LBNL-183129

Is $50/MWh Solar for Real? Falling 

Project Prices and Rising Capacity 

Factors Drive Utility-Scale PV 

Toward Economic Competitiveness

Mark Bolinger, Samantha Weaver1, Jarett Zuboy2

1

Energy Analysis and Environmental Impacts Division

Lawrence Berkeley National Lab, Berkeley, CA

2

Independent Consultant, Golden, CO

May 2015

This is a pre-print of an article posted in Progress for Photovoltaics: 

Research and Applications

This work was supported by the Office of Energy Efficiency and Renewable Energy 

(Solar Energy Technologies Office) of the U.S. Department of Energy under Lawrence 

Berkeley National Laboratory Contract No. DE-AC02-05CH1131

ERNEST ORLANDO LAWRENCE

BERKELEY NATIONAL LABORATORY
DISCLAIMER

This document was prepared as an account of work sponsored by the United States Government. While this 

document is believed to contain correct information, neither the United States Government nor any agency thereof, 

nor The Regents of the University of California, nor any of their employees, makes any warranty, express or 

implied, or assumes any legal responsibility for the accuracy, completeness, or usefulness of any information, 

apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. 

Reference herein to any specific commercial product, process, or service by its trade name, trademark, 

manufacturer, or otherwise, does not necessarily constitute or imply its endorsement, recommendation, or favoring 

by the United States Government or any agency thereof, or The Regents of the University of California. The views 

and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government 

or any agency thereof, or The Regents of the University of California.

Ernest Orlando Lawrence Berkeley National Laboratory is an equal opportunity employer.
Is $50/MWh Solar for Real? Falling Project Prices and Rising Capacity Factors Drive 

Utility-Scale PV Toward Economic Competitiveness

Mark Bolinger1

*, Samantha Weaver1, Jarett Zuboy2

1

Lawrence Berkeley National Laboratory, Berkeley, CA, USA

2

Independent Consultant, Golden, CO, USA

*Correspondence

Mark Bolinger, Lawrence Berkeley National Laboratory, 1 Cyclotron Road, MS 90-4000, 

Berkeley CA 94720

Email: MABolinger@lbl.gov

Recently announced low-priced power purchase agreements (PPAs) for U.S. utility-scale PV 

projects suggest $50/MWh solar might be viable under certain conditions. To explore this 

possibility, this paper draws on an increasing wealth of empirical data to analyze trends in three 

of the most important PPA price drivers: upfront installed project prices, operations and 

maintenance (O&M) costs, and capacity factors. Average installed prices among a sample of 

utility-scale PV projects declined by more than one third (from $5.8/WAC to $3.7/WAC) from the 

2007–2009 period through 2013, even as costlier systems with crystalline-silicon modules, sun 

tracking, and higher inverter loading ratios (ILRs) have constituted an increasing proportion of 

total utility-scale PV capacity (all values shown here are in 2013 dollars). Actual and projected 

O&M costs from a very small sample of projects appear to range from $20–$40/kWAC-year. The 

average net capacity factor is 30% for projects installed in 2012, up from 24% for projects 

installed in 2010, owing to better solar resources, higher ILRs, and greater use of tracking among 

the more recent projects. Based on these trends, a pro-forma financial model suggests that 

$50/MWh utility-scale PV is achievable using a combination of aggressive-but-achievable 

technical and financial input parameters (including receipt of the 30% federal investment tax 

credit). Although the U.S. utility-scale PV market is still young, the rapid progress in the key 

metrics documented in this paper has made PV a viable competitor against other utility-scale 

renewable generators, and even conventional peaking generators, in certain regions of the 

country.

Keywords: utility-scale, capacity factor, power purchase agreement, price trends, O&M, 

economic competitiveness

Short title: Technical and Economic Improvements Drive Utility-Scale PV to $50/MWh

1
1. Introduction

Power purchase agreement (PPA) prices associated with U.S. utility-scale photovoltaic (PV) 

projects have declined precipitously over the past few years (Figure 11), with some recently 

signed contracts averaging around $50/MWh – i.e., roughly half the level commonly seen just a 

few years ago. Most of these projects with ultra-low PPA prices, however, have not yet been 

built, and in many cases are not scheduled to achieve commercial operations until late 2016.2

Others that are already operational (e.g., Macho Springs) or that are scheduled to come online in 

2015 (e.g., Sandstone) benefit from state-level incentives that help to reduce PPA prices3 (Table 

14

).

Figure 1. Levelized U.S. Utility-Scale PV PPA Prices by Operational Status and PPA Execution Date

1 The PPA prices shown in Figure 1 and Table 1 are levelized (using a 7% real discount rate) over the full term of 

each contract, after accounting for any escalation rates and time-of-delivery factors. The PPA price data are drawn 

from FERC Electronic Quarterly Reports, FERC Form 1, Form EIA-923, state regulatory filings, company financial 

filings, and trade press articles.

2 Of the capacity shown in Figure 1, 18%—the newer contracts denoted by the red dashed circles—was not yet 

online at the time of writing. All of these projects are scheduled to be built in 2015 or, more often, 2016. 3 New Mexico’s and Arizona’s 10-year production tax credit (“PTC”) each averages $27/MWh over the full 10-year 

term (though Arizona’s steadily declining credit is worth slightly more on a present value basis). In addition, Macho 

Springs’ ability to share interconnection and other infrastructure with a co-located wind power project was also 

reportedly a significant enabler of its low PPA price.

4 In addition to the four contracts detailed in Table 1, there are at least a dozen planned utility-scale PV projects in 

California with levelized PPA prices in the $55-$65/MWh range (real 2013 dollars), most of which will not be built 

until 2016. These projects benefit from the demand created by California’s renewables portfolio standard (“RPS”), 

but not from direct state-level financial incentives. Another notable project not shown in Figure 1 or Table 1 is First 

Solar’s 18 MWAC Barilla project built in Texas in 2014; it is the first utility-scale PV project in the United States to 

be built on a merchant basis (i.e., without a long-term PPA) to compete directly with wholesale power prices. 

Finally, looking outside of the United States, the Dubai Electricity and Water Authority (“DEWA”) recently 

awarded a 25-year PPA at an unsubsidized price of $58.4/MWh to Saudi Arabia’s ACWA Power for a 200 MW PV 

project in Dubai. Unlike the U.S. projects analyzed in this paper, this Dubai project does not benefit from a 30% 

investment tax credit, and as such has been heralded by some to be the lowest-priced solar contract in the world [3].

$0

$50

$100

$150

$200

$250

$300

Jan-07Jan-08Jan-09Jan-10Jan-11Jan-12Jan-13Jan-14Jan-15

PPA Execution Date

 Operating (4,971 MW, 64 contracts)

 Planned (1,102 MW, 18 contracts)

Levelized PPA Price (2013 $/MWh)

32 MW

210

MW

550 MW

Sample includes 82 PV contracts totaling 6,073 MW

2

 
Table 1. Details on the Four Lowest-Price PPAs in the Sample

Project

Name State

Project

Capacity

(MWAC)

Levelized

PPA Price

(2013 $/MWh)

PPA

Execution

Date & Term

Year

Online

State

Financial

Incentives

Austin Energy/

Recurrent TX 150 $41.0/MWh 5/201420 years 2016 None

Sandstone AZ 45 $44.8/MWh 11/2014

21 years 2015 10-year PTC

Macho

Springs NM 50 $50.9/MWh 10/201220 years 2014 10-year PTC

River

Bend AL 80 $51.0/MWh 2/201520 years 2016 None

This apparent forward-bidding of low PPA prices for projects that are still very much in the 

planning stages begs the question of whether $50/MWh solar is, indeed, achievable (particularly 

without state incentives), or whether developers may have instead gotten ahead of themselves 

and bid too aggressively in “a race to the bottom”? This paper answers this question by drawing

on the wealth of empirical data that has begun to accumulate in the utility-scale PV sector as this 

sector has grown rapidly in recent years. Specifically, it analyzes trends in three of the most

important drivers of PPA prices: upfront installed project prices (the traditional realm of solar 

economics studies; see, for example, [1] and [2]), operations and maintenance (O&M) costs, and 

capacity factors. By analyzing these empirical trends and calculating what it takes to make 

$50/MWh PV a reality, this paper demonstrates that, under best-case conditions (including

receipt of the 30% federal investment tax credit), $50/MWh PV is, indeed, currently achievable.

The paper proceeds as follows. Section 2 describes the total population of utility-scale PV 

projects from which installed price, O&M cost, and capacity factor data samples are drawn in 

subsequent sections. This brief characterization of the project population highlights how project 

development trends are influencing trends in the rest of the data (and the capacity factor data in 

particular). Section 3 updates and extends through 2013 the installed price trend for utility-scale 

PV projects that was recently presented within this same journal through 2012 [1]. Installed 

prices, however, tell only part of the story: Sections 4 and 5 present trends in the equally 

important O&M costs and capacity factors, respectively. Section 6 then uses the empirical data 

presented in Sections 3, 4, and 5 as inputs into a simple pro-forma financial model exploring 

whether a $50/MWh PPA is feasible based on benchmarks already being observed in the market.

Section 7 briefly concludes.

3
2.0 Characterization of the Utility-Scale PV Sector

Although specific definitions vary,5 “utility-scale PV” generally refers to large (multi-megawatt) 

PV projects that generate electricity for sale to utilities at wholesale prices rather than for onsite 

consumption. In the United States, utility-scale PV has been the fastest-growing sector of the 

overall PV market (which also includes the residential and commercial sectors) since 2007, and 

since 2012 it has accounted for the largest share of the overall PV market in terms of new 

capacity installed [5]. This dominance is projected to continue through 2016 [5], with subsequent 

prospects dependent on whether or not the 30% federal investment tax credit is extended beyond 

2016 or reverts to 10% at the end of that year, as currently scheduled.

This paper defines utility-scale PV to include any ground-mounted project with a capacity rating 

larger than 5 MWAC. Based on this definition, 126 utility-scale PV projects totaling 3,023 MWAC

were fully online and operating in the United States by the end of 2013.6 The first of these 

projects came online in 2007, and—highlighting just how young this sector is—92% of this

capacity was installed in the 3 years from 2011 through 2013 (Figure 2). Most of this capacity 

(86%) is installed in the southwestern United States (broadly defined here to include the five 

states of California, Nevada, Arizona, New Mexico, and Colorado)—a region with a strong solar 

resource and state-level policies (such as renewable portfolio standards and state-level tax 

credits) that encourage utility-scale solar deployment.7

Within this utility-scale PV project population, projects can be classified into four main 

categories, depending on the type of module used—crystalline-silicon (c-Si) or thin-film 

(primarily cadmium telluride)—and whether the modules are mounted at a fixed-tilt or on a 

system that tracks the sun.

8 Over time, there has been a trend towards projects using c-Si 

modules, often in conjunction with single-axis tracking (Figure 2). As a result, at the end of 

2013, c-Si projects accounted for substantially more capacity than thin-film projects (69% versus 

31%), while the overall proportions of fixed-tilt and tracking capacity were about even (after 

tracking accounted for 60% of the record amount of new utility-scale PV capacity installed in the 

United States in 2013). Specifically, the total project population of 3,023 MWAC was dominated 

by tracking c-Si projects (1,489 MWAC), followed by fixed-tilt thin-film (893 MWAC) and fixedtilt c-Si (595 MWAC) projects, along with just two tracking thin-film projects (47 MWAC).

5 Bolinger and Weaver [4] describe some of the variations. For example, the U.S. Energy Information 

Administration (EIA) characterizes any project of 1 MWAC or larger as utility-scale, while GTM Research and the 

Solar Energy Industries Association (SEIA) [5] base the distinction on the offtake arrangement (i.e., whether the 

solar electricity is primarily consumed on site or sold to a utility) rather than on project capacity. 6 The utility-scale PV characteristics presented here are drawn from Form EIA-860, FERC Form 556, state 

regulatory filings, the National Renewable Energy Laboratory (NREL), SEIA, Google Earth, and trade press 

articles.

7 See [4] for a map of the United States that shows specific project locations in relation to solar resource strength. 8 All of the PV projects in the population that use tracking systems use single-axis (as opposed to dual-axis) 

tracking. Dual-axis tracking is not yet seen as cost effective in the market.

4

 
Figure 2. Historical U.S. Utility-Scale PV Capacity by Module Type and Project Configuration

Two development trends within this population are worth noting for the positive impact they 

have on project performance, as measured by capacity factor.9 First, the average solar resource 

strength (defined in Figure 3 in terms of direct normal irradiance or DNI) across the project 

population has generally increased with project vintage. On average, more recent projects have

been built at sites with a stronger solar resource (red line and left scale in Figure 3). All else 

equal, this trend boosts average capacity factors.

Second, as module costs have fallen more rapidly than inverter costs, developers have been 

increasing the capacity of the direct-current (DC) module array relative to the alternating-current 

(AC) inverter rating as a way to squeeze more electricity (e.g., during shoulder periods) out of 

the existing inverter(s) and thereby boost revenue—particularly under PPAs that use time-ofdelivery pricing [6]. This DC/AC capacity ratio, known by a variety of names, is referred to here 

as the inverter loading ratio (ILR).10 Figure 3 shows that the average ILR has increased from 

roughly 1.18 for 2010- and 2011-vintage projects to nearly 1.27 for 2013-vintage projects. All 

else equal, as the ILR increases, so will the amount of generation per unit of AC capacity, 

resulting in a higher capacity factor in AC terms (in DC terms, capacity factor will actually 

decrease as the ILR increases11).

9 Capacity factor is a measure of the actual generation from a project as a percentage of the maximum possible 

generation from that project if it were operating at full capacity at all times. The specific formula for calculating 

cumulative capacity factor is provided later in footnote 26. 10 The ILR is also referred to as DC/AC ratio, array-to-inverter ratio, oversizing ratio, overloading ratio, and DC 

load ratio [6,7]. 11 For example, a project with a 30% capacity factor in AC terms would have a 25% capacity factor in DC terms at 

an ILR of 1.20 and a 20% capacity factor in DC terms at an ILR of 1.50.

0

200

400

600

800

1,000

1,200

1,400

1,600

2007 2008 2009 2010 2011 2012 2013

 Tracking Thin-Film (columns=annual, line=cumulative)

 Fixed-Tilt Thin-Film (columns=annual, line=cumulative)

 Tracking c-Si (columns=annual, line=cumulative)

 Fixed-Tilt c-Si (columns=annual, line=cumulative)

Annual and Cumulative Capacity (MWAC)

Year Online

5

 
Figure 3. Trends in DNI and ILR by PV Project Vintage

3.0 Falling Installed System Prices

Figure 4 shows installed price data12 for 98 utility-scale (i.e., ground-mounted and larger than 5 

MWAC) PV projects, totaling 2,599 MWAC, built between 2007 and 2013.13 By definition, this 

sample is backward-looking, in the sense that only projects that were fully operational by the end 

of 2013 are included.

14 Moreover, installed prices within this backward-looking sample may 

reflect transactions (e.g., entering into an engineering, procurement, and construction—or EPC—

contract) that occurred one or more years prior to project completion. In some cases, those 

transactions may have been negotiated on a forward-looking basis, reflecting anticipated future 

costs at the time of project construction. In other cases, they may have been based on 

contemporary costs (or a conservative projection of costs), in which case the reported installed 

price data may not fully capture recent reductions in component costs or other changes in market 

conditions.15 For these reasons, the data presented in this section may not correspond to other 

recent installed price benchmarks for utility-scale PV and may differ from the average installed 

prices reported elsewhere (e.g., in [5]).

12 Installed “price” is reported (as opposed to installed “cost”) because, in many cases, the value reported reflects 

either the price at which a newly completed project was sold (e.g., through a sale/leaseback financing transaction) or 

the fair market value of a given project (the price at which it would be sold through an arms-length transaction in a 

competitive market). 13 This sample for which installed price data are available represents 78% of the total number of projects (86% of the 

total capacity) in the project population described in Section 2. The installed price information presented here is 

drawn from Section 1603 grant data from the U.S. Treasury, FERC Form 1, data from applicable state rebate and 

incentive programs, state and federal regulatory filings, company financial filings, trade press articles, and NREL.

14 This contrasts with the PPA prices shown in Figure 1, where 18% of the capacity in that sample is not yet 

operational.

15 This may partially explain why the decline in installed prices presented in this section seemingly has not kept pace 

with the decline in PPA prices shown in Figure 1.

1.15

1.17

1.19

1.21

1.23

1.25

1.27

5.20

5.40

5.60

5.80

6.00

6.20

6.40

2010 2011 2012 2013

 Average DNI (left scale)

 Average ILR (right scale)

Average ILR (DC/AC)

Project Vintage

Average DNI (kWh/m2/day)

6

 
Although utility-scale PV capacity is more appropriately reported in AC (rather than DC)

terms,

16 Figure 4 shows installed prices in both $/WAC and $/WDC terms to provide continuity 

between this paper and others (e.g., [1], [2] and [5]) that have expressed installed prices only in 

$/WDC terms. Apart from Figure 4, the remainder of this paper reports data exclusively in AC 

terms.

As shown in Figure 4, average installed prices among the sample of utility-scale PV projects 

have declined by more than one third from the 2007–2009 period through 2013, as capacityweighted average prices dropped from $5.8/WAC to $3.7/WAC over that timeframe. Most of this 

decline occurred through 2012, however, as capacity-weighted average prices within the sample 

were little changed from 2012 ($3.8/WAC) to 2013 ($3.7/WAC).

Figure 4. Installed Price of U.S. Utility-Scale PV, 2007–2013

Anecdotally, a similar pattern of slowing price declines even among forward-looking prices is 

evident in a recent Public Service Company of New Mexico (PNM) filing for regulatory 

approval of 40 MWAC of utility-scale PV scheduled to be built in 2015 (as two separate 20-

MWAC projects). The company expects this new turnkey capacity to cost $1.98/WAC, which is 

down only slightly from the $2.03/WAC it is currently paying for another 23-MWAC project built 

in 2014.17

Though capacity-weighted average prices in the sample have declined over time (at least through 

2012), there remains a considerable spread in individual project prices. Among the 25 PV 

projects in the sample that were completed in 2013, for example, installed prices range from 

16 AC capacity is more appropriate for utility-scale PV because all other utility-scale generation sources to which 

utility-scale PV is compared—including concentrating solar power projects—are described in AC capacity terms. In 

addition, as described in Section 2, ILRs have increased over time, making the DC capacity of a project less 

meaningful (given that output is increasingly constrained by the AC inverter rating).

17 Both of these prices (of ~$2/WAC) are down more substantially from the $2.25/WAC that PNM paid for another 20 

MWAC built in 2013 and the $3.99/WAC that it paid for an initial 22.5 MWAC built in 2011 [8]. PNM’s 2011 price 

point of roughly $4/WAC is consistent with the capacity-weighted average price for 2011 shown in Figure 4, while 

PNM’s 2013 price point of $2.25/WAC is at the low end of the overall range for 2013.

$0

$1

$2

$3

$4

$5

$6

$7

$8

$9

$10

2007-2009

n=5 (75 MW-AC)

2010

n=10 (170 MW-AC)

2011

n=25 (397 MW-AC)

2012

n=33 (786 MW-AC)

2013

n=25 (1170 MW-AC)

Installed Price (2013 $/W)

Installation Year

 Capacity-Weighted Averages

 Individual Projects - $/MW-DC

 Individual Projects - $/MW-AC

7

 
$2.2/WAC to $5.6/WAC, and prior years also show substantial variability. This price variation is 

partially attributable to differences in module type and project configuration (Figure 5).

Figure 5. Installed Price of U.S. Utility-Scale PV by Module Type and Project Configuration, 2007–2013

For example, although projects using c-Si modules historically have been significantly more 

expensive than projects using thin-film modules (e.g., by $2.1/WAC on average in 2010, though 

based on a very small sample), the average installed price of c-Si and thin-film projects largely 

converged in 2011, precipitating the start of a significant increase in the number of c-Si projects 

in both the installed price sample and the broader population (see Figure 2).

18 Since 2011, there 

have been only minor differences in installed prices across these categories, with c-Si projects 

being slightly more expensive than thin-film (just $0.4/WAC on average in 2013 among fixed-tilt 

projects) and with tracking projects only slightly more expensive than fixed-tilt (just $0.20/W on 

average in 2013 among c-Si projects). As discussed in Section 5, however, the higher upfront 

cost of single-axis tracking provides a benefit in terms of greater energy production and hence 

likely lower $/MWh costs over a project’s life.19

4.0 O&M Costs

In addition to upfront installed project prices, utility-scale PV projects incur ongoing O&M 

costs. Publicly available empirical data on the O&M costs of utility-scale PV projects are hard to 

obtain. Relatively few utility-scale PV projects have been operating for more than a full year, 

and even fewer of those projects are owned by investor-owned utilities, which are required by 

the Federal Energy Regulatory Commission (FERC) to report on Form 1 the O&M costs of the 

18 This shift towards c-Si can be illustrated anecdotally by the Copper Mountain projects in Nevada: the first three 

phases (built from 2008–2012) use thin-film modules, while the fourth phase (planned for 2015) will use c-Si 

modules. In a similar nod to the increasing cost competitiveness of c-Si, PNM’s 40 MWAC slated for 2015 will use 

c-Si modules, in contrast to its previous projects (built in 2011, 2013, and 2014), all of which use thin-film modules.

In its recent regulatory filing, PNM attributes the switch to c-Si solely to cost considerations [8]. 19 For example, based on its review of offers received in response to a renewable energy request for proposals, PNM 

estimated that the average PPA price benefit of single-axis tracking was $3/MWh, or about 4% of a levelized PPA 

price in the mid-$70/MWh range [9].

$0

$2

$4

$6

$8

$10

n=5 (75 MW) n=10 (170 MW) n=25 (397 MW) n=33 (786 MW) n=25 (1170 MW)

Installed Price (2013$/WAC)

Installation Year

 Fixed-Tilt c-Si Fixed-Tilt Thin-Film

 Tracking c-Si Tracking Thin-Film

2007-2009 2010 2011 2012 2013

Capacity-Weighted Averages

8

 
power plants they own.20 Finally, even fewer of those investor-owned utilities that own utilityscale PV projects actually report operating cost data in FERC Form 1 as they are required to.

Because of these limitations, the sample of utility-scale PV projects for which O&M cost data 

are publicly available is very small: just seven projects totaling 60 MWAC (see the left graph in 

Figure 6).21 Two of these projects have historical data for more than 2 years; the other five have 

data for only 2012 and 2013. Despite the extremely limited sample (and the considerable range 

of costs within it), reported empirical O&M costs seem to fall largely within the neighborhood of 

$20–$40/kWAC-year. The sample is too small to discern any sort of time trend, however, and the 

data are included here primarily to help benchmark the operating cost input assumption to the 

pro forma financial model later in Section 6.

Figure 6. Operating and O&M Costs for U.S. Utility-Scale PV Projects from Empirical Data (left) and Bond Rating 

Agency Research (right)

To supplement the limited empirical data, the graph on the right of Figure 6 presents projected

O&M (dashed lines) as well as total operating (OpEx, solid lines22) costs from two large projects 

that have financed a portion of their capital costs through public bond offerings, thereby 

necessitating the disclosure of detailed project information [10,11]. The 550-MW Topaz project 

is a fixed-tilt thin-film project, while the 579-MW Solar Star project uses c-Si with single-axis 

tracking. Both projects are located in California and, at the time of writing, were either fully 

online (Topaz) or under construction and delivering electricity from early phases (Solar Star).

Though not empirical data, and perhaps tending to be conservative in nature,

23 projected O&M

and operating costs for these two projects are instructive. As shown, the two PV projects have 

20 FERC Form 1 uses the “Uniform System of Accounts” to define what should be reported under “operating 

expenses,” namely those operational costs associated with supervision and engineering, maintenance, rents, and 

training. Though definitions may vary, FERC Form 1’s “operating expenses” are largely consistent with what most 

industry participants would consider to be O&M costs, rather than total operating expenses. 21 The O&M cost information presented in this section is drawn from FERC Form 1 and FitchRatings. 22 In addition to O&M costs—i.e., those costs incurred directly to operate and maintain the generating plant itself—

total operating expenses include property taxes, insurance, land royalties, performance bonds, various administrative 

and other fees, and overhead [10,11]. 23 Given that these projected O&M costs are obtained from documentation intended to support a credit rating, they 

may be conservatively high to provide comfort to potential bond buyers. In fact, in its published research on each 

project, the credit rating agency Fitch noted the robust nature of operating cost projections, referring in particular to 

0

10

20

30

40

50

60

70

2010 2011 2012 2013

O&M Costs (2013 $/kWAC-year)

 Generation-weighted average

 Fixed-Tilt c-Si (2 projects, 15 MW)

 Fixed-Tilt Thin-Film (4 projects, 20 MW)

 Tracking c-Si (1 project, 25 MW)

0

10

20

30

40

50

60

70

201620182020202220242026202820302032203420362038

Operating Costs (2013 $/kWAC-year)

Solar Star (tracking c-Si)

Topaz (fixed-tilt thin-film)

Total

OpEx

Just

O&M

9

 
very similar O&M and total operating cost projections, with O&M costs in the $22 to $36/kWACyear range over time—i.e., largely consistent with the limited empirical sample shown in the left 

graph.24 For both projects, projected O&M costs account for about 75% of total projected 

operating costs.

5.0 Rising Capacity Factors

At the close of 2013, at least 64 utility-scale PV projects totaling 1,532 MWAC had been 

operating for at least 1 full year (and for as many as 6 full years), thereby enabling the 

calculation of capacity factors.25,26 Although the capacity-weighted average cumulative capacity 

factor across this sample is 27.5%,27 Figure 7 shows a considerable variation in individual 

project-level capacity factors (from 16.6% to 32.8%) around this central tendency. This variation 

can be explained by a number of factors, including (in approximate decreasing order of 

importance): the strength of the solar resource at the project site (measured in DNI with units of 

kWh/m2

/day), whether the array is mounted at a fixed-tilt or on a tracking mechanism, the DC 

capacity of the array relative to the AC inverter rating (the ILR), and the type of modules used 

(c-Si versus thin-film).28

long-term, fixed-price O&M contracts with experienced operators covering both routine maintenance and major 

repair and replacement costs as well as the allocation of additional funds for any O&M contingencies that might 

arise [10,11]. For this reason, actual O&M costs for these projects might tend to be lower than shown in Figure 6.

On the other hand, these are both very large projects, and smaller projects might experience higher per-unit O&M 

costs if economies of scale are present.

24 The projected O&M costs for Solar Star are also consistent with PNM’s $21/kWAC-year estimate of annual O&M 

costs (which, in addition to O&M contract costs, also include costs associated with vegetation and animal 

management, vandalism, and other property damage) for 40 MWAC (split into two 20-MWAC projects) of tracking cSi projects that it plans to build in 2015 [8]. 25 The capacity factor information presented here is drawn from FERC Electronic Quarterly Reports, FERC Form 1, 

Form EIA-923, and state regulatory filings. 26 The capacity factor formula is: Net Generation (MWhAC) over Single- or Multi-Year Period / [Project Capacity 

(MWAC) × Number of Hours in that Same Single- or Multi-Year Period]. As such, the capacity factors presented in 

this section represent cumulative capacity factors—i.e., they are calculated over as many full years of data as are 

available for each individual project, ranging from just 1 year (2013) for projects built in 2012 to a maximum of 6 

years (2008–2013) for projects built in 2007. In addition, the capacity factors are expressed in net, rather than gross, 

terms (i.e., they represent the output of the project net of its own use). They are also calculated in AC terms (i.e., 

using the MWAC rather than MWDC capacity rating), which results in higher capacity factors than if reported in DC 

terms (see footnote 11) but allows for direct comparison with the capacity factors of other generation sources (e.g., 

wind energy or conventional energy), which are also calculated in AC terms.

27 The median is 26.9%, and the simple average is 25.9%. 28 Other factors such as tilt and azimuth also play a role; however, since this paper focuses only on ground-mounted 

utility-scale projects, we assume these fundamental parameters will be optimized equally across projects to 

maximize energy production.

10

 
Figure 7. Cumulative U.S. Utility-Scale PV Capacity Factor by Resource Strength, Fixed-Tilt vs. Tracking, ILR, and 

Module Type

Project vintage might also be expected to play a role, with newer projects having higher capacity 

factors because the efficiency of PV modules (both c-Si and thin-film) has increased over time.

As module efficiency increases, however, developers simply either use fewer modules to reach a 

fixed amount of capacity (thereby saving on balance-of-system and land costs as well), or they

use the same number of them to boost the amount of capacity installed on a fixed amount of land 

(which directly reduces at least $/WDC costs, if not also $/WAC costs). In other words, for PV 

more than for other technologies like wind power, efficiency improvements over time show up 

primarily as cost savings rather than as higher capacity factors. Any increase in capacity factor 

by project vintage is therefore most likely attributable to a time trend in one of the other 

variables noted above, e.g., towards higher ILRs, a higher DNI, or greater use of tracking.

Figure 8 supports this hypothesis by breaking out the average cumulative net capacity factor by 

project vintage across the sample of projects built in 2010, 2011, or 2012 (and by noting the 

relevant average project parameters within each vintage). As shown, the average capacity factor 

does not differ much on average between 2010- and 2011-vintage projects, which makes sense

given the lack of significant change in average ILR across vintages, in conjunction with the 

opposing influences of a lower DNI and a higher proportion (in capacity terms) of projects using 

tracking among 2011-vintage projects. Projects built in 2012, however, have a notably higher 

capacity factor on average (almost 30%), driven by a significant increase in both the average ILR 

and the average DNI.

29 Because average DNI and ILR increased among the fleet of projects built 

29 The sharp increase in the average capacity factor among 2012-vintage projects comes in spite of reports that the 

insolation in the southwestern United States (where many of these projects are located) was below normal in 2013 

[12]. With just a single year—2013—contributing to the capacity factor calculation, the 2012-vintage projects 

presumably would be impacted more negatively than the 2010- and 2011-vintage projects by sub-par 2013 

insolation.

0%

5%

10%

15%

20%

25%

30%

35%

ILR<1.15

1.15-1.25

ILR≥1.25

ILR<1.15

1.15-1.25

ILR≥1.25

ILR<1.15

1.15-1.25

ILR≥1.25

ILR<1.15

1.15-1.25

ILR≥1.25

ILR<1.15

1.15-1.25

ILR≥1.25

ILR<1.15

1.15-1.25

ILR≥1.25

Fixed-Tilt Tracking Fixed-Tilt Tracking Fixed-Tilt Tracking

Solar Resource of <5 kWh/m2/day Solar Resource of 5-7 kWh/m2/day Solar Resource of ≥7 kWh/m2/day

Cumulative Net Capacity Factor

 Capacity-Weighted Average (all projects)

 Individual Project (c-Si)

 Individual Project (thin-film)

1 project18 MW

6 projects89 MW

1 project10 MW

3 projects41 MW

3 projects46 MW2 projects25 MW3 projects53 MW

6 projects

95 MW5 projects50 MW2 projects31 MW

2 projects70 MW

5 projects246 MW

7 projects461 MW7 projects90 MW

6 projects106 MW

5 projects101 MW

Sample includes 64 projects totaling 1,532 MWAC that came online from 2007 through 2012

11

 
in 2013 (Figure 3), additional increases in capacity factors might be expected among 2013-

vintage projects.

Figure 8. Cumulative U.S. Utility-Scale PV Net Capacity Factor (NCF) by Project Vintage: 2010-2012 Projects Only

6.0 Achieving $50/MWh PV

This paper so far portrays an increasingly competitive utility-scale PV sector, with installed 

prices falling even as developers shift towards more-expensive project configurations involving 

single-axis tracking and/or higher ILRs to boost production and, hence, AC capacity factors. But 

is this progress enough to justify the $50/MWh PPAs that have been signed recently (as shown in 

Figure 1 and Table 1)? This section addresses this question by using a pro-forma financial model 

to see whether input assumptions drawn from the empirical data presented in previous sections, 

in conjunction with current market-based financing parameters, yield a PPA price close to

$50/MWh (without state-level incentives).

The simple pro-forma financial model—developed for and detailed within [13]—assumes that 

the project is financed solely by a combination of sponsor equity and long-term project-level 

debt (i.e., no third-party tax equity) and that the sponsor has sufficient “tax appetite” to make 

efficient use of tax losses (5-year MACRS depreciation30) and credits (the 30% federal 

investment tax credit) in the years in which they are generated. This simple financing structure, 

involving such a tax-efficient sponsor, will yield a lower overall weighted-average cost of capital 

than complicated partnership flip or sale-leaseback structures involving third-party tax equity 

[13]; hence this should be considered a best-case financing scenario.

Similarly, to reach $50/MWh, the inputs drawn from the empirical data in Sections 3–5 

presumably also must reflect best-case conditions. The column titled “Case 1” in Table 2 reflects 

these assumptions: $2.25/WAC is the low end of the installed price range among 2013-vintage 

projects from Figures 4 and 5, total operating expenses of $30/kWAC-year (assumed to escalate in 

30 MACRS stands for Modified Accelerated Cost Recovery System.

0%

5%

10%

15%

20%

25%

30%

2010 Vintage 2011 Vintage 2012 Vintage

7 projects 32 projects 19 projects

144 MW 463 MW 842 MW

Cap-Wgtd Avg Cumulative Net Capacity Factor

Cap-Wgtd Avg:

NCF = 24.2%

ILR = 1.20

DNI = 6.53

Tracking = 13% (MW)

Cap-Wgtd Avg:

NCF = 29.9%

ILR = 1.27

DNI = 7.40

Tracking = 27% (MW)

Cap-Wgtd Avg:

NCF = 24.6%

ILR = 1.19

DNI = 6.15

Tracking = 51% (MW)

12

 
nominal dollars at the assumed inflation rate of 2%/year) seem feasible based on Figure 6, and a 

33% capacity factor (in AC terms) matches the best projects shown in Figure 7. The assumed 

output degradation rate of 0.5%/year is an industry standard that is commonly used within 

utility-scale PV PPAs to reduce expected/promised generation over time [14]. Recent financing 

parameters come from [13] and include a 10% after-tax internal rate of return (IRR) for the 

project sponsor and a 5.5% all-in interest rate on 17-year term debt with a debt service coverage 

ratio (DSCR) of 1.3531—all of which enables a capital structure (determined endogenously by 

the model) of 54% equity and 46% debt.

The bottom row of Table 2 shows that this particular combination of aggressive-but-achievable 

input parameters breaks the $50/MWh threshold on a real dollar basis. Since Figure 1 and Table 

1 are also expressed in real 2013 $/MWh, we can conclude that the scenario laid out in Table 

2/Case 1 is largely consistent with recent PPA prices shown in Figure 1 and Table 1.

Table 2. Key Inputs for Pro-Forma PPA Modeling

Modeling Parameter Case 1 Case 2 Source

Installed Cost ($/WAC) 2.25 1.55 Section 3 (for Case 1)

Net Capacity Factor (AC) 33% 25% Section 5

Total Operating Expenses ($/kWAC-year) 30 Section 4

Annual Degradation 0.5% [14]

Sponsor After-Tax Internal Rate of Return (IRR) 10%

Recent market-based financing

terms from [13]

Term Debt Interest Rate 5.5%

Debt Term (years) 17

Debt Service Coverage Ratio (P50) 1.35

Capital Structure (%Equity/%Debt) 54%/46% Determined by model

Levelized 20-Year PPA Price (2013 $/MWh) $49.9/MWh $49.8/MWh Model Output

Absent even higher inverter loading ratios, dual-axis tracking, and/or project-level storage 

becoming economical, however, the applicability of the 33% net capacity factor (in AC terms) 

assumed in Case 1 will be limited to projects located in the best resource areas (e.g., in the 

southwestern United States). To examine what it takes to achieve $50/MWh solar in other parts 

of the United States, Case 2 of Table 2 assumes a more modest capacity factor of 25% – shown 

earlier to be nearly achievable (with tracking) in even the lowest resource bin of Figure 7. All 

other inputs except installed price are held constant in Case 2, given that operating costs, 

degradation, and financing terms should not differ materially by location. As shown, in order for 

Case 2 to break $50/MWh in real dollar terms, the installed price must fall to $1.55/WAC – i.e., 

well below the range of installed prices seen in Figures 4 and 5 among the sample 2013-vintage 

projects, but perhaps achievable within the next few years, given analyst projections [2] and 

lower installed price benchmarks in Germany [15,16].

Finally, the results in Table 2 assume access to the 30% federal investment tax credit in Section 

48 of the tax code. This 30% credit is scheduled to revert to 10% for any project placed in 

service after December 31, 2016. Rerunning Case 1 and Case 2 with the same input assumptions 

except for a 10%, instead of 30%, investment tax credit yields real levelized PPA prices of 

31 The DSCR of 1.35 is based on a P50 (i.e., median) generation estimate.

13

 
$62.6/MWh and $61.3/MWh, respectively.

32 Hence, if the investment tax credit reverts to 10% 

as currently scheduled, project sponsors will need to find additional cost or performance 

improvements to achieve $50/MWh PPA prices.33

7.0 Conclusion

Although the U.S. utility-scale PV market is young and the operating history of many projects 

(particularly the record amount of new capacity built in 2013) is still very limited, a critical mass 

of project-level data now enables empirical analysis of this rapidly growing sector of the market.

This paper draws on the increasing wealth of data to illuminate progress in PPA prices, installed 

project prices, operating costs, and capacity factors. Using a pro-forma financial model, it also

demonstrates that the recent remarkable decline of PPA prices to $50/MWh appears to be 

justified by the combined progress in installed prices and capacity factors. This progress has

helped make PV the dominant utility-scale solar technology in the United States and a viable 

competitor against other renewable generators, and even conventional peaking generators, in 

certain regions of the United States.

Acknowledgments

The work described in this paper was funded by the U.S. Department of Energy’s Solar Energy 

Technologies Office, within the Office of Energy Efficiency and Renewable Energy, under 

Contract No. DE-AC02-05CH11231.

References

1. Barbose G, Darghouth N, Weaver S, Feldman D, Margolis R, Wiser R. Tracking US 

photovoltaic system prices 1998–2012: A rapidly changing market. Progress in Photovoltaics: 

Research and Applications 2014; DOI: 10.1002/pip.2482.

2. Feldman D, Barbose G, Margolis R, James T, Weaver S, Darghouth N, Fu R, Davidson C, 

Booth S, Wiser R. Photovoltaic System Pricing Trends: Historical, Recent, and Near-Term 

Projections – 2014 Edition. NREL/PR-6A20-62558. National Renewable Energy Laboratory:

Golden, CO, 2014.

3. Dipaola, A. “Dubai Doubling Size of Power Plant to Make Cheapest Solar Energy.”

Bloomberg, January 15, 2015. http://www.bloomberg.com/news/articles/2015-01-15/acwapower-wins-contract-to-build-dubai-solar-plant-acwa-ceo, accessed February 19, 2015.

32 This $12-$13/MWh (in real 2013 dollars) increase in levelized PPA prices resulting from the reversion of the 30% 

investment tax credit back to 10% is perhaps more modest of an impact than one might expect, in large part due to a 

corresponding shift in the project’s capital structure. Specifically, as the size of the credit decreases to 10%, the 

amount of leverage the project can support increases from 46% (see Table 2) to 61%. Because debt is cheaper than 

equity, the greater amount of leverage possible under the 10% credit partially mitigates the negative impact of the 

declining credit [13]. 33 If federal tax incentives were eliminated altogether (e.g., no investment tax credit at all, and a 12-year straight-line 

rather than a 5-year accelerated depreciation schedule), the corresponding real levelized PPA prices for Case 1 and 

Case 2 would be $76.8/MWh and $74.2/MWh, respectively. In this light, the aforementioned $58.4/MWh 

unsubsidized PPA price between ACWA Power and DEWA for a planned 200 MW project in Dubai does indeed 

seem unprecedented [3].

14

 
4. Bolinger M, Weaver S. Utility-Scale Solar 2013: An Empirical Analysis of Project Cost, 

Performance, and Pricing Trends in the United States. Lawrence Berkeley National Laboratory: 

Berkeley, CA, 2014.

5. GTM Research, Solar Energy Industries Association. U.S. Solar Market Insight Report: 2013 

Year in Review. Solar Energy Industries Association: Washington, DC, 2014.

6. Fiorelli J, Zuercher‐Martinson M. Array Oversizing (White Paper). Solectria Renewables: 

Lawrence, MA, 2013.

7. Advanced Energy. DC Loading of AE TX Inverters. http://solarenergy.advancedenergy.com/upload/File/Application%20Notes/ENG-DCLoadingTX-260-02_Web.pdf, accessed 

July 31, 2014.

8. O’Connell P. Direct Testimony of Patrick J. O’Connell, Case No. 14-00158-UT, In the Matter 

of Public Service Company of New Mexico’s Renewable Energy Portfolio Procurement Plan for 

2015 and Proposed 2015 Rider Rate under Rate Rider No. 36, filed before the Public Regulation 

Commission of New Mexico, June 2, 2014.

9. O’Connell P. Direct Testimony of Patrick J. O’Connell, Case No. 13-00183-UT, In the Matter 

of Public Service Company of New Mexico’s Renewable Energy Portfolio Procurement Plan for 

2014 and Proposed 2014 Rider Rate under Rate Rider No. 36, filed before the Public Regulation 

Commission of New Mexico, July 1, 2013.

10. Fitch Ratings. Topaz Solar Farms LLC. Presale Report. Fitch Ratings: New York, February 

14, 2012.

11. Fitch Ratings. Solar Star Funding, LLC. Presale Report. Fitch Ratings: New York, June 13, 

2013.

12. 3TIER. Solar Variance from Average: June-August 2013. 

http://www.3tier.com/static/ttcms/us/documents/SolarPerformance_Summer2013.pdf, accessed 

July 31, 2014.

13. Bolinger M. An Analysis of the Costs, Benefits, and Implications of Different Approaches to 

Capturing the Value of Renewable Energy Tax Incentives. LBNL-6350E. Lawrence Berkeley 

National Laboratory: Berkeley, CA, 2014.

14. Bolinger M, Weaver S. Utility-Scale Solar 2012: An Empirical Analysis of Project Cost, 

Performance, and Pricing Trends in the United States. LBNL-6408E. Lawrence Berkeley 

National Laboratory: Berkeley, CA, 2013.

15. Kelm, T., Schmidt, M., Taumann, M., Puettner, A., Jachmann, H., & Capota, M. 

Vorbereitung und Begleitung der Erstellung des Erfahrungsberichts 2014 gemaess Paragraph 

65 EEG, Zwischenbericht IIc: Stromerzeugung aus Solarer Strahlungsenergie. ZSW, IWES, 

Bosch & Partner, GfK, 2014.

16. Fraunhofer ISE. Photovoltaics Report. October 24, 2014.

15