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UTILITY-SCALE SOLAR: THE PATH TO HIGH-VALUE, COST-COMPETITIVE PROJECTS

In partnership with:

How to Optimize the Economics of Utility-Scale Solar Photovoltaic (PV) Facilities

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JOHN STERLING – SENIOR DIRECTOR, RESEARCH & ADVISORY SERVICES

TED DAVIDOVICH – MANAGER, UTILITY PLANNING

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

Appendix B: Average Capacity Factor by State 23

21

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TABLE OF FIGURES

TABLE OF TABLES

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 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 7

for a Solar Project in Phoenix

Table 4 - Impact of Location on LCOE 10

for a 20 MW South-Facing Solar Project

Table 5 - Impact of Project Financing on LCOE 11

for a 20 MW Solar Project in Phoenix

Table 6 - Impact of System Orientation to LCOE 12

for a 20 MW Solar Project in Phoenix

1

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.

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

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

Factors such as labor rates can impact solar economics on a sub-regional basis

Financing MattersProject riskiness can dictate financing terms, which impacts LCOE

Efficient monetization of the ITC can drive LCOE down dramatically

Different Designs Meet Different Needs

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

Design Flexibility Can Be Reflected in Resource Planning Tools

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

Streamlined Procurement Processes Save Time and Money

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

FIGURE 1 - KEY TAKEAWAYS

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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 utility-

scale 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?

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.

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.

2 All prices are stated in $ per Watt-dc unless otherwise noted.

INTRODUCTION

UTILITY-SCALE SOLAR PROJECT COSTS

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MODULEHard Cost

PV panels that convert sunlight to electricity; sold on a per panel basis

30-40% Low impact

BALANCE OF SYSTEMHard 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

INVERTERHard 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 / ENVIRONMENTALSoft 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 location-dependent, 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.

COST COMPONENT

DESCRIPTION

CONTRIBUTION TO PROJECT

COSTS

ECONOMIES OF SCALE

IMPACT

TABLE 1 - BREAKDOWN OF SOLAR BUILD COSTS

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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.

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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.

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CAPACITY FACTOR 30.5% 36.0%

BUILD COST $1.60/Watt-dc $1.68/Watt-dc

LCOE $63/MWh $55/MWh

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

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.

FIXED TILT SINGLE-AXIS TRACKING

5 Exogenous factors such as snow loading impacts will cause this number to fluctuate regionally.

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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

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

6 All LCOEs in this Report reflect monetization of the 30% federal investment tax credit unless otherwise noted.

CAPEX (FIXED TILT) $2.00/Watt-dc $1.60/Watt-dc $1.20/Watt-dc

LCOE (FIXED TILT) $74MWh $63/MWh $51/MWh

CAPEX (SAT) $2.10/Watt-dc $1.68/Watt-dc $1.26/Watt-dc

LCOE (SAT) $65/MWh $55/MWh $45/MWh

5 MW 20 MW 50 MW

dc

dc

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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.

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

7 This and other solar maps are available at www.nrel.gov/gis/solar.html

8 Capacity Factor (CF) = Annual Output / (Nameplate MW * 8760).

9

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

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.

Source: SEPA, 2016

Source: SEPA, 2016

FIGURE 7 - TYPICAL PRODUCTION CURVES BY LOCATION

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TABLE 4 - IMPACT OF LOCATION ON LCOE FOR A 20 MW SOUTH-FACING SOLAR PROJECT

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.

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%

LCOE (SAT) $55/MWh $70/MWh $81/MWh

PHOENIX, AZ JACKSON, MS PITTSBURGH, PA

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DEBT 50% @ 6% return 50% @ 6% return

EQUITY 50% @ 10% return 50% @ 10% return

ITC & ACCELERATED DEPRECIATION TREATMENT

Immediately monetized Normalized

LCOE (FIXED TILT) $63/MWh $96/MWh

LCOE (SAT) $55/MWh $85/MWh

NORMALIZED ITCBASE CASE FINANCING

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

Source: SEPA, 2016

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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

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

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.

Source: SEPA, 2016

CAPACITY FACTOR 30.5% 25.3%

LCOE (FIXED TILT) $63/MWh $75/MWh

SOUTH-FACING WEST-FACING

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FIGURE 9 - SYSTEM ORIENTATION

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.

Source: SEPA, 2016

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FIGURE 10 - LCOE POTENTIAL BY CAPACITY FACTOR

Source: SEPA, 2016

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.

DESIGN CONSIDERATIONS FOR RESOURCE PLANNERS

15

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 south-

facing 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 west-

facing 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.

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.

MAXIMIZING PROCUREMENT TO MINIMIZE COST

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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.

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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.

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.

FREQUENTLY ASKED QUESTIONS

18

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

19

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.

20

Recurrent Energy, one of North America’s largest solar project developers, is redefining what it means

to be a mainstream clean energy company, with utility-scale solar plants that provide competitive clean

electricity to large energy buyers. Based in the U.S. and headquartered in San Francisco, Recurrent

Energy is a wholly owned subsidiary of Canadian Solar and functions as the U.S. development arm of

Canadian Solar’s Energy Group. With more than 1,400 MWac/1,900 MWp of contracted projects, over

$7 billion in project financing commitments to date, and a project pipeline of more than 3GWac/4GWp,

Recurrent Energy has resources and capabilities to deliver solar at any scale.

Since 2006, Recurrent Energy has successfully developed and sold approximately 520MWac/700MWp

of solar PV projects. These projects have ranged from commercial rooftop arrays to utility-scale ground

mount power plants, highlighting Recurrent Energy’s ability to execute on its development pipeline and

build clean, renewable generation facilities for its customers.

As part of the development of this report, Recurrent Energy verified the reasonableness of SEPA’s

pricing assumptions and modeling, and validated the insights and approaches contained herein on how

utilities can pursue utility-scale solar in a cost-effective manner.

For more information about Recurrent Energy and this report, contact

origination_structuring@recurrentenergy.com

ABOUT RECURRENT ENERGY

21

BASE CASE FINANCING ASSUMPTION

DEBT 50% 6% 8%

EQUITY 50% 10%

NOTES• ITC and Modified Accelerated Cost Recovery System monetized • 20 year LCOE

WEIGHTED AVERAGE COST OF CAPITAL

PERCENTAGE RATE OF RETURN

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

$2.00/WATTdc$1.60/WATTdc $1.80/WATTdc$1.20/WATTdc $1.40/WATTdcCAPACITY FACTOR

APPENDIX A: LCOE PRICE EXPECTANCY MATRICES

22

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

$2.00/WATTdc$1.60/WATTdc $1.80/WATTdc$1.20/WATTdc $1.40/WATTdcCAPACITY FACTOR

REGULATED UTILITY OWNERSHIP FINANCING ASSUMPTION

DEBT 50% 6% 8%

EQUITY 50% 10%

NOTES • ITC normalized; no bonus depreciation• 30 year LCOE

PERCENTAGE RATE OF RETURN WACC

23

Alabama 25.0% 28.7%

Alaska 15.9% 17.1%

Arizona 30.5% 36.0%

Arkansas 24.5% 28.1%

California 27.2% 32.1%

Colorado 26.2% 29.6%

Connecticut 21.9% 24.4%

Delaware 23.4% 26.2%

Florida 24.3% 28.1%

Georgia 25.1% 28.9%

Hawaii 26.4% 31.9%

Idaho 25.4% 29.1%

Illinois 23.8% 26.9%

Indiana 23.3% 26.4%

Iowa 24.4% 27.6%

Kansas 24.9% 28.3%

Kentucky 23.2% 26.4%

Louisiana 23.6% 27.2%

Maine 23.5% 26.0%

Maryland 23.2% 26.1%

Massachusetts 22.9% 25.3%

Michigan 21.6% 24.3%

Minnesota 22.9% 25.6%

Mississippi 24.7% 28.4%

Missouri 24.0%

STATE FIXED TILT SINGLE AXIS

TRACKING

Montana 24.0% 27.1%

Nebraska 22.6% 25.4%

Nevada 30.9% 36.0%

New Hampshire 22.5% 24.8%

New Jersey 23.3% 26.1%

New Mexico 29.9% 35.1%

New York 22.8% 25.7%

North Carolina 24.2% 27.5%

North Dakota 23.4% 26.0%

Ohio 21.5% 24.2%

Oklahoma 25.7% 29.7%

Oregon 20.3% 22.8%

Pennsylvania 21.6% 24.4%

Rhode Island 22.3% 24.8%

South Carolina 24.9% 28.6%

South Dakota 23.8% 26.7%

Tennessee 23.6% 27.0%

Texas 25.5% 30.2%

Utah 26.0% 29.9%

Vermont 21.7% 24.2%

Virginia 23.9% 27.0%

Washington 18.6% 21.0%

West Virginia 22.6% 25.5%

Wisconsin 22.4% 24.9%

Wyoming 26.1%

Source: PvSyst

STATE FIXED TILT SINGLE AXIS

TRACKING

APPENDIX B: AVERAGE CAPACITY FACTOR BY STATE

27.5% 29.5%

In partnership with: