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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:
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.
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
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2. developers and the increased sophistication of utilities has driven a narrowing of the range of
proposed prices in RFPs.
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.
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
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3. 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.
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.
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4. 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
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5. 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
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6. 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.
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7. 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
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8. 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.
---
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.
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