How project developers form their bidding strategies – and what it means for prices and the industry.
Greer Mackebee is a recent graduate of Stanford Univ. Law School, Palo Alto, Calif., and an associate attorney (energy and infrastructure practice) in the Washington, D.C. office of Orrick, Herrington & Sutcliffe, LLP. Justin Bowrsock is Research Director for the Steyer-Taylor Center for Energy Policy & Finance at Stanford Univ., where he served recently as leader of the Electric Power Commercialization Finance Project (EPCF). James Stack is Portfolio Manager for Energy Procurement at City of Palo Alto Utilities, a municipally owned electric utility in California.
In the renewable power industry, the relationship between utilities and project developers is crucial, yet at this point little understood. Based on numerous conversations with wind and solar project developers, it appears that many utilities do not understand how developers approach the competitive procurement solicitations (commonly known as requests for proposals, or RFPs) that utilities conduct to contract for new generation resources. To shed some light, this paper will address two related issues concerning RFPs for renewable energy:
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Bidding Behaviors. First, how have project developers changed their bidding strategies over time, as competition has grown not only in the number of developers, but also in the availability of sites for viable projects?
Energy Prices. Second, what can we learn from the prices, project sizes, and technology choices exhibited by the bids that developers submit in response to utility RFPs?
To answer these questions, we will turn to two sources: a) RFP bidding behaviors exhibited by renewable energy developers as collected through phone interviews with active wind and solar industry professionals, and b) a decade's worth of renewable energy RFP bid data collected by City of Palo Alto Utilities (CPAU), a municipally owned California utility located in the heart of one of the most dynamic and competitive renewables markets in the United States.
For the purpose of this paper, CPAU has agreed to open its internal RFP bid data from the past decade for analysis - a decision that is truly rare in an industry where both developers and utilities traditionally keep this kind of business intelligence confidential. This data set presents a unique opportunity to examine some of the industry's major trends over the last decade.
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And what can this data tell us, first about developer behavior and second about price trends for renewable energy?
Overall, as competition between project developers has increased, we find that bidding strategies have changed substantially. Until recently, many developers employed a bottom-up, pro forma approach, adding up costs to arrive at a reasonable bid offer. But today, because of intense market competition, many developers use a top-down, bid-to-win to strategy. And this strategy, whereby developers bid a price calculated to win the RFP (and as coupled with consolidation among development firms), has helped to decrease bid prices.
Here we have analyzed graphically the pricing, size, and technology data from bids received by CPAU during its last seven RFPs for renewable resources. These data provide direct evidence of the dramatic decline in and convergence of solar PV pricing, which can be compared to the relatively flat trajectory of non-solar technologies' pricing.
This trend could be interpreted as reflecting the increasing liquidity of the market. Put another way, as the renewables industry has matured, both the increased level of competition among developers and the increased sophistication of utilities has driven a narrowing of the range of proposed prices in RFPs.
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But while lower power prices are beneficial both to ratepayers and utilities, an important question remains unanswered: can winning developers actually build projects at those prices? Many project developers suspect that the low-price bids seen in the winning RFPs are not deliverable. That is, that the RFP-winning developer ultimately will not be able to build the wind or solar project at the low price it bid, and, thus, will default on its agreement with the utility.
Top-Down Bidding
In the vast majority of renewable power projects today, developers sign long-term power purchase agreements (PPAs) with utilities, generally twenty years or longer, by which the utility commits to purchase, at a fixed rate, all energy, capacity, and environmental attributes (e.g., Renewable Energy Certificates) whenever the generation asset is producing. For many of the nation's electric utilities, a request for proposal marks the primary means of procuring wind, solar, and other renewable energy PPAs. For the developer, the signed PPA with a credit-worthy utility creates the linchpin toward obtaining project financing and actually building the project.
And today, because of market competition, many developers now use a top-down approach to forming and submitting RFP bids.
Unsurprisingly, the developers interviewed for this article agree that today's marketplace for renewables is highly competitive, and most believe that the number of utility RFPs has decreased and will continue to shrink in the future. This sentiment finds support in the data. In states with Renewable Portfolio Standards (RPS), most utilities already have executed contracts for enough renewable capacity to meet their targets. And in states without RPS mandates, the low marginal cost of electricity - itself primarily a function of low natural gas prices - makes it very difficult for renewable resources to compete.
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These factors create a buyer's market; even small utilities that issue renewable power RFPs may receive upwards of 40 bids. Developers need the PPA in order to get project financing. And with intense competition and few expected future opportunities to obtain a PPA, developers are focused on bidding the lowest price possible. Making matters worse for developers, most approach the RFP process with roughly the same assumptions for the cost of major equipment and the cost of capital. Therefore, RFPs have become, in effect, a reverse auction mechanism in which the bids most likely to win are those with the lowest price per megawatt-hour.
This dynamic creates challenging incentives for developers. In a bottom-up approach, developers calculate a bid price based on known or estimated costs. For example, the developer might get quotes from major equipment manufacturers and from engineering, procurement, and construction (EPC) contractors for the balance of system costs. Using these inputs, the developer arrives at a bid price based on actual or expected costs.
As the competition for PPAs increased, some developers began bidding prices calculated to win the RFP. For these developers, it became "shoot first, ask questions later." Be sure to to win the critical PPA. There will be time later to worry about how to build the project at that price.
After winning a PPA, these developers then attempt to dictate the price to the major equipment manufacturers and to EPC contractors. This strategy also forces developers to ruthlessly squeeze costs out of the project. The top-down approach to bidding is inherently riskier because the developer may not be able to squeeze its costs down in order to make the project economical to build. There is a long list of developers and projects that have defaulted on their PPAs when the economics of the project were poor.
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In some cases, developers have been able to go back to the utility buyer and negotiate a price increase. In other cases, developers have had to walk away from their projects and write off their investments. In addition to losing money invested in developing the projects, these developers also may forfeit collateral they provided to the utility under the terms of the PPA. Most utilities require winning bidders to provide security both during the development period (i.e., before the project is built), and during the delivery term (i.e., when the project is operating).
The amount of collateral required by the utility affects how aggressively developers can bid. In RFPs where the development term security is low, the winning developer effectively has a low-cost call option on a PPA. In this case, the decision to bid aggressively can be viewed as rational. The developer is betting, through the collateral it posts to the utility, that it can drive its costs down sufficiently to make the project economic or sell the project to another developer that thinks it can deliver the project. Top-down bidding represents a market-wide change over the last five to seven years as the supply of projects has exceeded the number of available contracts. When the market was not as competitive and wind and solar technology was not as commoditized, margins were higher, and there was less pressure to trim costs at every step of the development process. Before the wave of new developers entered the marketplace, RFP bidding remained pro forma-driven. However, beginning around 2007, this approach became less and less successful for many developers in open RFPs. The largest developers with lower costs of capital could still win utility RFPs, but overall PPA prices came down at a rate at which most developers could not compete. By 2010, most developers had fully embraced a top-down bidding approach to stay competitive in solicitations.
While the trend toward top-down bidding has been observed across the market, bidding behavior still varies somewhat depending on the character of the developer. For example, a pure-play developer without the capacity to operate a project will assess risks differently than a diversified independent power producer (IPP) or a large wind or solar operator. Some larger developers will choose to avoid RFPs and instead purchase projects from smaller players who win.
With supply and demand conditions as they are today, utilities are in a position to get very favorable PPA pricing. However, as bids have become more aggressive, utilities have recognized the increase in default risk by increasing the required development security for winning bids. By increasing the cost of the developer's PPA "option," the utility lowers its risk that the project won't be delivered and that it will have some financial compensation if the developer does default.
And it appears also that in recent years small development shops are not bidding into RFPs and winning PPAs as often as in the past. However, at the same time many of the largest developers with the capacity to operate projects are no longer in the business of pursuing greenfield development opportunities. Instead of entering into an RFP, a large IPP may choose to acquire the rights to buy a project after it wins an RFP. Taking this into account, several developers note that bidding partnerships have increased as security requirements for winning bidders have increased. Because an RFP-winning small-scale developer will likely turn around and sell the PPA to a larger player, small developers may bid even more aggressively under the assumption that they will never be the ones to actually seek financing or build the project.
Utility Motivations
Utilities employ a range of different processes for their RFPs. A poorly designed RFP can increase the risks for both the issuing utility and developers. An RFP with low collateral requirements, for example, can increase the number of bids that are unlikely to be viable.
And because many utilities today buy renewable power for regulatory compliance, it stands to reason that a utility does not want to be in a position where its contracted projects do not come online when promised. Therefore, a sophisticated utility often will try to set up its RFP to screen out the developers who don't have the wherewithal to build the projects they bid, such as by by instituting heavy requirements for interconnection or security of collateral..
For developers, the nature of the utility issuing the RFP factors into their bidding strategy. For many large investor-owned utilities (IOUs), the reverse auction mechanism employed is driven by price alone. Publicly-owned utilities (POUs), on the other hand, may factor in other considerations. While these POUs have a fiduciary duty, they are publicly owned, allowing them to consider the nuances of counterparty liability and not necessarily be driven by the absolute lowest price. With this in mind, discussions with POUs (and smaller generation and transmission cooperatives), while still demanding, tend to be more bilateral than with IOUs, where there is usually little back-and-forth.
By contrast, larger IOUs retain significant negotiation power and frequently offer take-it-or-leave-it PPAs, leaving developers with a difficult decision as to whether the project is worth the additional risks the utility is shifting. Some of the contract terms insisted upon by these larger utilities can prove onerous to the point that developers might be unsure as to whether the project is financeable. If that indeed is the case, a utility's aggression might backfire in the long run, as it may have to purchase more expensive power elsewhere or face burdensome regulatory compliance costs.
Not surprisingly, for all these reasons, many developers prefer to sign PPAs with POUs rather than larger and more powerful IOUs.
In addition to its status as an entity, the size and experience of an RFP-issuing utility may impact how developers approach the solicitation. It stands to reason that larger, more experienced utilities will conduct their RFPs with more process and formality. However, problems with the come-one-come-all style of RFP arise no matter how big and experienced the utility is. To complicate the calculus, a large IOU might not actually want a developer that wins its RFP to succeed. The IOU might want the project to default so that it can pocket the development security and then build and rate-base the project itself.
To complicate matters even further, a utility might not care how much energy is actually delivered by the project. That's because up until recently, wind and solar power were offered only at a premium to wholesale prices, meaning that utilities seeking to comply with regulatory obligations often would focus on the PPA - the obligation to buy the power - and not how much was actually delivered. Apparently, an RFP is not always about signing the contract and offtaking energy. This potential snag leads some large developers to avoid open RFPs altogether. These developers may instead wait and go after the winner of this type of RFP to acquire PPA-winning projects.
Head-to-Head Negotiations
The purchase price for electricity is clearly the most important component of any PPA. However, the allocation of risk between the seller and offtaker set forth in the contract remains crucial to preserving a project's "financeability" and long-term health.
In general, it is a safe assumption that a PPA signed through an RFP process will be more onerous on the developer than one executed through bilateral negotiations. However, pure bilateral deals are very difficult to find, and bilateral negotiations are today unheard of for smaller, more inexperienced developers.
Because one-on-one negotiations usually lead to the utility taking on more of the risk usually shifted to developers during the RFP process, the additional layer of risk resulting from a small developer's relative inexperience will not be acceptable to the contracting utility. A more common arrangement is one in which a POU elects to solicit bids from a small group of familiar developers rather than from the development community at large. This situation can be beneficial for both the utility and the chosen developers. Because the risks presented by familiar parties are already known, the utility can more efficiently evaluate bids received. At the same time, a developer chosen to be in this small group of invite-only bidders stands a much better chance of winning a PPA. This bounded auction process is still competitive, but each developer likely knows the remainder of other bidders well and can evaluate their positional advantages.
Limited access to project data makes it difficult to assess the degree to which the RFP mechanism may affect project health. However, some industry experts posit that projects financed on RFP-based PPAs are more likely to suffer delays (and possibly also defaults) than those projects based on bilaterally negotiated offtake agreements.
Today, most developers tend to believe that substantially marking up the utility's standard contract will poison any bid into a competitive solicitation. In fact, with heightened competition, developers (particularly inexperienced ones) can feel pressured to accept the standard utility contract as provided - without regard for whether the project will be financeable on those PPA terms - simply to be assured of advancing round-by-round through the RFP process, If each developer's ultimate goal is to win the RFP and sign a PPA, then its interim goal certainly must be to make the utility's short list of bidders.
Solar PV Bid Prices
We have considered five different categories of renewable energy projects: 1) wind, 2) solar photovoltaic (PV), 3) landfill gas (LFG), 4) geothermal, and 5) biomass. And upon studying the RFP bid data made available by Palo Alto, across the five technologies, we find that bid prices - which in 2005 were seen to span a range from $50 to $200/MWh - had converged by 2013 to a range of between $60 and $100/MWh.
These data could be could be interpreted as reflecting the increasing liquidity of the market. Put another way, as the renewables industry has matured, both the increased level of competition among developers and the increased sophistication of utilities has driven a narrowing of the range of proposed prices in RFPs.
Examining Figures 1-3, the most apparent trend is the strong downward trend in solar photovoltaic (PV) bid prices over the last decade. Aside from a small uptick in the 2009 RFP (when the number of solar PV bids was quite small), the data show a monotonic decline in bid prices - from a flat price of more than $200/MWh in 2005 to about $75/MWh in 2013. While biomass, geothermal, landfill gas, and wind bid prices have held relatively steady over the last decade, solar PV bid prices have fallen dramatically, transforming it from the high-price resource to the co-market leader (with wind) in just a few years.
Solar PV pricing is obviously heavily influenced by module cost. Not surprisingly, the price drop observed in Figures 1-3 mirrors the observed drop in solar module prices over the same time period. Over the past decade, the efficiency and quality of manufactured solar panels increased, while panel prices plummeted. As shown in Figure 4, average capacity factors for solar bids in CPAU's RFPs increased from 20 percent for the earliest projects to more than 28 percent for those with a commercial operation date (COD) planned for 2016. At the same time, solar module prices fell from approximately $5/Watt (W) in 2006 to around $0.85/W in early 2012. Today, the global module spot price has fallen even further, hitting a low of $0.63/W in early 2014. Nationally, these declining module costs have led to a similar decline in levelized PPA prices for solar PV, which have fallen by a steady $25/MWh per year on average since 2007.
Utility-scale solar projects were very rare prior to 2009. But since that time, solar PV has become almost a commodity itself. Today, solar PV presents virtually no technological risk to developers and utilities; over the last decade, the technology has amassed a long and reliable track record. While this serves to lower the cost of capital for new solar projects, it adds a layer of difficulty for developers trying to stand out amid a sea of solar RFP bids.
While Figure 1 shows that the range of bid prices for solar has decreased markedly from CPAU's earliest RFPs, a substantial spread persists. For projects with 2016 start dates, solar bid prices ranged from $65/MWh to more than $100/MWh. Part of this spread may be due to larger developers having access to lower-cost financing, and having the buying power to receive the lowest prices on modules and other hardware. However, another factor in this spread may be the differences in interconnection costs - which can vary dramatically from one site to another and are often the most significant non-hardware costs associated with a solar project - between different project bids.
Wind Bid Prices
In contrast to the dramatic decline in solar PV bid prices, wind bid prices remained relatively steady in CPAU's RFPs over the last decade. This pricing stability is notable given the many regulatory and legislative upheavals that have beset the industry over the same period - in particular the start-and-stop nature of the federal production tax credit (PTC). Examining Figures 1-3, however, wind prices in CPAU's RFPs did not show substantial PTC sensitivity over the last decade. This pattern may indicate either risky bidding behavior or developer confidence in the ultimate legislative outcome.
Over the last three decades, capital cost reductions and performance improvements have combined to significantly reduce the cost of wind generation; however, this trend has not been without deviation. From 2004 to 2009, increased capital costs (driven by turbine supply shortages and increasing commodity costs) outweighed performance increases, leading to an overall increase in the cost of wind power. This effect can be seen in the moderate bump in wind bid prices for projects with 2009 and 2010 CODs in Figure 2. In recent years, reductions in turbine prices, combined with advancing technology and increasingly pro-buyer purchase terms, have pushed down total project costs. Wind PPA prices have followed: nationally, wind PPAs were signed for an average of $70/MWh in 2009; however, by 2013 prices had decreased to about $25/MWh - a record low.
From Figure 4, it is clear that little improvement has been observed in the average capacity factors of wind projects built after 2005. However, this is not necessarily indicative of turbine efficiency stagnation. Rather, as the sites with the best wind resource and transmission access get built out, the average quality of the wind resource in which new projects are located has declined; between 2009 and 2012, this decrease in wind quality was especially significant. Controlling for the influence of wind resource quality, wind turbine capacity factors have in fact increased steadily over the past decade.
Some wind developers have seen capital costs on projects holding steady or drifting slightly higher than in previous years - driven by increases in interconnection costs in some regions. At the same time, turbine efficiency is improving significantly, driving steady but limited discounting of the levelized cost of energy (LCOE). However, according to some wind developers, the overall appeal of developing wind projects has decreased in recent years because of these wavering capital costs, the industry-wide move toward poorer wind resource sites, uncertainty around production tax credit (PTC) extension, and lower wholesale electricity prices.
Near-term Outlook
In thinking about how the price trends explored above may continue or shift in the coming years, it is important to bear in mind that, while national averages are useful in some respects, project pricing is inherently regional.
In markets where there is new demand, such as through the adoption of a new or an increased RPS, like in California and Hawaii, or in areas where EPA's Clean Power Plan may require large shifts away from coal power, we can expect that new greenfield opportunities will arise to meet that demand.
And by contrast, in historically active markets where demand for renewables nevertheless appears relatively stagnant (such in as Arizona, Texas, parts of the Northeast, and in the case of wind, the Midwest), there arises a physical constraint on new projects simply based on geography and lack of transmission.
New projects naturally gravitate to the best resource sites in any given area, so the number of greenfield opportunities decreases as a market matures over time.
Wind Prices. The National Renewable Energy Lab (NREL) estimates that the LCOE of onshore wind could fall by 20-30 percent over the next two decades. However, other factors may push wind costs higher once again, including the continued movement towards sites with poorer wind resources and local transmission conditions.
With current turbine technology, there are very few opportunities for new greenfield wind projects on the West Coast, particularly in California. On the other hand, the Department of Energy (DOE) notes that if U.S. developers begin to deploy taller wind turbines - those with hub heights of 110 meters or more, as exist already in Germany and other parts of Europe - we could see an expansion of areas with the technical potential for wind deployment by as much as 54 percent.
In addition, opportunities for the expansion of wind power in the Midwest and Texas exist because of the continued availability of high resource land. Going forward, it is reasonable to expect that sites closest to existing interconnection infrastructure will be the cheapest and will be built first. As new transmission projects are permitted (some of which may ultimately not be constructed), opportunities for greenfield development may arise proximate to these new transmission routes.
Because wind, as a relatively well-established industry, has progressed farther down its technology learning curve than other technologies (including solar PV), the market might currently be showing close to the lowest wind pricing possible. While turbine efficiencies may continue to improve and capital costs may continue to drop over time (just as in more mature industries), a substantial price reduction should not be expected based on competition alone. Furthermore, the likely expiration of the PTC in the near future may more than offset these efficiency and capital cost improvements. On the other hand, EPA's Clean Power Plan has the potential to drive an increasing number of coal plant retirements and simultaneously push up demand for wind generation. Ultimately, it seems clear that the market referent for wind will not be driven by competition in the wind sector alone.
Solar Prices. The first factor to consider in thinking about the future of solar PV pricing is that current panel prices are already very low. Most analysts forecast that solar PV pricing will continue to decrease in the next few years as PV hardware costs (particularly non-module costs) continue to fall and as module efficiencies continue to improve. However, this expected trend is complicated by potential additional tariffs on Chinese-manufactured panels, by reduction of panel oversupply that has persisted in recent years, by increased market consolidation, and by the likely sunset of the 30% federal investment tax credit (ITC).
Although there are still greenfield opportunities available for solar on the West Coast, these opportunities may be more expensive than in past years, as the locations with the best solar resources and lowest interconnection costs increasingly get built out. Additionally, because developers must bid projects based on an expectation of where the market price for panels will be when construction begins (which is often up to two years after the initial bid is submitted), rising panel prices (or at least a slowing decline in prices) may put the economics of projects under development in jeopardy. If rising panel prices lead to an increase in the project default rate over the next few years, PPA prices could increase across the board.
Assuming that the 30 percent ITC is not extended past 2016, solar PV pricing can be expected to rise sharply in 2017, which will likely lead to a pause in solar deployment in the U.S. Such an event, however, would have the potential to cause another panel oversupply situation, which could drive prices back down.
Combined with continued improvements in hardware costs and efficiencies, these factors are likely to pull solar PV pricing back down to its 2016 levels within a couple of years of the 30 percent ITC sunset.
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Palo Alto's Internal Data Set
A unique opportunity to study renewable RFPs.
As a chartered municipality, the City of Palo Alto can claim a tradition of over 100 years of public power service. And as a fairly progressive city in a progressive state, Palo Alto also enjoys a long history of leadership on sustainability issues - renewable energy in particular.
The City of Palo Alto Utilities (CPAU) began its renewable energy efforts in the early 1980s with the introduction of a solar water heating program. In 2002, the City Council adopted a renewable portfolio standard (RPS) mandating that CPAU procure renewable energy resources equivalent to at least 20 percent of retail sales by 2015 - long before public utilities in California were required to adopt such measures. The City Council later raised the RPS requirement to 33 percent by 2015. And in 2013, Palo Alto became only the second city in the U.S. to adopt a carbon neutral electric supply standard.
To achieve these lofty goals, CPAU has issued Requests for Proposals (RFPs) for new renewable resources on roughly an annual basis since 2005. By preserving the bid data from each of these RFPs, CPAU has amassed a data set that paints a vivid picture of the evolution of California's utility-scale renewables industry.
In each RFP, CPAU typically solicited bids to contract for projects that would generate between 20,000 and 80,000 megawatt-hours (MWh) per year. CPAU did not, however, set a target level or an upper limit on the total volume of energy that it would procure through each RFP. The contract terms for each bid could range from five to 30 years. And proposal pricing was almost always provided as a flat, non-escalating price per MWh, or as a price per MWh that escalated at a fixed rate (usually 1.5 percent) per contract year. (The very limited number of proposals that provided index-based pricing, or some other pricing structure, were excluded from this analysis.) Finally, while many utilities conduct resource-specific RFPs, each of CPAU's has been open to any generation resource that meets California's RPS eligibility criteria.
Pricing data from bids received by CPAU during its last seven RFPs for renewable resources are shown in the main article text in Figures 1-3. Levelized costs per MWh were calculated based on bid data submitted by developers, and assume an annual inflation rate of 1.5 percent and a discount rate of 8.0 percent.
Because executed PPA prices often reflect market conditions at the time an RFP bid is submitted, the bid submission date can be more relevant than a project's projected commercial operation date (COD) when examining PPA prices. However, projected COD is relevant for an analysis of installed prices and capacity factors, as it incorporates developers' projections of technology costs and efficiencies.
With this in mind, Figures 2-3 display the same data set organized by COD and bid submission date, respectively. Figure 4 represents the back-calculated capacity factors for wind and solar project bids, organized by COD. -GB, JB, JS
Lead image © Can Stock Photo Inc. / opal