Porter’s Five Forces
In this section, we begin by exploring Porter’s five forces in utility-scale solar project development and EPC; specifically, these are: the threat of new entrants, the threat of established rivals, the threat of substitute products or services, the bargaining power of suppliers, and the bargaining power of customers. The framework is illustrated in Figure SC.1 below and characteristics of each of the forces will be discussed in detail subsequently in the context of PV project development.
Figure SC.1 Porter’s Five Forces
- Industry Rivalry
The utility-scale solar project development industry has a low to moderate level of market share concentration, with the four largest firms accounting for less than 40% of industry installed capacity in 2017 (Solar Project Database). However, this figure is calculated across a variety of solar technologies; within individual technology types, the market concentration is substantially higher and competition has declined in recent years (IBISWorld 2017). As demand for solar energy has grown significantly over the past few years, new companies have entered the industry; at the same time, larger project developers also expanded their market presence through acquisition or partnership.
Competition in utility-scale solar project development and EPC takes place across a variety of factors, primarily cost, project quality, and time to completion. Factors that impacts a firm’s success by these measures include cost management strategies, availability of skilled research personnel, hiring practices for local labor, and secure supply of high-quality PV modules (IBISWorld 2017). Labor costs vary widely by project location and represent the largest share of variable soft costs, so a firm with practices in place to hire productive workers for a reasonable rate gain strategic advantage. Project development firms that are either vertically integrated with module manufacturing or have standing relationships with outside module manufacturing benefit from reduced uncertainty in their supply chains. Large firms benefit from economies of scale through reduced-price bulk material and equipment purchases.
- Threat of New Entrants
The utility-scale solar project development industry has high barriers to entry, or low threat of new entrants, because of high capital costs associated with solar project construction. Additionally, solar project development requires substantial technical expertise in solar power generation technology, which creates barriers for new entrants. Federal, state, and local permitting and licensing requirements also create barriers to new entrants, who must pay related fees and learn to navigate these regulations (IBISWorld 2017).
- Threat of Substitutes
This industry experiences some level of threat of substitutes, mainly from competition with power plant contractors for other energy types (e.g., natural gas, other renewables). However, competition from fossil fuel power plant contractors has declined over the past five years due to government incentives for renewable energy. The fall in electricity cost from utility-scale solar PV projects since 2010 has been remarkable, making it competitive directly with fossil fuel sources even without government incentives (see Figure SC.2). Their cost gaps are expected to continuously close up in the near future (Table SC.1).
Figure SC.2 Global Levelized Cost of Electricity by Utility-Scale Renewable Power Generation Technologies, 2010-2017 (2016 $/MWh)
Source: Figure 2.1 from IRENA 2018, original source from IRENA Renewable Cost Database
Table SC.1 Estimated Levelized Cost of Electricity (Unweighted Average) for New Generation Resources Entering Service in 2022 (2017 $/ MWh)
Source: Recreated from Table 1a in U.S. EIA Independent Statistics & Analysis (2018) https://www.eia.gov/outlooks/aeo/pdf/electricity_generation.pdf
|Plant Type||Capacity Factor (%)||Levelized Capital Cost||Levelized Fixed O&M||Levelized Variable O&M||Levelized Transmission Cost||Total System LCOE||Levelized Tax Credit||Total LCOE incl. tax credit|
|Coal with 30% CCS||85||84.0||9.5||35.6||1.1||130.1||N/A||130.1|
|Coal with 90% CCS||85||68.5||11.0||38.5||1.1||119.1||N/A||119.1|
|Advanced CC with CCS||87||26.9||4.4||42.5||1.1||74.9||N/A||74.9|
- Bargaining Power of Suppliers
The primary suppliers in the context of utility-scale solar project development are mainly PV panel manufacturers and construction machinery manufacturers. The bargaining power of suppliers differs based on a firm’s business model and breadth of services (Table SC.2). By vertically integrating across project development and EPC, and even manufacturing activities, companies can obtain a larger portion of the margin available and can insulate against price fluctuations from suppliers. FirstSolar, the world’s leading thin-film manufacturer, is highly vertically integrated. They offer integrated solutions by not only manufacturing solar panels, but also providing project development and engineering design services for their customers. Bargaining power of suppliers, in this case, is very low. However, most crystalline silicon solar project developers purchase solar and construction equipment from PV manufacturers and equipment OEMs. Hence, project developers who are able to obtain less expensive equipment from their suppliers than other developers are in a better competitive position.
Table SC.2 Range of Services for Selected EPC Firms in U.S. Renewable Energy Industry
Source: Table 2 from The evolving landscape for EPCs in U.S. renewables (BNEF 2014)
- Bargaining Power of Buyers
The “buyer” in the context of project development may be another project development firm (early in the process) or the final operator of the solar project; a project developer may retain ownership of a project once it becomes operational. The bargaining power of buyers is expected to differ depending on the project developer’s business model and degree of vertical integration. Recently, several project developers have moved toward a “build, sell, and operate” model. This is a topic that would benefit from additional future research.
Overview of Geography
Nearly half (46%) of U.S. utility-scale solar generation capacity is located in California (Table SC.3). An additional 24% of generation capacity is located in the Southwest (Arizona, New Mexico, Nevada, Utah and Colorado). These states have also been the sites of the most growth in capacity installations in recent years. Some EPCs operate across the U.S., while others only operate in certain regions (Figure SC.3).
Table SC.3 Utility PV installations by State (MW), 2013-2016
Source: Summarized based on Figure 2.22 in SEIA U.S. Solar Market Insight 2016 Year in Review
|Rest of U.S.||98||199||204||1,592|
Figure SC.3 Top EPC Firms by U.S. Region
Source: Figure 15 from The evolving landscape for EPCs in U.S. renewables (BNEF 2014)
Overview of Governance
Solar PV technologies have become much more affordable and competitive today, due in part to the government financial incentives and regulatory policies that driving the demand for new utility-scale PV capacity. Relevant policies are constantly evolving, and the differences in policies across countries, regions, and states strongly contribute to project developers’ choices of solar plant locations.
Investment Tax Credit (ITC)
The Investment Tax Credit (ITC) has been one of the most influential federal policy mechanisms supporting U.S. solar energy, which currently provides a 30 percent federal tax credit claimed against the tax liability of residential (Section 25D), commercial, and utility (Section 48) investors in solar energy property (SEIA 2017). The ITC is based on the amount of investment in eligible solar property, so in the case of commercial and utility solar, the business that installs, develops and/or finances the project claim the credit. As a result, the ITC helps drive down the cost of constructing new solar projects, increasing business certainty for project developers and investors. A salient feature of the ITC is that it is only valuable to entities that owe tax. If an organization is experiencing losses or otherwise has a low tax bill, the ITC is not useful to them. As a result, ITC-eligible projects are often joint projects between developers and another corporate entity with a large tax liability.
The Solar ITC was first adopted through the Energy Policy Act of 2005 as a method to boost investment in solar energy technologies and to incentivize deployment of residential and utility-scale solar energy in the U.S. The original bill was set to expire at the end of 2007; however, in 2006, the Tax Relief and Health Care Act extended these credits for another year. In 2008, Congress voted in favor of another eight-year extension of the ITC through the Emergency Economic Stabilization Act, and in 2015, the Omnibus Appropriations Act included a multi-year extension of the residential and commercial/utility ITC. The current 30 percent tax credit of ITC will exist for eligible projects that have commenced construction through 2019. The ITC then steps down to 26 percent in 2020 and 22 percent in 2021. After 2021, the utility credit will drop to a permanent 10 percent. As a result, utility-scale solar segment is expected to grow till 2019 as developers try to leverage the 30 percent ITC (SEIA 2016). Figure SC.4 shows the timeline of different ITC extensions and how they impacted the total solar installations.
Figure SC.4 U.S. Solar Installations with ITC Timeline
Source: SEIA web post (2018) https://www.seia.org/solar-industry-research-data
Treasury Grant Program, Section 1603
Under Section 1603 of the American Recovery and Reinvestment Tax Act of 2009, qualifying commercial renewable energy projects can accept a cash payment from Department of Treasury regardless of their tax liability, under the Treasury Grant Program. This grant program became popular as many renewable energy developers and operators generally do not have enough tax liability to take full advantage of the ITC directly and the transaction cost of utilizing the ITC can be quite high (Platzer 2015). Via the Treasury Grant Program, the Treasury pays grants equal to 30% of the cost of solar property placed in service, which is equivalent to the tax write-off currently available under the ITC (NREL 2012).  The program was originally scheduled to terminate on December 31, 2010, but Congress extended it through December 31, 2011. Property that is not placed in service prior to December 31, 2011, can qualify for the grant program as long as construction has commenced prior to that date. As of 2017, this program had awarded almost $9 billion in grants to roughly 20,000 non-residential solar projects, adding up to nearly 9 GW of capacity (Department of Treasury 2017).
Loan Guarantee Program, Section 1705
Section 1705 Loan Guarantee Program of Title XVII, added by the American Recovery and Reinvestment Act authorized DOE to guarantee loans for certain clean energy projects. Developing a utility-scale solar project is very capital-intensive, and the loan guarantee program allows project developers to gain access to low-cost financing and a higher amount of capital than private markets would provide without the program. Through January 2012, solar projects supported solely under Section 1705 of the loan guarantee program received $12 billion in loans to add 3,500 MW of utility solar capacity (both PV system plants and concentrating solar power plants). To support the solar project loans, an estimated $1.4 billion in credit subsidy costs have been paid under the American Recovery and Reinvestment Act. The credit subsidy is a fund set aside by the DOE to cover the costs associated with specific project failures. The loan guarantee program required an average credit subsidy of 11.7% per project, so every dollar the DOE spends in credit subsidy will support $8.55 in loan (NREL 2012).  The program awarded projects that commenced construction on or before September 30, 2011 and was suspended after that date.
Renewable Energy Credits (RECs)
Renewable Energy Credits (RECs), also known as Renewable Energy Certificates, or Renewable Electricity Certificates, were first created as a means to track progress towards and compliance with states’ Renewable Portfolio Standards (RPS). Some states offer RECs that power plants that generate excess renewable energy can trade or sell to other electricity utilities (IBISWorld 2017). RECs are tradable, non-tangible energy commodities that represent the environmental benefits associated with one megawatt-hour (MWh) of electricity generated from renewable sources. The REC mechanism is designed to incentivize carbon-neutral renewable energy by providing a production subsidy to electricity generated from renewable sources.
Renewable Portfolio Standard (RPS)
On the state level, renewable portfolio standards (RPS) require utilities to generate a certain portion of their electricity from renewable sources, including solar. Over the past five years, many states implemented RPSs or increased the target levels of existing RPSs, which contributed to greater demand for solar energy. The U.S. Energy Information Administration (EIA) estimates that annual solar electricity generation has increase an annualized 70 percent in the past five years (SEIA 2016), in part due to the prevalence of RPSs. The solar project development industry experienced this as a boost in demand for its firms’ services, which benefited overall industry revenue and created many job opportunities for solar operations (IBISWorld 2017).
Propensity to adopt an RPS varies by state and may be influence by the politics of the state legislature, the strength of state regulatory authorities, the presence of an in-state renewable energy industry, and a state’s reliance on the natural gas or coal industry (Herche 2017).  Currently 29 states and Washington D.C. have established renewable portfolio standards and an additional 8 states have non-binding voluntary renewable goals (Figure SC.5). RPS requirements are thought to be responsible for 60% of the total increase in U.S. renewable electricity generation since 2000. However, RPSs’ role appears to have declined in recent years from 75% of all U.S. utility PV procurement in 2014 to only 26% in 2016 as many utilities in major state markets have met their RPS obligations (SEIA 2016). The declining costs of solar energy heightens the appeal of utility-scale PV as a cost-competitive alternative to other energy sources, so voluntary procurement (i.e. projects made viable due to their economic competiveness) is expected to be the primary driver of new utility PV demand going forward (Figure SC.6) (SEIA 2017). The National Conference of State Legislatures provides additional information on renewable portfolio standards by state.
Figure SC.5 Nationwide Renewable Portfolio Standard Policies
Source: DSIRE database, www.desireusa.org
Figure SC.6 Share of Utility PV Procurement by Market Driver, 2016 vs. 2017 YTD
Source: Figure 2.24 from SEIA 2016 Year in Review. Note: PURPA = Public Utility Regulatory Policy Act
Public Utility Regulatory Policy Act (PURPA)
The Public Utility Regulatory Policies Act of 1978 (PURPA) aimed to enable “qualifying facilities” (e.g., small renewable energy generators, cogeneration projects) to compete in the electric sector. In the years following the initiation of PURPA in 1978, independent power producers (IPPs) have come to be the most common owners of utility-scale PV projects in the U.S Two key features of PURPA are the right of qualifying facilities to interconnect with a utility-controlled grid and the mandatory purchase obligation. Under the mandatory purchase obligation, utilities were required to purchase a qualifying facility’s energy at “avoided cost” (i.e., the cost to the utility to generate or purchase that amount of energy in the absence of the qualifying facility). Through 2016, PURPA was a strong driver of utility PV, but as the purchase obligation was weakened in the Energy Policy Act of 2005 and subsequent contract length and avoided cost rate decreases in many states, it may play a lesser role going forward.
Other Renewable Energy Policies
Power Purchase Agreements (PPAs)
The power purchase agreement (PPA) is one of the key contracts for a utility-scale PV project, in which a power off-taker that specifies the terms under which electricity produced at the PV project will be sold. The typical PPA structure in the solar industry currently is “take or pay.” Under this arrangement, the offtaker is obligated to take and pay for all output actually delivered by seller, but does not have to pay for any output not actually produced or delivered (although provisions may exist to require payment under situations like curtailment). A PPA is fundamental to obtaining financing because it details the expected revenue for the project (IFC 2015). (NREL 2012).  The Energy Policy Act of 2005 defines projects that may employ PPAs, and most PPAs are subject to regulation by the Federal Energy Regulatory Commission (FERC).
Expedited Solar Permitting and Interconnection Process
In the U.S., permits are required at the local, state and federal level to construct and operate the solar project and to sell the electricity produced. Typically, a solar project needs approval from a local land use board or zoning authority, a building permit, an electrical permit, and in some cases, a permit from the fire department. Solar projects located on federal lands may require permits from the BLM or the Department of Agriculture’s Forest Services. Because utility-scale solar projects usually sell the electricity they generate to wholesale utility buyers, interconnection agreements are required, often including additional facilities and transmission infrastructure upgrades to ensure the grid stability.
Several state have taken action to streamline residential and commercial solar permitting and reduce the associated costs and time burden (e.g., California Solar Permitting Efficiency Act of 2014, Vermost standardized solar permitting law, Massachusetts expedited interconnection, Colorado SB17-179). Similar actions could reduce the soft costs of utility-scale PV. The Bureau of Land Management’s Competitive Leasing Rule for Solar and Wind Energy Development, effective January 2017, is expected to decrease the timeframe of obtaining a renewable energy project permit on federal lands by one half; it establishes a competitive bidding process to attract renewables development on federal lands, drawing from the process used to award oil and gas extraction leases.
Modified Accelerated Cost-Recovery System (MACRS)
The Modified Accelerated Cost Recovery System (MACRS), which was initially established in 1986, alters the computation of depreciation on solar generating equipment in order to boost cost recovery through tax deductions for solar owners. MACRS allows full depreciation of qualifying solar equipment over the first five years of the project, which provides a tax benefit sooner than traditionally allowed for annual depreciation. At several points, “bonus depreciation” has also been allowed on the first year of a project’s life (after the first year, the remaining value depreciates according to the original MACRS). Currently, PV projects entering service in 2018 can qualify for 40% bonus depreciation and projects entering service during 2019 can qualify for 30% bonus depreciation.
Quantitative Measurement of Imperfect Competition
Four Firm Concentration Ratio (FFCR)
This information is not available from the U.S. Census for construction and several other activities encompassing the roles of project developers and EPC firms. However, the HHI, addressed below, is a more nuanced metric than the FFCR.
Herfindahl-Hirschman Index (HHI)
Tables SC.4 and SC.5 show the top utility-scale solar developers and EPCs in 2017, ranked by total number of MW of new installed capacity. Using the capacity installed in 2017 to estimate market share, we calculate HHIs of 2,407 for project developers and 864 for EPCs.
Table SC.4 Top U.S. Utility-Scale Solar Developers in 2017
Source: Solar Power World 2017 https://www.solarpowerworldonline.com/2017-top-solar-developers/
|Company||Total MW Installed||MW installed in 2016||Market Share|
|Cypress Creek Renewables||1,227||720||22.7%|
|Innovative Solar Systems||756||414||13.1%|
|Origis Energy USA||147||123||3.9%|
|Carolina Solar Energy||180||84||2.6%|
|Renewable Energy Massachusetts||31||14||0.4%|
|MC Power Companies||53||12||0.4%|
Table SC.5 Top U.S. Utility-Scale Solar EPC Companies in 2017
Source: Solar Power World 2017 https://www.solarpowerworldonline.com/2017-top-solar-epcs/
|Company||Total MW installed||MW installed in 2016||Market Share in 2016|
|Swinerton Renewable Energy||2331||1355||14.2%|
|Amec Foster Wheeler||1283||647||6.8%|
|McCarthy Building Cos.||1000||603||6.3%|
|Bombard Renewable Energy||420||219||2.3%|
|Primoris Renewable Energy||479||186||1.9%|
|The Ryan Company||536||182||1.9%|
|J. Ranck Electric||169||138||1.4%|
|Blue Oak Energy||105||55||0.6%|
|S&C Electric Company||264||22||0.2%|
|Newkirk Electric Associates||113||12||0.1%|
Other resources on the current market players in utility-scale PV project development and EPC include Argonne National Laboratory’s Solar Projects Web Site and the Solar Energy Industries Association’s Major Solar Projects List. At a global scale, Wiki-Solar website populates top-ranked utility-scale solar power project developers and EPC contractors, along with other solar industry players (i.e., project owners, O&M contractors, inverter suppliers, finance providers, etc.)