utility-scale solar: the path to high-value, cost-competitive

UTILITY-SCALE SOLAR:
THE PATH TO HIGH-VALUE,
COST-COMPETITIVE
PROJECTS
How to Optimize the Economics of Utility-Scale
Solar Photovoltaic (PV) Facilities
In partnership with:
i
TABLE OF CONTENTS
Contents
ii
Key Takeaways 1
Introduction
2
Utility-Scale Solar Project Costs 2
Implications of Project Design on Levelized Cost of Energy 5
Fixed Tilt and Single-Axis Tracking 5
Economies of Scale 6
Location 8
Project Financing 10
Fixed Tilt System Orientation 12
Putting It All Together
13
Design Considerations for Resource Planners 14
Maximizing Procurement to Minimize Cost 15
Frequently Asked Questions 17
About Recurrent Energy 20
Appendix A: LCOE Price Expectancy Matrices 21
Base Case Financing Assumption 21
Regulated Utility Ownership Financing Assumption 21
Appendix B: Average Capacity Factor by State 23
JOHN STERLING – SENIOR DIRECTOR, RESEARCH & ADVISORY SERVICES
TED DAVIDOVICH – MANAGER, UTILITY PLANNING
ii
TABLE OF FIGURES
Figure 1 - Key Takeaways 1
Figure 2 - Comparison of State Average Construction 4
Labor Rate Against National Median
Figure 3 - Added Production from Single-Axis Tracking 6
Figure 4 - Representative Solar Economies of Scale 7
Figure 5 - NREL Solar Resource Map 8
Figure 6 - Solar Capacity Factors for Phoenix, 9
Jackson and Pittsburgh
Figure 7 - Typical Production Curves by Location 9
Figure 8 - Implications of System Orientation on Production 12
Figure 9 - System Orientation 13
Figure 10 - LCOE Potential by Capacity Factor 14
TABLE OF TABLES
Table 1 - Breakdown of Solar Build Costs 3
Table 2 - Impact of System Design on LCOE 6
for a 20 MW Solar Project in Phoenix
Table 3 - Impact of Economies of Scale on LCOE for a Solar Project in Phoenix
Table 4 - Impact of Location on LCOE 11
for a 20 MW Solar Project in Phoenix Table 6 - Impact of System Orientation to LCOE 10
for a 20 MW South-Facing Solar Project Table 5 - Impact of Project Financing on LCOE 7
12
for a 20 MW Solar Project in Phoenix iii
KEY TAKEAWAYS
Industry news expounding low cost utility-scale solar has been prevalent in recent months, touting
prices below $40/MWh in multiple jurisdictions.1 While eye-catching, the reality is that utility-scale solar
photovoltaic (PV) project economics vary widely and are dependent upon a host of drivers (Figure 1). As
utilities consider adding solar to their resource mix, understanding these drivers and their implications
is necessary for securing high-value, cost-competitive projects. This report will enable utilities to: (1)
understand solar cost drivers; (2) recognize the value of solar in their resource mix; and, (3) establish a
framework to evaluate solar projects.
FIGURE 1 - KEY TAKEAWAYS
Solar Pricing is
More Economic
than Ever
Hard and soft costs for solar have declined steadily in recent years and are
predicted to decline further through the end of the decade
Solar levelized cost of energy (LCOE) can achieve less than $70/MWh in poor
solar resource locations, and below $50/MWh in good-to-strong solar resource
locations
Economies of Scale
are Real
Large scale solar projects can achieve significant economies of scale across soft
cost categories compared to small projects, with as much as 40% build cost
savings for utility-scale solar
Location Location
Location
States with strong solar resources can generate significantly more energy than
states with sub-optimal solar resources given the same project design
Financing Matters
Different Designs
Meet Different
Needs
Design Flexibility
Can Be Reflected in
Resource Planning
Tools
Streamlined
Procurement
Processes Save
Time and Money
Factors such as labor rates can impact solar economics on a sub-regional basis
Project riskiness can dictate financing terms, which impacts LCOE
Efficient monetization of the ITC can drive LCOE down dramatically
West-facing systems may provide additional capacity at peak hours, creating an
added capacity value for the project
Design strategies that leverage tracking systems can boost capacity factor and
lower LCOE, particularly given the decreasing gap in costs between fixed and
tracking systems
Modeling multiple system sizes, orientations, and designs can allow resource
planning tools to better identify “best fit” solar projects
Routinely testing the market for pricing can allow utilities to stay on top of the
continually declining costs of solar projects
Identifying your value proposition in advance and communicating it to bidders
can result in more intelligently designed proposals
Standardizing templates for key response data translates into less review time
and less risk of errors
1 UtilityDive, February 23, 2016; http://www.utilitydive.com/news/cheapest-power-in-the-us-palo-alto-muni-eyes-solar-at-under-37mwh/414372/
GTM, June 30, 2015 http://www.greentechmedia.com/articles/read/cheapest-solar-ever-austin-energy-gets-1.2-gigawatts-of-solar-bids-for-less
1
INTRODUCTION
Solar photovoltaic (PV) pricing has steadily declined over the last decade, with significant efficiencies
being driven into both hard (modules, inverters) and soft (permitting, labor, financing) costs. The utilityscale development community has worked diligently to turn solar into a cost-competitive resource with
conventional fossil-fueled alternatives…in many situations. The caveat in that sentence is important: not
all solar projects are equal.
Indeed, the old adage that economies of scale drive solar economics is still alive and well; however,
there are a multitude of nuances and additional factors that can impact both the nominal economics
of the project as well as the value that project delivers to the utility and its customers. The goal of this
report is to provide context behind the key drivers that impact the overall cost and value of a solar
project. Questions that this report seek to answer include:
What drives PPA price differentials between two seemingly similar projects?
What impacts do size, location, financing, and system design have on project
economics?
How does normalization factor into how attractive a project can appear?
How should all of these factors get translated into resource planning and procurement
processes?
Gaining a fundamental understanding of how all of the characteristics of a solar project act in concert
to deliver value to the utility will be critical in driving broader adoption of solar by utilities. Translating
this increased understanding and subsequently adding more sophistication to how utility-scale solar is
modeled will provide utilities with a fuller picture of the true economics of this resource.
UTILITY-SCALE SOLAR PROJECT COSTS
The cost categories for solar are relatively straightforward and fall into one of two generic categories:
hard costs and soft costs. Hard costs represent the capital expenditures (CapEx) related to hardware
and other installation components: modules, inverters, racking, etc. For the most part, design and
engineering efficiency improvements over recent years have been highly successful in driving savings
into those components. Modules, in particular, have seen significant price declines over the last decade,
falling from several dollars per Watt to $0.60 per Watt or less on average.
2
Soft costs refer to non-hardware items such as permitting and labor. These cost categories have seen
significant reductions for utility-scale solar; however, improvements can still be made. Table 1 breaks
down the various cost categories and how they factor into the overall build cost of a typical 20 MW solar
project. This table also provides context for how susceptible these categories are to project size.
2 All prices are stated in $ per Watt-dc unless otherwise noted.
2
TABLE 1 - BREAKDOWN OF SOLAR BUILD COSTS
COST
COMPONENT
DESCRIPTION
CONTRIBUTION ECONOMIES
TO PROJECT
OF SCALE
COSTS
IMPACT
MODULE
Hard Cost
PV panels that convert sunlight to electricity; sold
on a per panel basis
30-40%
Low impact
BALANCE OF
SYSTEM
Hard Cost
All other hardware such as structural and electrical
equipment; sold by length of wire, feet of structural
material, or quantity
20-25%
Medium impact
CONSTRUCTION
LABOR
Soft Cost
Workforce expenses to construct system; varies by
location
10-15%
Medium impact
MARGIN AND
OVERHEAD
Soft Cost
Builder profits and overhead expenses
6-12%
Medium impact
INVERTER
Hard Cost
Electronic equipment that converts DC to AC; sold
on a per equipment piece price
5-10%
Low impact
SALES TAX
Soft Cost
Sales tax on system
4-8%
Low impact
LAND
Soft Cost
Actual land for the system
3-7%
Low impact
PERMITTING /
ENVIRONMENTAL
Soft Cost
Necessary local permits and environmental studies;
generally a fixed price and not dependent on
system size unless system is complex
2-5%
High impact
ENGINEERING
Soft Cost
System design; generally a fixed price but can be
more expensive for complex systems
1-3%
High impact
INTERCONNECTION
Hard & Soft Cost
Cost of connecting to the grid; cost will be locationdependent, driven by distance from and need for
additional equipment at interconnection point
1-3%
Medium-High
impact
Separate from these components, solar projects can take advantage of the Federal Investment Tax
Credit (ITC) of 30% to reduce project costs. Moreover, some states and municipalities have separate tax
exemptions for solar projects that further reduce cost for solar assets.
3
Additional jurisdiction-specific factors can impact the final cost to build a solar project. For example,
permitting costs and sales tax can fluctuate from state to state and municipality to municipality. Further,
costs for construction labor can vary widely across the country.3
FIGURE 2 - COMPARISON OF STATE AVERAGE CONSTRUCTION
LABOR RATE AGAINST NATIONAL MEDIAN
Source: US Bureau of Labor and Statistics, 2014
Working in tandem with the raw cost of construction outlined in Figure 2 is the relative maturity of the
solar market. States with robust solar deployment such as California and Arizona have a higher density
of qualified and experienced solar labor compared to states with little to no solar deployment. In the
latter regions, developers would likely need to mobilize a workforce from other regions or work to train
local construction labor in solar project construction, increasing overall labor costs initially until the local
labor force is trained.
Understanding the interplays between your state’s relative costs for taxes, permitting, and labor is
important to understand the potential solar project costs. Factoring these region-specific factors
together can cause a movement of more than $0.10/Watt (5-10% of total project cost) up or down from
the base national average price.4
3 US Bureau of Labor and Statistics, http://www.bls.gov/oes/tables.htm; Data from May 2014.
4 For purposes of this Report, national average solar build costs will be leveraged for simplicity.
4
IMPLICATIONS OF PROJECT DESIGN ON
LEVELIZED COST OF ENERGY
Project costs only tell one side of the story and can obscure the true economics of a project. As
a variable renewable resource with no fuel cost, solar cannot be compared apples-to-apples with
conventional gas-fired generation, irrespective of other factors. In truth, a variety of system-specific
data points can drive one solar project to be considerably more economic than another. Project size,
location, financing, ongoing operations and maintenance (O&M) costs, and system design decisions all
factor together to convert project costs into a levelized cost of energy (LCOE).
LCOE is a measure (typically represented in $/MWh) that considers the lifetime project costs against
lifetime production, and creates a single value that represents the variable payment required to balance
those factors (given a set of financing assumptions). This is a much more accurate comparison point
for solar against not only other renewable projects but against conventional generation as well. Further,
LCOE can be used as a crude approximation of what Power Purchase Agreement (PPA) price could be
anticipated under a specific set of circumstances.
This section will delve into how a variety of factors—both working individually and in tandem—impact
the economic proposition of solar. All economics assume a system located in Phoenix, AZ, unless
otherwise indicated. All CapEx pricing is stated in pre-tax dollars, and are representative national
average costs for projects commercially operational in calendar year 2016.
FIXED TILT AND SINGLE-AXIS TRACKING
A primary decision facing utilities and developers relates to the base system design under consideration:
namely, whether or not to pursue a fixed tilt or single-axis tracking (SAT) system. SAT systems are
designed to physically track the sun’s motion across the sky each day rather than being fixed and
pointed directly south (or west). Tracking systems create more production in mid-morning and late
afternoon hours, but have historically come with added costs from a more complex engineering design
and racking system.
5
FIGURE 3 - ADDED PRODUCTION FROM SINGLE-AXIS TRACKING
Source: SEPA, 2016
This has resulted in more south-facing fixed tilt projects being the predominant design adopted
nationally, with SAT systems developed in specific regions of the country such as the desert
southwest. Increasingly, however, the market appears to be moving towards more SATs rather than
fixed tilt due to declining cost differentials between the two system designs. SEPA anticipates that
leveraging a tracking system rather than fixed tilt will result in a cost differential of 5% or less on
average in the next 1–2 years.5
TABLE 2 - IMPACT OF SYSTEM DESIGN ON LCOE FOR A 20 MW SOLAR
PROJECT IN PHOENIX
CAPACITY FACTOR
BUILD COST
LCOE
FIXED TILT
SINGLE-AXIS TRACKING
30.5%
36.0%
$1.60/Watt-dc
$1.68/Watt-dc
$63/MWh
$55/MWh
Source: SEPA, 2016
ECONOMIES OF SCALE
Economies of scale for solar PV are both obvious and obscure. On the one hand, clearly utility-scale
solar projects benefit from economies of scale when compared to rooftop assets. What becomes
less clear is just where the natural break points are for utility-scale solar. Generally speaking, solar
experiences some natural break points with regards to pricing. The first, for utility-scale solar, occurs
between 1–5 MW. On average, SEPA anticipates any non-distributed solar project at 5 MW to be priced
at or below $2/Watt in 2016.
5 Exogenous factors such as snow loading impacts will cause this number to fluctuate regionally.
6
The second common breakpoint occurs between 5-20 MW. At 20 MW, SEPA anticipates 2016 pricing
at or below $1.60/Watt on average. Lastly, another common breakpoint occurs from 20-50MW. SEPA
anticipates 2016 pricing for 50 MW projects to be $1.20/Watt or less. Beyond 50 MW, some additional
economies of scale may be gained, but at diminishing levels. These breakpoints occur where the
relationship between capacity and specific cost components diverge from where marginal costs apply.
FIGURE 4 - REPRESENTATIVE SOLAR ECONOMIES OF SCALE
dc
dc
Source: SEPA, 2016
How do these values translate into LCOE? Under the same assumptions for interconnection, labor,
permitting, taxes, and solar availability, the LCOE can still change significantly based solely on
economies of scale:
6
TABLE 3 - IMPACT OF ECONOMIES OF SCALE ON LCOE FOR A SOLAR
PROJECT IN PHOENIX
CAPEX (FIXED TILT)
LCOE (FIXED TILT)
CAPEX (SAT)
LCOE (SAT)
5 MW
20 MW
50 MW
$2.00/Watt-dc
$1.60/Watt-dc
$1.20/Watt-dc
$74MWh
$63/MWh
$51/MWh
$2.10/Watt-dc
$1.68/Watt-dc
$1.26/Watt-dc
$65/MWh
$55/MWh
$45/MWh
6 All LCOEs in this Report reflect monetization of the 30% federal investment tax credit unless otherwise noted.
7
LOCATION
While project size and the resulting economies of scale very obviously impact LCOE, project location
can have a more subtle but equally dramatic impact as well. This comes about from both the amount,
intensity, and persistence of the solar resource at a given location. The map depicted in Figure 5
illustrates how significantly the solar resource can vary across the U.S.7
FIGURE 5 - NREL SOLAR RESOURCE MAP
Source: National Renewable Energy Laboratory, 2012
The solar resource calculation of kilowatt-hour per square meter per day (kWh/m2/day) is interesting but
does not necessarily correlate to the electric utility industry; it can, however, be translated into capacity
factor. Capacity factor describes the amount of energy that is produced compared to the system’s
theoretical maximum.8 For example, a 100 MW natural gas peaking plant that runs at maximum
capacity for only a handful of hours a year would have a capacity factor of under 5%, whereas a large
nuclear facility that runs as a baseload plant likely has a capacity factor close to 90%. Those two
resources are dispatched largely on operating costs that are heavily weighted by fuel. Solar, on the other
hand, dispatches at effectively zero cost and is structured to deliver as much energy as possible given
existing weather conditions.
7 This and other solar maps are available at www.nrel.gov/gis/solar.html
8 Capacity Factor (CF) = Annual Output / (Nameplate MW * 8760).
8
For comparative purposes, assume three different site assumptions for development of a 20 MW solar
project: a strong solar resource location (Phoenix, AZ); a moderate solar resource location (Jackson,
MS); and a lower solar resource location (Pittsburgh, PA).
FIGURE 6 – SOLAR CAPACITY FACTORS FOR PHOENIX, JACKSON AND
PITTSBURGH
Source: SEPA, 2016
The difference in just a few percentage points of capacity factor can create a wide discrepancy in both
the output the system delivers as well as the overall LCOE, even if the projects are similar in all other
factors. For a 20 MW south-facing project, 23% and 41% more energy is produced at the Phoenix site
compared to the Jackson and Pittsburgh sites, respectively.
FIGURE 7 - TYPICAL PRODUCTION CURVES BY LOCATION
Source: SEPA, 2016
9
TABLE 4 - IMPACT OF LOCATION ON LCOE FOR A 20 MW SOUTH-FACING
SOLAR PROJECT
PHOENIX, AZ
JACKSON, MS
PITTSBURGH, PA
CAPACITY FACTOR
(FIXED TILT)
30.5%
24.7%
21.6%
LCOE (FIXED TILT)
$63/MWh
$77/MWh
$88/MWh
CAPACITY FACTOR
(SAT)
36.0%
28.4%
24.4%
$55/MWh
$70/MWh
$81/MWh
LCOE (SAT)
Source: SEPA, 2016
PROJECT FINANCING
Solar project financing has major implications and can swing a project’s LCOE from highly attractive
to highly priced. Major variables include: (1) the amount financed by debt; (2) debt and equity return
requirements; and, (3) ability to maximize the monetization of the ITC and accelerated depreciation.
Impacting items (1) and (2) are factors such as the relative creditworthiness of the developer, the
creditworthiness and strength of the counter party backing the project, and the overall risk of
production. Strong contracts between highly credit worthy parties can lead to very attractive financing.
Conversely, projects facing significant risk, such as those that are highly likely to experience curtailment
and lost sales, would be looked upon as riskier investments requiring higher returns to finance.
For item (3) above, the treatment of the ITC and accelerated depreciation can have a huge impact on
relative LCOE. For regulated investor owned utilities (IOUs), they have the ability to take advantage of the
ITC; however, the immediate effects of the ITC only benefits shareholders. For rate making purposes, the
ITC has to be “normalized”, or spread across the asset life similar to straight-line depreciation.
Why does this rule exist? Simply speaking, the ITC is an incentive to build new capital, as construction
projects have historically been good for the economy. And the specific ITC relevant to solar exists to
incentivize renewable generation growth to help advance deployment of clean energy. By passing that
value on directly to customers, the “incentive” to deploy capital has been dampened for shareholders.
To retain that incentive, utilities are required to normalize the benefits of the ITC across the project’s life.
Customers still get that benefit – just not immediately. This also ensures that future customers receive
the same benefit across the project’s entire life, rather than just customers on day one.
10
Third party developers, though, are not faced with that challenge and are able to monetize the ITC
and accelerated depreciation to both their immediate benefit and the immediate benefit of their utility
counterpart. Front-loading these incentives, for lack of a better term, significantly lowers the project cost
from a net present value perspective, translating into a more attractive LCOE and PPA price.
Taking all of these options into account, two specific financing assumptions were created for modeling
purposes:
Base Case – assumes that the project is equally financed with debt and equity. Debt is
obtained at 6%, and the rate of return required for equity is 10%. This case assumes
that the project is owned by a third party that can monetize the ITC and accelerated
depreciation most efficiently.
Normalized ITC – in this final case, the financing assumes that a regulated utility
owns the project. As such, they are required to normalize the benefits of the ITC and
accelerated depreciation over the life of the asset rather than factor their immediate
impacts into the project’s LCOE.
TABLE 5 - IMPACT OF PROJECT FINANCING ON LCOE FOR A 20 MW SOLAR
PROJECT IN PHOENIX
BASE CASE FINANCING
NORMALIZED ITC
DEBT
50% @ 6% return
50% @ 6% return
EQUITY
50% @ 10% return
50% @ 10% return
Immediately monetized
Normalized
LCOE (FIXED TILT)
$63/MWh
$96/MWh
LCOE (SAT)
$55/MWh
$85/MWh
ITC & ACCELERATED
DEPRECIATION
TREATMENT
Source: SEPA, 2016
11
FIXED TILT SYSTEM ORIENTATION
Traditional logic dictates that fixed tilt solar projects should be faced south to maximize production. That
is, after all, where the sun is most often visible on the horizon. Some utilities, however, have pursued
west-facing systems, and that has sizable implications to the production that can be anticipated:
FIGURE 8 – IMPLICATIONS OF SYSTEM ORIENTATION ON PRODUCTION
Source: SEPA, 2016
A notable trade-off exists: nearly 17% annual production compared to south-facing systems is foregone
by facing systems west. These lost sales have a real and measurable impact on the relative LCOE of
two similarly situated projects:
TABLE 6 – IMPACT OF SYSTEM ORIENTATION TO LCOE FOR A 20 MW SOLAR
PROJECT IN PHOENIX
SOUTH-FACING
WEST-FACING
CAPACITY FACTOR
30.5%
25.3%
LCOE (FIXED TILT)
$63/MWh
$75/MWh
Source: SEPA, 2016
So why talk about orientation if it causes such a dramatic decrease in production and corresponding
increase in LCOE? Because looking at LCOE conceals part of the true value proposition: increased
alignment with a typical utility’s load profile.
12
FIGURE 9 - SYSTEM ORIENTATION
Source: SEPA, 2016
South-facing solar maximizes production around 12-1pm daily. The typical utility, though, serving a
summer peak demand driven by air conditioning load, does not experience its maximum load until
around 5pm. At that point in time, a south-facing system’s production is less than 40% of its average
12pm output. A west-facing system, however, is producing at over 70% of its relative peak production
at 5pm. This increased availability translates directly into additional capacity value for the resource. For
utilities looking to meet peak demand, the increased value of generation at 5pm may offset the lost
production during other hours.
PUTTING IT ALL TOGETHER
How do these factors all come together to impact a project’s LCOE? As a general rule, the following
assumptions hold true:
Large projects with favorable financial structures in strong solar resource
locations will result in very low LCOEs
Small projects with sub-optimal solar resource locations and financing will
result in high LCOEs
Separate from these, lowest build cost is not always the primary driver; rather, the ability to shift when
production occurs, or increase production compared to standard designs, can either lower the LCOE,
provide added value in terms of avoided cost potential, or both.
13
FIGURE 10 - LCOE POTENTIAL BY CAPACITY FACTOR
Source: SEPA, 2016
DESIGN CONSIDERATIONS FOR RESOURCE
PLANNERS
Translating utility-scale solar from the conceptual to something that can be modeled in a resource
planning process is complicated. The following considerations are offered for resource planners looking
to more accurately model solar for their portfolios.9
Routinely obtain market pricing
Solar costs have declined steadily for some time and are projected to continue declining
into the future, albeit at a slower rate than past five years. Utilities that are using solar cost
information from one planning cycle ago run the risk of significantly over-estimating the
cost to build solar in their territory. Routine discussions with large developers and other
organizations can help maintain a fresh outlook on where prices are trending.
Consider modeling multiple configurations
Many utilities today model either 10 MW or 20 MW, south-facing solar only. While this
is a common project size, it may limit how solar can be deployed. Consider how other
resources like natural gas generators are modeled. Utilities may model variations around
aeroderivatives, reciprocating engines, 1x1s, 2x1s, duct-firing, etc. – a virtual cavalcade of
modeling choices for one fuel type. This is much less common with solar. Identifying multiple
options around size / economies of scale, orientation, design (fixed vs. tracking), and other
choices, including battery storage and its multiple capabilities,
9 Additional details and considerations can be found in: Sterling, J., McLaren, J., Taylor, M., & Cory, K. (2013). Treatment of Solar Generation in Electric Utility Resource Planning.
National Renewable Energy Laboratory. http://www.nrel.gov/docs/fy14osti/60047.pdf.
14
add complexity in choice to the resource planning tool but not necessarily added complexity
to the resource plan itself. And modeling multiple sizes can provide flexibility in meeting
needs. For example, a 100 MW west-facing system can solve a different resource need than
a series of 20 MW south-facing systems. Understanding those problem sets and options can
add depth to the resource plan.
Let resource needs define solar design
Some utilities are “long” resources today, meaning they do not need additional capacity in
the future. For them, least cost pricing is paramount and should point them towards southfacing systems or other designs that result in the lowest possible LCOE. Other utilities show
a definite need for new capacity in the future. These utilities should consider modeling westfacing solar or other configurations that are more likely to deliver energy when their system
peaks. In any case, modeling more than one type of solar project can allow the resource
planning tools increased flexibility in identifying the best fit for the future.
Leverage accurate production data
Make sure that the solar production curve assigned to each solar resource being modeled is
accurate and based on the specific design factors under consideration. In addition, utilities
should make sure that the solar resource being modeled matches a production curve that can
be expected for their region.
Pay attention to risk sensitivities
One of the real benefits of deploying a resource like solar is that it comes with no fuel price
risk. As utility resource plans increase in complexity, reviewing multiple variable sensitivities
and scenarios, it will be important to monitor how solar-heavy portfolios perform from a risk
perspective. It is anticipated that these portfolios will experience less volatility associated
with uncertain fuel costs, and provide less exposure to future environmental regulation costs.
MAXIMIZING PROCUREMENT TO MINIMIZE COST
Transitioning from planning for a resource to seeing proverbial steel in the ground requires a solid
procurement process, the backbone of which is the Request for Proposals (RFP). An open and
transparent RFP that provides clear and concise directions to the industry can go a long way towards
identifying the least cost project for the utility. Moreover, streamlining and standardizing processes and
procedures can reduce the time required on all parties in the development and review of proposals. The
following suggested practices may help meet those goals.
15
Pre-qualify bidders
Some utilities have a pre-qualification process, where developers provide their expertise,
organization structure, financial standing, etc. This does not have to be an overly exclusive
process; rather, it allows the utility to focus more closely on proposals and pricing during the
RFP itself. Alternatively, this step could be taken to reduce the number of competitors so that
the utility has less review time required on the meat of the proposals, and the developers feel
like their time spent on responding to the RFP is worthwhile because they know they aren’t
having to compete against dozens of others.
Create a scoring matrix and communicate your value proposition to
bidders
An important step prior to issuing the RFP is understanding just what value proposition you
are hoping to achieve in the first place. The developer community will likely assume the RFP is
looking for the least cost $/MWh possible and will design and engineer their bids around that
idea. If, though, you are going to compare each bid against your avoided cost and you have a
need for capacity at 5pm, your value proposition is driven around something slightly different
than nominal least cost. Communicating how bids will be analyzed in the RFP itself will result
in proposals driven around that value proposition.
Standardize
Identify ways to streamline and standardize the process for both yourself and the bidders. One
concept often leveraged is the creation of a template for responses that standardizes inputs.
For example, a spreadsheet template can be provided to bidders that standardizes how they
input production, pricing, and other key information. This accomplishes two important things.
First, it makes reviewing each bid much easier for the utility as they won’t have to process a
myriad of different formats. Second, it minimizes the potential for unintentional errors by the
utility when having to make all of those format modifications.
Allow for creativity
Provide the opportunity for developers to be innovative in solving your problems. If you write
an RFP that is overly prescriptive in how the solar project has to be designed, you will get a
very narrow range of proposals. If, on the other hand, you state your value proposition and
boundary requirements (“must haves”) and allow bidders the flexibility to design around those,
you may end up with proposals that are structured in ways you never would have considered
but that deliver more value. This includes allowing for multiple bids. For example, you could
require a very specific system design as the base proposal, but then allow for one or more
alternative designs to be submitted if the developer can identify alternatives worth considering.
16
Find ways to reduce risk
Developers price risk into their proposals, and the more you can do to reduce their
unknowns the better a set of pricing you will receive. One example is to provide a draft PPA
contract as part of the procurement process. This allows the developer to both price in any
contract-specific risk as part of their proposal, as well as provide red-lined comments and
suggestions to contract provisions that can result in more competitive pricing overall.
FREQUENTLY ASKED QUESTIONS
Often, utilities consider the same sets of questions as they begin evaluating utility-scale solar. These
“FAQs” have been consolidated here to help inform utilities’ decisions to pursue source as part of their
resource mix.
Q: Solar is highly intermittent. Why would I pursue large amounts of solar? Wouldn’t that have
negative implications for my system?
A: While solar intermittency is undoubtedly a fact of life, there are ways to mitigate it so that the
distribution and/or transmission system don’t “feel” that intermittency. As a general rule, the inverters
that connect the solar to the grid have gotten significantly more sophisticated in recent years, and they
are capable of providing and absorbing VARs, among other factors. In addition, the ability to forecast
production and then monitor conditions in the real time has allowed both utilities and developers insight
into system production with the ability – again, via the inverter – to manage output more efficiently.
Should this still be of concern, one option that some utilities have considered is building a series of
smaller projects that aggregate to a large total installed capacity (i.e., four 25 MW projects rather than
one 100 MW project). These smaller projects would get spread around the service territory, minimizing
the local impact of weather events on the aggregate production curve. The trade off, though, comes in
the form of increased overall cost for the same capacity (via economies of scale).
Q: Can I get a lower price overall if I use the same site for multiple stages of a project?
A: Not generally. For the developer community, they would still be designing, permitting, and mobilizing
a labor force for each of those phases. While leveraging the same land may provide some cost savings,
ultimately the phased approach is unlikely to result in the same economies of scale as building the
entire project at once. One factor that may help bridge that gap would be guaranteeing a build-out
schedule for a single developer. That could allow for lower financing costs or at least a more thoughtful
deployment of labor to reduce overall project costs.
17
Q: What prices can I expect for solar in 2020?
A: Predicting prices for solar out in time is tricky. This is evidenced by the rapid decline in pricing that
we have seen over the last several years, which makes it extremely difficult to keep an accurate price
point for even the current year. It can be said, though, that the Department of Energy’s SunShot Initiative
has a target of $1/Watt installed for utility-scale solar in 2020.10 Based on pricing seen in late 2015, this
value is likely achievable on a national average basis for larger projects (50 MW+) and, potentially, for
projects as small as 20 MW; however, the rate at which prices decline going forward is likely to be much
slower/steadier than the rapid decreases seen in years past.
Q: I’ve seen some solar pricing at or below $40/MWh. Is that feasible?
A: It depends. Pricing at that level likely requires a confluence of factors, as has been shown in this
Report: (1) a large project (2) sited in a strong solar resource location (3) with very favorable financing.
Even with these assumptions in place, it may also require a lower than anticipated return requirement
as part of the financing to ensure pricing at that level. As mentioned, though, the capital cost curve for
solar continues to decline and projects that do not require delivery for another 1-2 years may very well
find themselves with LCOEs at or below $40/MWh under more traditional assumptions.
Q: As a utility, owning the solar project is never as good of an economic deal for my
customers than getting a PPA, right?
A: Again, it depends. It is certainly true that third party developers can monetize the ITC much more
efficiently than a regulated utility due to normalization rules. One factor to consider, though, is that an
owned system can be used for its entire useful life, which is likely 35 years or more. Most PPAs today
are roughly 20 years in length. So when running the economics, be careful not to compare 20 years
of ownership against a 20 year PPA – that is surely going to show the PPA being more beneficial. A
better comparison would be 35 years of ownership compared to a 20 year PPA and another 15 year
PPA (or similar market purchase) to match against the asset life. The assumptions that are used for the
second window of time will play a role in whether or not ownership is truly more costly for customers.
In addition, a utility-owned project would provide the utility with more control over performance
transparency and predictability that a PPA project may not be able to offer.
A second option is the idea of a PPA buyout or ownership flip. Under this structure, the developer
would own the asset and sell to the utility under a PPA for 7 to 10 years (long enough to most effectively
monetize the ITC), at which time the utility would have the option to purchase the project for its net book
value. This could provide the “best of both worlds” where customers benefit from the ITC monetization
and utilities are able to own the project long term, incorporating it more effectively into their generation
fleet. The utility may choose to require extra due diligence specific to evaluating system condition at time
of the ownership flip to better predict the long-term equipment performance and financial risks.
10 U.S. Department of Energy, SunShot Initiative, http://energy.gov/eere/sunshot/about-sunshot-initiative
18
Q: How should O&M factor into the equation?
A: Developing an O&M strategy prior to design can increase the efficacy of design specifications
and accuracy of capital budgeting and the final LCOE. The Electric Power Research Institute’s O&M
report suggests developers should budget $10 to $45/kW per year.11 Although O&M is often treated
separately from the rest of the PV system delivery process, stakeholders interested in long-term
performance predictability should consider their O&M options during plant design and specifications.
For example, stakeholders should consider all potential options to optimize system design for longevity,
increase performance visibility (i.e., monitoring equipment), account for local environmental conditions,
and use top-tier equipment options.12
Q: How can I use this report?
A: This report can be used to inform expected LCOE and PPA prices for different geographies and
project designs. Appendix A provides reference information to show how the LCOE varies as the
factors discussed in the Report are modified. Appendix B provides representative capacity factors for
each state for both fixed tilt and SAT systems. By combining the information contained in both of these
appendices, it is possible to extrapolate a range of prices that are representative of projects that could
be developed in your territory and based upon your own project design preferences.
11 See EPRI, December 2015, “Budgeting for Solar PV Plan Operations and Maintenance: Practices and Pricing.”
12 For more information, see SEPA’s report, “Resource Guide: Asset Management and Operations and Maintenance”, February 2016.
19
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As part of the development of this report, Recurrent Energy verified the reasonableness of SEPA’s
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20
APPENDIX A: LCOE PRICE EXPECTANCY MATRICES
BASE CASE FINANCING ASSUMPTION
PERCENTAGE
RATE OF RETURN
DEBT
50%
6%
EQUITY
50%
10%
WEIGHTED AVERAGE
COST OF CAPITAL
8%
• ITC and Modified Accelerated Cost Recovery System monetized
• 20 year LCOE
NOTES
CAPACITY
FACTOR
$1.20/WATTdc
$1.40/WATTdc
$1.60/WATTdc
16%
$97/MWh
$108/MWh
$119/MWh
$130/MWh
$141/MWh
18%
$86/MWh
$96/MWh
$106/MWh
$116/MWh
$126/MWh
20%
$78/MWh
$87/MWh
$95/MWh
$104/MWh
$113/MWh
22%
$71/MWh
$79/MWh
$87/MWh
$95/MWh
$103/MWh
24%
$65/MWh
$72/MWh
$79/MWh
$87/MWh
$94/MWh
26%
$60/MWh
$67/MWh
$73/MWh
$80/MWh
$87/MWh
28%
$56/MWh
$62/MWh
$68/MWh
$74/MWh
$81/MWh
30%
$52/MWh
$58/MWh
$64/MWh
$69/MWh
$75/MWh
32%
$49/MWh
$54/MWh
$60/MWh
$65/MWh
$71/MWh
34%
$46/MWh
$51/MWh
$56/MWh
$61/MWh
$66/MWh
36%
$43/MWh
$48/MWh
$53/MWh
$58/MWh
$63/MWh
$1.80/WATTdc $2.00/WATTdc
21
REGULATED UTILITY OWNERSHIP FINANCING ASSUMPTION
PERCENTAGE
RATE OF RETURN
DEBT
50%
6%
EQUITY
50%
10%
8%
• ITC normalized; no bonus depreciation
• 30 year LCOE
NOTES
CAPACITY
FACTOR
WACC
$1.20/WATTdc
$1.40/WATTdc
$1.60/WATTdc
16%
$145/MWh
$164/MWh
$183/MWh
$202/MWh
$221/MWh
18%
$129/MWh
$146/MWh
$163/MWh
$179/MWh
$196/MWh
20%
$116/MWh
$131/MWh
$146/MWh
$161/MWh
$176/MWh
22%
$106/MWh
$119/MWh
$133/MWh
$147/MWh
$160/MWh
24%
$97/MWh
$109/MWh
$122/MWh
$134/MWh
$147/MWh
26%
$89/MWh
$101/MWh
$113/MWh
$124/MWh
$136/MWh
28%
$83/MWh
$94/MWh
$104/MWh
$115/MWh
$126/MWh
30%
$77/MWh
$87/MWh
$98/MWh
$108/MWh
$118/MWh
32%
$73/MWh
$82/MWh
$91/MWh
$101/MWh
$110/MWh
34%
$68/MWh
$77/MWh
$86/MWh
$95/MWh
$104/MWh
36%
$65/MWh
$73/MWh
$81/MWh
$90/MWh
$98/MWh
$1.80/WATTdc $2.00/WATTdc
22
APPENDIX B: AVERAGE CAPACITY FACTOR
BY STATE
STATE
FIXED TILT
SINGLE AXIS
TRACKING
28.7%
Montana
24.0%
27.1%
15.9%
17.1%
Nebraska
22.6%
25.4%
Arizona
30.5%
36.0%
Nevada
30.9%
36.0%
Arkansas
24.5%
28.1%
New Hampshire
22.5%
24.8%
California
27.2%
32.1%
New Jersey
23.3%
26.1%
Colorado
26.2%
29.6%
New Mexico
29.9%
35.1%
Connecticut
21.9%
24.4%
New York
22.8%
25.7%
Delaware
23.4%
26.2%
North Carolina
24.2%
27.5%
Florida
24.3%
28.1%
North Dakota
23.4%
26.0%
Georgia
25.1%
28.9%
Ohio
21.5%
24.2%
Hawaii
26.4%
31.9%
Oklahoma
25.7%
29.7%
Idaho
25.4%
29.1%
Oregon
20.3%
22.8%
Illinois
23.8%
26.9%
Pennsylvania
21.6%
24.4%
Indiana
23.3%
26.4%
Rhode Island
22.3%
24.8%
Iowa
24.4%
27.6%
South Carolina
24.9%
28.6%
Kansas
24.9%
28.3%
South Dakota
23.8%
26.7%
Kentucky
23.2%
26.4%
Tennessee
23.6%
27.0%
Louisiana
23.6%
27.2%
Texas
25.5%
30.2%
Maine
23.5%
26.0%
Utah
26.0%
29.9%
Maryland
23.2%
26.1%
Vermont
21.7%
24.2%
Massachusetts
22.9%
25.3%
Virginia
23.9%
27.0%
Michigan
21.6%
24.3%
Washington
18.6%
21.0%
Minnesota
22.9%
25.6%
West Virginia
22.6%
25.5%
Mississippi
24.7%
28.4%
Wisconsin
22.4%
24.9%
Missouri
24.0%
27.5%
Wyoming
26.1%
29.5%
STATE
FIXED TILT
Alabama
25.0%
Alaska
SINGLE AXIS
TRACKING
Source: PvSyst
23
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