At the recent Freshwater Wind conference, the President of Power Advisory LLC John Dalton spoke of financing challenges faced by several renewable-energy projects. He spoke on power purchase agreements, requests for proposals, and feed in tariffs and related the experience of projects such as Deepwater Wind off Rhode Island and Wolfe Island Shoals in Ontario, Canada. Those confronted by the maze of financing concerns may find Dalton’s comments useful.
Long term agreements
It should be no surprise that a long term power purchase agreement or PPA will be critical for offshore wind. “Recently, when credit markets were more accommodating to renewable-energy projects, onshore wind projects could be financed on a merchant basis,” says Dalton. “Natural gas prices were considerably higher than today. Places like west Texas, even though it has a good wind resource, took comfort from high natural gas prices. A wind developer could go to lenders and say, ‘Here’s our view in terms of gas prices and these are the expectations of the pricing for a PPA. So, based on the availability of the production tax credit (PTC), we can make this work.”
For offshore wind, based on its economics, developers will need a PPA. “The key question here is from whom will the PPA be offered and how will it be offered? Will one use an RFP for power supplies to select suppliers, or a feed in tariff?” suggests Dalton. Utilities and other purchasers generally prefer requests for proposals or RFPs. From a utility perspective, the benefits are that with sufficient competition in the RFP process, there also comes a ‘market test’. “Utilities can go in front of a regulator and say, ‘We received several proposals, this one has the least-cost. It met the terms and conditions outlined in our PPA, so based on the competitive tension in the RFP process, we are confident we have secured the best offer for the specific resource.’”
From the seller’s perspective, Dalton says the challenge is the cost to participate in an RFP. “These can be high, in excess of $500,000. It all comes down to what is required in the RFP. We recommend to clients that there be a PPA in the RFP that would outline how risks are to be allocated among the various parties. The bidder should demonstrate support from equity investors and lenders. With all these requirements, there is a fair degree of due diligence required for developers, even the cost to participate in the process can be expensive. Most of these costs are fixed costs. So that for a relatively small project you have to amortize these fixed costs over a relatively few MWh, so the costs can be prohibitively expensive for these small projects,” he says.
The Ontario experience
Prior to its feed-in tariff, Ontario had a standard-offer process that applied to any project of 10 MW or less. “The notion here was to post a price and let the market respond, to see if developers think they can develop the project. With reference to nomenclature, ‘standard offer’ refers to a price that does not discriminate between different resource types. So you might say the standard offer price is going to be, for example, $0.112/kWh and you will receive that price whether the power comes from wind or a biomass project,” says Dalton.
The difference between a feed-in tariff and a standard offer is that a feed-in tariff is a cost-based price. As a result, it distinguishes between the underlying cost and performance of the different renewable-energy technologies. “I think the intent of the feed-in-tariff is most often to secure participation in the renewable-energy market by a wide range of different technologies. In Ontario, we saw the vast majority of projects for wind because it represents the lowest-cost resource to participate in a standard offer. The province did not distinguish between technologies, other than higher prices for photovoltaics,” he says.
To implement, feed-in-tariffs generally require action by policy makers and will require legislation for execution. “From our perspective, to make feed-in-tariffs succeed, one needs good information regarding the cost and performance of the technology. In developing a feed-in-tariff, you must know the capital costs, the capacity factor, and the fixed and variable O&M costs, then put these into a financial model, and make some assumptions regarding what it takes to finance the project. The resulting output is the appropriate Feed-in Tariff price.”
But if there is a relatively high degree of uncertainty with regard to the capital costs and the output of the resource, it is difficult to calculate a feed-in tariff that will reflect the actual costs to develop the project. This is the situation with offshore wind in North America; there isn’t reliable information regarding project capital and operating costs and projected project output, says Dalton.
From a consumer perspective, there is significant risk in terms of getting the advice wrong if the price is too high. “There is an asymmetry in terms of risks for consumers. We’ve seen in Ontario where they came out with feed-in tariff price, which was meant for roof mounted PV. But through direction from senior policy makers, it was applied to all solar PV projects of 10 kW and less. The price they came up was relatively rich, at $0.82/kWh, Canadian dollars. As you can imagine the market was very creative. Because there was no stipulation that these projects had to be on a roof, a lot of projects were developed on farms which reduced their costs or enhanced their capacity factor by putting in tracking devices. So no surprise, the developers realized a significant profit beyond what was viewed as reasonable for these ground-mounted solar PV projects. They recently proposed revising the price down to about $0.58/kWh.” [Editors: note the final price was $0.642/kWh.]
One cornerstone of a feed-in tariff is market stability. “The objective here from a European perspective, is to let the market know the price you will procure the resource for, and let the market respond. The notion is that with this revenue certainty, you can promote the development of technology suppliers in the various industries behind these technologies so that over time technology improvements drive down costs.
But a feed-in tariff that clearly misses the mark, and this is what appears to have happened in Ontario in terms of the ground-mounted solar PV price for projects 10 kW and less, “you get an over response from the market and from a consumer perspective, this can be a significant cost impact.”
So the feed-in tariff implementation for offshore wind in North America, has been limited to Ontario. “One contract has been awarded and that was to the Wolfe Island Shoals project. Prices were offered for a full range of renewable technologies for 60 days during the initiation period. During this period, developers were able to respond. The magnitude of the market response was such that, virtually all of the remaining available interconnection capacity in Ontario, about 2,500 MW of interconnection capacity, was consumed by the first round of projects. So going forward, the key issue in Ontario is whether you can demonstrate that you can economically connect to the grid. Part of that is going to be finding what it takes to build out the grid — to let the project connect.”
The Vermont and Maine experiences
Two other feed-in tariff programs, these in the U.S., are relatively modest. The Vermont program is limited to 2.2 MW projects and has a 50 MW program cap. The design recognized Vermont as a relatively small state and as a consequence, there was concern for managing the rate impacts from the market response.
The Maine program was similarly modest. It was limited to no more than 25 MW for any one utility, and because it was to promote development of community based projects, it mandated community participation.
The economics of offshore wind
Speaking in general terms of capital costs, these are about twice those of onshore wind. Greater cost uncertainty comes from the lack of experience in U.S. and Canada with offshore wind. Of course, the offshore wind markets are better developed in Europe, but not all of this experience is readily transferable given that we don’t have a well- developed supply chain here.
“So the challenge in the U.S. is to develop key elements of a supply chain. The bottom line, from a developer’s perspective, is the risk of pricing a project, participating in an RFP, and finalizing a PPA. You will have to specify larger contingencies, especially for the underlying capital costs of the project. That raises some issues for buyers.
“Deepwater Block Island has come up with interesting strategies for addressing these issues. If the developer had to embed these higher contingencies (i.e., for higher capital and operating costs and lower output) in its bid price, the price would be significantly higher. However, if a sharing and auditing mechanism is established then the developer can specify a price which he is confident that he can leave with and then share any savings with consumers. While such an approach wouldn’t be appropriate for conventional resources where these costs and technology performance are relatively well know, it is more appropriate for offshore wind if the desire is to provide a lower overall cost to consumers. However, the developer’s capital costs would need to be audited and this risk sharing is asymmetrical. Consumers receive lower prices if costs are lower (or output is higher assuming such a sharing mechanism is used for production). If in fact this approach is used for production then care should be taken to ensure that consumers don’t bear the risk of lower availabilities from poor project performance.”
|Deepwater Block Island
“The table shows some prices for offshore wind projects in North America. All are in terms of 2013 prices. [Editors note: Cape Wind has subsequently reduced its price.) One of the outliers here is the Bluewater Delaware project at $139/MWh. One unique provision in the Bluewater Delaware PPA, in my understanding, is that the developer is allocated 2.5 renewable energy certificates or RECs for every MWh. Whereas, in these and other PPAs, prices are for a fully bundled product. The purchaser or utility is getting energy, capacity, the RECs, and any future products that might be available such as CO2 offsets.”
For Bluewater Delaware, with RECs allocated to the developer, “if you value these RECs from $25 to $30, the price lines up neatly with Cape Wind. That value comes close to about $65 to $75/MWh. Other important variables here are the contract term or contract duration. A longer contract term lets a developer amortize that cost over a longer period, thereby potentially securing longer term debt.”
Deepwater Block Island
“It’s an interesting project. The starting point was an RFP issued by the state to select a preferred developer for offshore wind projects. This was issued in mid 2008. About seven parties responded to the RFP and ultimately Rhode Island signed a joint development agreement with Deepwater at the beginning of 2009. The joint development agreement provided that Rhode Island would commit to facilitating the PPA for the project which let it have the necessary revenue certainty. The developer in turn would be responsible for permitting the project, negotiating the ultimate terms of the PPA, and ultimately financing, constructing, and operating the project. So part of this legislation was passed to essentially let National Grid to enter into long term contracts for renewable-energy projects.”
“Let’s step back for a moment because one must be aware of what is going on in New England in terms of renewable energy. Markets there, other than Vermont, are restructured so it’s a competitive wholesale market with renewable portfolio standards. Renewable-energy project developers see two primary revenue streams: The wholesale price of power and what they can get from the REC market. The challenge became the amount of uncertainty in terms of what the wholesale price of power was going to be, and similar uncertainty with respect to the value offered by the REC market. Initially, the market was in deficit and alternative-compliance-payment-pricing provisions drove REC market pricing, essentially serving as a ceiling. So you’d expect the market on a spot basis to trade up to the alternative compliance payment pricing provision. The problem was there were no long term contracts for renewable-energy certificates,” says Dalton.
There was a significant disconnect between spot market prices for RECs and the alternative compliance payment (ACPs) pricing, with RECs trade below ACPs. “Some of it reflected the change in law risk, the uncertainty regulators or legislators could come back later and say, ‘Hey, this costing too much. We want to scale it back, as well as the uncertainty, in the value of a REC over a 10 to 15-year period.”
“We had this ideal of a competitive market. The problem that renewable-energy-project developers have is the uncertainly with what their revenue streams would be. Rhode Island and Massachusetts have applied similar approaches to address this situation which is based on having the Local Distribution Companies (LDCs) enter into long-term contracts for renewable-energy projects.”
The Deepwater Project was originally envisioned as two projects, a pilot that was to be off Block Island and a larger one off Rhode Island Sound. The legislation that enabled the Deepwater Block Island Project to go forward allowed National Grid to enter into a contract for a renewable-energy project of 10 MW or less that enhanced Block Island’s reliability and environmental quality.”
National Grid issued an RFP but only one party responded, recognizing that there already was a joint development agreement with the state. Deepwater was it. The challenge for National Grid became that there wasn’t a market test that enabled National Grid to say, ‘we got the best possible deal.’ There was one party that was in the best position to respond.”
National Grid’s initial evidence was not a ringing endorsement in terms of the economics of the project. “The price for bundled energy relatively high when compared to choices in the market.” National Grid essentially says, ‘if there are other policy objectives in play here, such as a desire to jump start an offshore wind industry, and the economic development benefits that come with doing so and the associated environmental benefits, then we can see a rational for approving the contract.’”
The bottom line in the review by the public utility commission was that because there was no market test, and because the cost benchmarks did not tell a compelling story in terms of economics for Deepwater, the underlying focus of the review was: What is the project developer’s IRR, internal rate of return? And is this IRR reasonable in light of project risks?
“Evidence from different parties suggested the IRR was higher than what might be needed. Deepwater provided some evidence that it was a reasonable rate return, but the commission rejected that evidence. Authorities made their decision, essentially, on whether the pricing was commercially reasonable. They could not determine that. The commission was concerned that the pricing would result in an unnecessary high IRR.”
“So what did we learn in terms of the Deepwater Block Island PPA rejection? There are serious challenges in demonstrating that offshore wind prices are commercially reasonable. After the contract was rejected, the Rhode Island legislature enacted a new law. Remember, Rhode Island had an obligation to facilitate the award of a PPA. The new law addressed concerns with the transparency of pricing, and changed the actual standard that the PUC would apply to assess whether the project should be approved.”
One thing that happened in terms of a risk allocation in the PPA was recognizing there were significant contingencies embedded in the price. “For example, it specified that if the construction cost is less than $205 million, cost savings would be shared with consumers. The price will go down. However, if costs are higher than the 205 million dollars, the developer bears the risks of the cost increases. One thing maintained in the PPA is referred to as a ‘wind out-performance adjustment clause.’ That means if the wind resource is better than that specified in the PPA, there would be a 50-50 sharing of the benefit. That is looked at on a going-forward basis. The PUC is directed to evaluate the economics of the project recognizing that this is a pilot project of 28 MW, the technology is an offshore wind project in relatively deep water, and meets the policy goals outlined in the legislation.”
”We had three different sets of legislative changes to let the project go forward. I’m not saying this would be needed in every jurisdiction. There were a few missteps in Rhode Island. But clearly, one needs supportive policy in the regulatory environment. To get this policy support, one must demonstrate the benefits of offshore wind. In addition, we must recognize the premium that one will pay for offshore wind relative to other renewable resources and this premium should be assessed in terms of the ultimate benefits for consumers. This includes price-suppression benefits. A study for Cape Wind looked at the impact of 468 MW project during peak periods. Obviously, that will move the market down the supply stack and by so doing reduce wholesale prices. This is a benefit to consumers. In addition, because these resources have higher capacity factors than land based turbines, there will probably be a closer coincidence of peak demand periods, yielding greater capacity value.
Of course, there are environmental benefits as well. One recent TV program focused on jobs and economic developments from offshore wind. Those are immediate and meaningful.
A final point is risk allocation and the PPA. It is different from other projects and this is probably most true for Deepwater. It is essentially the bleeding edge of project development.
Editors note: I took the liberty to edit Mr. Dalton’s comments to capture the essential ideas. Any misinterpretations are entirely mine.
Editor, Windpower Engineering
Mr. Dalton is a senior electricity market analyst and electricity policy consultant with over twenty-years of experience in energy market analysis, power procurement, project valuation, and strategy development. He offers extensive experience in the evaluation and analysis of electricity markets and the competitive position of generation technologies and projects within these markets including the assessment of the competitiveness of the underlying market, the development of power market price forecasts, the implementation of power procurement processes, and the development and evaluation of renewable energy policies. John has used market price forecasting tools to evaluate generation and transmission system investments in markets across North America.
Filed Under: Financing, News, Projects