBURG: A 10-year contract is more likely to be an energy contract than a lease.

MR. MARTIN: What difference does it make to the independent generator whether the contract is characterized as a lease or a power contract?

MR. WITTENBURG: The independent generator may also want the contract to be a lease. It may want to get the contract off its balance sheet. A contract that is not a lease is usually classified as a derivative, which would require marking the value to market at the end of each year. That can lead to volatility in earnings. For this reason, a generator may try to structure the contract so that it is considered an operating lease of the power plant. It will lead to more predictable earnings.

MR. MARTIN: So a generator may prefer to have a lease. Is there any circumstance where a generator would prefer to have the arrangement treated as a power contract?

MR. WITTENBURG: Yes, if the generator is trying to match costs. Let’s say the form of fuel contract the generator has requires it to mark the fuel contract to market each year. It might be better in that case also to mark the power contract to market.

MR. MARTIN: You mentioned two other horrors. One is that the contract could be characterized as a derivative. What are the consequences for the generator and for the utility if the contract is treated as a derivative?

MR. WITTENBURG: There are three possible outcomes in terms of accounting for the contract in that case. First, the default accounting is the contract must be marked to market.

MR. MARTIN: Every year the generator must mark the contract to market, meaning record on its books the current value of the contract, and that affects the generator’s earnings.

MR. WITTENBURG: As an example, suppose your contract price was $50 when you executed it. That was the market price for electricity. Forward market prices go up to $80. That leads to a $30 addition to earnings. What goes up can also come down. You can imagine the potential volatility over the term of the contract.

MR. MARTIN: Nobody likes that except, as you said, in the case where the fuel contract is also being marked to market.

MR. WITTENBURG: Yes, so that it gives some level of balancing the account, although the balancing is not perfect.

MR. MARTIN: And a utility? Does it care whether the contract is a derivative?

MR. WITTENBURG: The utility normally gets to pass through all of its costs to its ratepayers, so it does not care as much, except there is an administrative burden in terms of having to mark the contract to market, particularly if it is a 20-year
contract.

MR. MARTIN: So the utility would also have to mark to
market?

MR. WITTENBURG: Yes, if the contract is classified as a derivative. Let me take a step back. If the contract is a derivative, there are three possible outcomes. The first is that the contract must be marked to market. The second is that you can call it a hedge and get special accounting if you meet certain requirements. The third, if you are talking about a physical contract as opposed to a financial contract, is that you can scope it out altogether and the utility can call it a normal purchase of electricity or the generator can call it a normal sale of electricity if certain requirements are met.

MR. MARTIN: Scope it out meaning ignore all the stuff we just talked about?

MR. WITTENBURG: Ignore all of that and not have to mark the contract to market.

MR. MARTIN: That seems like the best approach for both parties.

MR. WITTENBURG: A lot of companies try to do that. The only problem is that it is an election. It is not an automatic scope out. You have to maintain the facts that made the election possible. The utility must demonstrate that it is not reselling the electricity other than to its own ratepayers. A utility can probably demonstrate that unless it is contracting for amounts beyond its projected load requirements.

MR. MARTIN: All of these rules are about to change because the US is moving to international accounting standards. When is that change expected?

MR. WITTENBURG: That is the million dollar question for the accounting industry. The US Securities and Exchange Commission issued another white paper last month in which it said it supports movement toward international standards, but not full-blown conversion, but it did not give a date. That said, there are a number of projects underway, many of which will probably become standards this year, including for leases, financial instruments and revenue recognition.

The approach the SEC is taking has been called “condorsement.” It hasn’t fully endorsed the international accounting standards, but is in favor of convergence. The commission has not said that all SEC registrants must adopt IFRS by a certain date. It said it is still studying the subject and supports meshing US GAAP with IFRS.

MR. MARTIN: The direction in which this is moving on convergence is what? There will no longer be a distinction between operating leases and capital leases? Everything will be a capital lease?

MR. WITTENBURG: Not necessarily. A capital lease will remain as before. If the arrangement is a capital lease, then the lessee will have to put the asset on its books, and it will treat the obligation to pay future rent as a form of debt, just as if it owned the asset. The operating lease model that is currently proposed will put the right to use the asset on the books, not necessarily the asset itself. The right to use the asset would be recorded on the lessee’s books at its present value as an asset, and the present value of the expected future rents would be recorded as an offsetting liability. The tricky part is what happens if there is a renewal option. It will not be as simple for the lessee as determining what its obligation is and putting it on the balance sheet and then forgetting about it. The lessee will have continually to evaluate whether it is more likely than not to renew and adjust the present value of the lease obligation accordingly.

MR. MARTIN: So there will still be distinctions among derivatives, different types of leases, energy contracts, all these things will still be relevant under the international standards, but the tests may be a little different.

MR. WITTENBURG: Yes. As you can imagine, most of the companies in this space today have thousands, maybe tens of thousands, of operating leases depending on a company’s size, and we are not talking about just PPAs. The exercise of
evaluating everything once the standards change will lead to a lot of heartburn.

MR. MARTIN: This is a boost for the accounting industry. You have the Sarbanes Oxley Act and now this. It seems like this could double the big four firms in size just to handle the workload.

MR. WITTENBURG: Not only is it going to present a lot of opportunities for the accounting firms to assist, but it will also be a monumental task for companies to get their arms around the effects. They are broad reaching. Putting all of these leases on balance sheets may affect debt ratios and covenants in existing financings. Companies need to start focusing on the potential effects now. ¥