Electricity Generation Projects: Additional Data Could Improve Understanding of the Effectiveness of Tax Expenditures
Released: 2015-05-28T00:00:00

Letter

Background

This section describes (1) utility-scale electricity generation in the United States, (2) federal and state regulation of electricity markets, and (3) federal actions that have supported utility-scale electricity generation projects.

Utility-Scale Electricity Generation in the United States

Developers of utility-scale electricity generation projects build new projects to meet the growing electricity demands of U.S. retail customers. Developers include: (1) utilities that build projects to serve their own retail customers and (2) nonutilities, which includes both developers that build and sell projects and independent power producers that build and own projects and then sell the electricity generated by the project. In the later case, the independent power producers sell electricity to utilities or other retail service providers—entities that compete with each other to provide electricity to retail customers by offering electricity plans with differing prices, terms, and incentives. Developers are either for-profit or nonprofit entities. For-profit developers include investor- owned utilities—which serve 75 percent of the U.S. population—that are owned by private investors and provide the services of a utility, and independent power producers. Nonprofit developers include municipally- owned utilities and electric cooperatives.

Across the United States, the development of new renewable and traditional utility-scale electricity generation projects varied by state from 2004 through 2013 (see fig. 1).

From 2004 through 2013, around 2,000 new renewable and about 500 new traditional utility-scale electricity generation projects were built in the United States. However, according to our analysis of SNL Financial data, renewable projects were significantly smaller than traditional ones. For example, utility-scale solar projects averaged about 10 MW of generating capacity, whereas gas projects averaged 285 MW of generating capacity. Specifically, renewable projects added about 69,000 MW of new generating capacity, and traditional projects added about 157,000 MW of new generating capacity (see fig. 2).

Federal and State Regulation of Electricity Markets

The electricity industry has historically been characterized by investor- owned utilities that were integrated and provided the four functions of electricity service—generation, transmission, distribution, and system operations—to all retail customers in a specified area. These integrated utilities were allowed to operate in monopoly service territories, but the rates they could charge retail customers were regulated by state regulatory commissions, often called public utility commissions. These commissions were charged with ensuring that, in the absence of competition, the services these integrated utilities provided were adequate, and the rates they charged were reasonable and compensated them for approved costs they incurred. In most states, this regulatory approach continues. These states are referred to as traditionally regulated.

During the last 2 decades, some states and the federal government have taken steps to restructure traditionally regulated electricity markets with the goal of increasing competition. Broadly speaking, these efforts by the states have resulted in areas where electricity generation and distribution services are no longer integrated. These are referred to as restructured states. Utilities in restructured states still generally provide transmission, distribution, and system operations to retail customers in their service areas, but they do not own all the generation facilities in those areas. In restructured states, retail customers may purchase electricity from any qualified retail service provider, and the price for electricity is determined largely by supply and demand. The responsibility for regulating electricity in these states is divided between states and the federal government. States continue to regulate the provision of electricity service by retail service providers, and the Federal Energy Regulatory Commission oversees electricity that is traded in wholesale markets prior to being sold to retail customers.

Federal Support of Utility- Scale Electricity Generation Projects

The federal government’s support of the development of utility-scale electricity generation projects generally falls into the following three categories:

Providing funds: The federal government provides funds through outlays such as grants or incentive payments that directly cover some of the developer’s project costs. These outlays do not need to be repaid and, therefore, represent a direct cost to the government.

Assuming risk: The federal government assumes risk and potential costs associated with risk in a number of ways, including by making direct loans and by guaranteeing loans. When making direct loans, the federal government disburses funds to nonfederal borrowers under contracts requiring the repayment of such funds either with or without interest. When making loan guarantees, the federal government provides a guarantee, insurance, or other pledge regarding the payment of all or a part of the principal or interest on any debt obligation of a nonfederal borrower to a lender. For both loans and loan guarantees, the cost to the government is estimated using the credit subsidy cost—the cost to the government, in net present value terms, over the entire period the loans are outstanding to cover interest subsidies, defaults, and delinquencies (not including administrative costs).

Forgoing revenues: The federal government may choose to forgo certain revenues through various measures in the tax code, broadly known as tax expenditures. Tax expenditures are tax provisions— including tax deductions and credits—that are exceptions to the normal structure of income tax requirements necessary to collect federal revenue. Tax expenditures can have the same effects on the federal budget as spending programs—namely that the government has less money available to use for other purposes.

As we have previously reported, some of these federal supports may be combined, resulting in support from multiple programs going to the same recipient for the development of a single project. For example, in the last decade, project developers may have combined the support of more than one tax expenditure with grants or loan guarantees from DOE or USDA.

Key State Supports Aided the Development of Electricity Generation Projects

Key state supports, in the form of state policies, aided the development of utility-scale electricity generation projects—particularly renewable energy projects—for fiscal years 2004 through 2013. For example, most states have a renewable portfolio standard (RPS) that mandates that retail service providers obtain a certain percentage or amount of the electricity they sell from renewable energy sources, which helped create additional demand for renewable energy, according to many stakeholders we interviewed. In addition, most states remain traditionally regulated, and regulatory policies in these states provided important state-level support for renewable or traditional projects by allowing regulated utilities to recover costs incurred while purchasing power from existing electricity generation facilities or building new generating capacity themselves. Respondents to our survey of state regulatory commissions and some stakeholders cited other state supports for new renewable energy projects, such as state implementation of the Public Utility Regulatory Policies Act of 1978, and state tax incentives including property tax exemptions and tax credits.

RPSs Provided Important State-Level Support by Mandating the Purchase or Generation of Renewable Energy

According to many stakeholders we interviewed and most respondents to our survey of state regulatory commissions, state RPSs provided important state-level support for new renewable projects built by utilities and independent power producers from 2004 through 2013 (see app. II for a list of stakeholders we interviewed and app. III for a copy of our survey). Of the regulatory commissions that answered our survey questions about the importance of state-level supports, 17 of 19 (89 percent) responded that RPSs were either very or extremely important for renewable projects built by utilities, and 21 of 24 (88 percent) responded that RPSs were either very or extremely important for renewable projects built by independent power producers. According to many stakeholders we interviewed, RPSs provided important support because they mandated the purchase or generation of electricity from renewable energy sources, which helped create additional demand for renewable energy. As of September 2014, 30 states and the District of Columbia had established RPSs, and an additional 8 states had established a voluntary or nonbinding renewable portfolio goal (RPG).

The characteristics of state RPSs and RPGs varied by state. For example,

Timelines for meeting RPSs or RPGs and the amounts of electricity required to be obtained from renewable energy sources varied, according to survey respondents. For example, Michigan’s RPS required retail service providers to generate 10 percent of the electricity they sold from renewable energy sources by 2015. In contrast, Hawaii’s RPS required utilities to obtain 40 percent of the electricity they sell from renewable energy sources by 2030.

Types of entities subject to RPSs and RPGs also varied. For example, 14 state regulatory commissions confirmed that their RPSs or RPGs applied specifically to investor-owned utilities. Another commission in a restructured state noted that the state’s RPS did not apply to utilities; instead, it applied to the retail suppliers that provided electricity in utilities’ service areas.

Types of energy sources that could satisfy RPSs or RPGs also varied.

For example, the California Energy Commission’s guidebook on RPS eligibility identifies a variety of renewable energy sources—such as solar photovoltaic, wind, and biomass—that can satisfy California’s RPS. In contrast, under Pennsylvania law, the state’s RPS allows “alternative energy sources” to satisfy the RPS and defines alternative to include waste coal and coal mine methane. Additionally, some state RPSs include provisions that require a certain percentage of the electricity generated or produced to be derived from specific types of renewable energy. For example, according to Lawrence Berkeley National Laboratory, 17 states plus the District of Columbia have special provisions encouraging solar or other energy sources.

See appendix IV for additional information about individual state RPSs and RPGs.

In addition to creating additional demand for renewable energy, state RPSs and RPGs were an important factor in determining where projects were built. More specifically, our analysis of utility-scale electricity generation project data and responses to our survey found that 91 percent of new renewable projects from 2004 through 2013 were built in states with RPSs or RPGs, and that these projects accounted for 94 percent of new renewable generating capacity. Several stakeholders explained that state RPSs made it possible for developers to secure power purchase agreements (PPA)—contracts in which a utility agrees to purchase power, generally over a term of 20 to 25 years. In addition, most stakeholders said that PPAs were essential to moving a project forward because they provided the developer and potential investors an expectation of stable revenue for projects. See figure 3 for additional information about where new renewable generating capacity was added from 2004 through 2013.

Regulatory Policies in Most States Provided Important State-Level Support by Allowing Utilities to Recover Costs for New Renewable or Traditional Projects

Most states remain traditionally regulated, and regulatory policies in these states provided important state-level support by allowing regulated utilities to recover costs incurred while purchasing power from existing renewable or traditional electricity generation facilities or building new generating capacity themselves. Specifically, 29 of 46 (63 percent) respondents to our survey reported that regulatory commissions regulated the electricity generation services provided by investor-owned utilities (see app. V for more detail about what states reported about their regulatory status). As previously discussed, in these states, state regulatory commissions set retail customers’ electricity rates to compensate regulated utilities for the costs they incur serving these customers—including expenses incurred while purchasing power or building new electricity generation capacity. Of the 19 traditionally regulated states that answered a survey question about the importance of commission-approved rates of return for building new traditional projects, 17 (90 percent) reported that they were either very or extremely important. In addition, of the 22 traditionally regulated states that answered a survey question about the importance of commission-approved rates of return for building new renewable projects, 19 (86 percent), reported that they were very or extremely important. In addition, according to at least 36 regulatory commissions we surveyed, utilities subject to this type of regulation did not build projects from fiscal year 2004 through 2013 without seeking approval to recover their costs and earn a return on their investments. All 29 regulatory commissions in traditionally regulated states also reported that, when utilities purchased power for fiscal years 2004 through 2013, the utility was allowed to recover associated costs by passing these costs on to retail customers.

Other State Supports Aided the Development of Renewable Projects

State regulators and some stakeholders cited other state supports for the development of new renewable projects for fiscal years 2004 through 2013. For example, in some cases, state regulatory commissions allowed regulated utilities to offer their retail customers “green power”— the option to purchase renewably produced electricity to meet their electricity needs. According to DOE, in 2012, the most recent year for which data were available, more than 860 traditionally regulated utilities, which served more than half of all U.S. retail customers, offered such an option.

Another state policy that supported the development of new renewable projects was state implementation of the Public Utility Regulatory Policies Act of 1978. Specifically, 17 of 21 of the regulatory commissions that answered one of our survey questions about how developers earned revenues reported that developers earned revenues through PPAs obtained as a result of state implementation of the Public Utility Regulatory Policies Act.

Finally, several stakeholders also told us that state tax incentives, such as property tax exemptions and tax credits, were helpful for developing new renewable projects. For example, some solar developers have used the New Mexico Renewable Energy Production Tax Credit, which allows companies that generate electricity from solar energy to receive a tax credit ranging from $0.015 to $0.04 per kilowatt-hour over a 10-year period. The program also provides a tax credit against corporate income taxes of $0.01 per kilowatt-hour for companies that generate electricity from wind or biomass.

Federal Financial Supports Aided the Development of New Electricity Generating Capacity, but Limited Data on Tax Expenditures Hinders an Understanding of their Effectiveness

For fiscal years 2004 through 2013, programs at DOE, Treasury, and USDA aided the development of new electricity generating capacity through outlays, loan programs, and tax expenditures. Most of this support was directed at renewable projects, with federal support for traditional projects largely directed toward reducing the cost of fuel rather than the development of new projects. As shown in table 1, one program—Treasury’s temporary Payments for Specified Energy Property in Lieu of Tax Credits (payments-in-lieu-of-tax-credits program)— accounted for most of the $16.8 billion in total outlays, which supported over 29,000 MW of new generating capacity. Federal loan programs accounted for an estimated $1.2 billion in credit subsidy costs that supported nearly 10,000 MW of new generating capacity. Federal tax expenditures—which reduce a taxpayer’s tax liability by providing, for example, credits toward or deferrals of tax liability—accounted for an estimated $15.1 billion in forgone revenue to the government, but limited data hinder an understanding of their contributions to new generating capacity and ultimately, their effectiveness.

Treasury’s Temporary Payments-in-Lieu-of-Tax- Credits Program Accounted for Most of the $16.8 Billion in Outlays That Supported Over 29,000 MW of Generating Capacity

In total, $16.8 billion in outlays supported over 29,000 MW of new generating capacity through eight federal programs, and Treasury’s temporary payments-in-lieu-of-tax-credits program accounted for 99 percent of the total outlays. Treasury’s program was enacted in the American Recovery and Reinvestment Act of 2009 (Recovery Act), and provided cash payments of up to 30 percent of the total eligible costs of qualifying renewable energy facilities. These cash payments were available in lieu of the Energy Investment Credit, also known as the Investment Tax Credit (ITC) or the Energy Production Credit, also known as the Production Tax Credit (PTC). During the first 5 years of Treasury’s program, developers of 1,073 utility-scale electricity generation projects developed 28,309 MW of generating capacity across the United States, according to the data submitted by developers in their applications for payments in lieu of tax credits.

In addition to Treasury’s program, seven other federal programs at DOE, Treasury, and USDA, supported 128 projects for fiscal years 2004 through 2013 through grants, incentive payments, or other mechanisms, for a total of $241 million in additional federal outlays. For example, USDA’s Rural Energy for America Program provides outlays in the form of grants to farmers, ranchers, and small businesses in rural areas to assist with purchasing and installing renewable energy systems. These grants supported 50 projects that added 139 MW of electric generating capacity for total outlays of nearly $16 million.

DOE’s outlay program that supported the greatest number of projects was its now-discontinued Renewable Energy Production Incentive program, which provided production-based cash payments to nonprofit owners of qualified renewable energy projects for 10 years after the project was placed in service. According to DOE officials, this program was designed to provide incentives for entities that do not pay income taxes—such as electric cooperatives and municipally-owned utilities—similar to those provided to for-profit developers through the PTC. Unlike the PTC, this program was subject to annual appropriations by Congress. The Renewable Energy Production Incentive program provided $26 million in incentive payments to 59 projects with 704 MW of generating capacity but, according to agency officials, was discontinued in 2010. Projects that received support through federal outlays may have also received support through loan programs or tax expenditures. See appendixes VI and VII for program descriptions and outlays for all federal programs.

Federal Loan Programs Provided Support at an Estimated Cost of $1.2 Billion for Nearly 10,000 MW of New Generating Capacity

Six federal loan programs—providing both direct loans and loan guarantees—at DOE and USDA accounted for an estimated $1.2 billion in credit subsidy costs that supported 70 projects for a total of 9,748 MW of new generating capacity. DOE administered two of the six loan programs that were authorized to support the development of projects for fiscal years 2004 through 2013, but only one DOE loan program actually awarded loan guarantees for utility-scale electricity generation projects during this timeframe. Specifically,

DOE’s loan guarantee program for innovative technologies was authorized to support the development of these projects, but did not award loan guarantees to any utility-scale electricity generation projects during these years.

DOE’s now-expired Recovery Act loan guarantee program—which supported both innovative and commercial technologies—authorized loans for 21 utility-scale electricity generation projects with 3,976 MW of generating capacity and is estimated to have provided over $1.2 billion in federal support through payments of credit subsidy costs as of the close of fiscal year 2013. (For an explanation of how the credit subsidy costs for DOE’s loan guarantees were calculated, see app. I.) Under the Recovery Act loan guarantee program, the credit subsidy cost was paid with appropriated funds, whereas under the loan guarantee program for innovative technologies, borrowers generally had to pay for their own credit subsidy costs.

USDA administered four programs that provided either loans or loan guarantees for both traditional and renewable projects for fiscal years 2004 through 2013, and earned revenues for the government. In aggregate, USDA’s loan programs resulted in a negative credit subsidy cost—that is, they yielded revenue rather than incurring a cost to the government—of $14 million. According to a USDA official, this is because USDA’s Direct and Guaranteed Electric Loans program had a low rate of default and earned revenues from borrowers’ annual fees and interest. This program, which provided both loans and loan guarantees to establish and improve electric service in rural areas, supported 32 projects that added 5,714 MW in new generating capacity. The other three loan programs at USDA supported 17 projects and added 58 MW of additional generating capacity. Projects that received support through federal loan programs might also have received support through outlays, including Treasury’s payments in lieu of tax credits, or tax expenditures. See appendixes VI and VII for program descriptions and credit subsidy costs for all federal loan programs.

Federal Tax Expenditures Accounted for an Estimated $15.1 Billion in Forgone Revenue, but IRS Does Not Collect Key Data on the Two Largest Tax Expenditures

Seven tax expenditures administered by the Internal Revenue Service (IRS) at Treasury accounted for an estimated $15.1 billion in forgone revenue for fiscal years 2004 through 2013, but IRS does not collect or report key data on the two largest tax expenditures supporting new utility- scale electricity generation projects. Tax expenditures supported the development of both renewable and traditional projects, and the majority of the forgone revenue (91 percent) supported renewable projects. Of the seven tax expenditures, the following four accounted for nearly 97 percent of the forgone revenue ($14.6 billion):

PTC. The PTC accounted for an estimated $8.1 billion in forgone revenue and, as of the end of 2013, provided an income tax credit of 2.3 cents per kilowatt-hour for energy produced from wind and certain other renewable energy sources. Since it was first made available in 1992, the PTC has expired and been extended by Congress six times—in 1999, 2001, 2003, 2012, 2013, and 2014. Most recently, the PTC was extended for certain qualified facilities for projects that began construction before January 1, 2015. Because the credit is taken over a 10-year period once a project is placed in service, the PTC will continue to result in forgone revenue for years to come. ITC. The ITC accounted for an estimated $3.4 billion in forgone revenue, and it provided an income tax credit up to 30 percent for the development of certain renewable projects. Developers of certain qualifying facilities could choose to take the ITC in lieu of the PTC if the project met certain criteria; however, developers could not claim both tax credits for the same project. The ITC was first established in 1978 at 10 percent of eligible investment costs and was temporarily increased in 2005 to 30 percent for solar and certain other technologies. Subsequent legislation extended the ITC at 30 percent for these technologies through December 31, 2016. After December 31, 2016, the ITC is scheduled to return to 10 percent of eligible investment costs for solar projects.

Accelerated Depreciation for Renewable Energy Property.

Accelerated Depreciation Recovery Periods for Specific Energy Property: Renewable Energy (accelerated depreciation for renewable energy property) accounted for an estimated $1.7 billion in forgone revenue. This provision is similar to accelerated depreciation provisions available for a wide range of investments in other sectors. Accelerated depreciation for renewable energy property allows developers of certain renewable energy properties to deduct larger amounts from their taxable income sooner than they would normally be able to do under the straight-line depreciation method.

Specifically it allows them to recover investments by deducting the cost of the investment from their taxable income over a 5-year period. Unlike the ITC and PTC, which have expiration dates and have been subject to congressional review as part of efforts to expand, extend, or reauthorize them, accelerated depreciation for energy property—like other accelerated depreciation provisions—does not have a specific expiration date and, as such, is not subject to periodic review by Congress.

Credit for Investment in Clean Coal Facilities. This credit for traditional fuel sources is estimated to have accounted for $1.4 billion in forgone revenue to support the development of clean coal projects. The credit provides up to 30 percent of qualified investments in clean coal facilities greater than 400 MW in size. Unlike the ITC, PTC, and accelerated depreciation for renewable energy property—for which all eligible taxpayers may claim the tax expenditure—the Credit for Investment in Clean Coal Facilities is subject to a specified amount authorized by Congress. As such, developers must submit an application that includes a description of the project, the project’s financing structure, and the proposed technology to apply for the credit. According to IRS officials, DOE’s NREL reviewed the applications to determine whether the projects met the required technical criteria, and then made recommendations to IRS about whether the projects should receive an allocation of the tax credit. According to IRS officials, 12 awards have been made for projects included in our scope, and 4 of those projects had been placed in service as of September 2014. Additionally, according to the officials, further allocations of the credit are available. IRS announced a 2015 reallocation round on March 9, 2015 and the agency plans to send acceptance letters by April 30, 2015.

Projects that received support through federal tax expenditures may also have received support through outlay or loan programs. See appendixes VI and VII for program descriptions and details on estimates of forgone revenue for all federal tax expenditures that supported the development of utility-scale electricity generation projects.

While some project-level data are collected for the projects supported through outlays, loan programs, and the Credit for Investment in Clean Coal Facilities, basic information such as projects supported or MW of generating capacity added is not collected or available about the ITC and PTC. The ITC and PTC—which accounted for an estimated $11.5 billion in forgone revenue from 2004 to 2013—are the two largest tax expenditures supporting these projects and in the past 5 years, the estimated forgone revenues from them have more than tripled from $870 million to $2.8 billion. Key information is not available because the IRS does not collect certain project-level data, such as the total generating capacity added. Specifically,

For the ITC, the IRS requires all developers to report the total amount of the credit they are claiming for all eligible projects aggregated as a single line item; therefore, the IRS does not know the total number of projects for which an individual developer is claiming the credit. Developers who were eligible for the PTC but instead elected to claim the ITC must also submit supporting documentation that includes project-level data, such as the generating capacity and technology of each specific facility for which they are claiming the credit; however, the IRS does not require such project-level information from developers eligible only for the ITC. Consistent with the Internal Revenue Code, in general, the IRS is not allowed to make individual taxpayer information available for analysis, but IRS can and does make available certain aggregated data. However, IRS does not make available the project-level data it collects for the ITC.

For the PTC, as with the ITC, the IRS requires all developers to report the total amount of the credit they are claiming for all eligible projects aggregated by technology as a single line item; therefore, the IRS does not know the total number of projects for which an individual developer is claiming the PTC. Unlike the ITC, the IRS requires developers to report the technology type (e.g. wind, geothermal, solar) for which they are claiming the PTC. IRS does not require developers to submit any project-level data, such as generating capacity, when they claim the PTC.

The IRS is not required to collect or evaluate data other than those which are required for administration of the tax code unless it is legislatively mandated to collect additional information. IRS officials stated that, given a number of factors, IRS is unlikely to collect additional information on these tax expenditures without being directed to do so by Congress. IRS has not evaluated the costs of collecting these data. As we have previously found, collecting additional data to identify users and specific properties would require changes in IRS forms and information processing procedures. To some extent, the increasing number of taxpayers filing electronically could make it easier for IRS to collect additional data without expensive transcription costs. In considering additional data requirements, it is important that Congress weigh the need for more information with IRS’s other priorities because such requirements likely would increase, to some degree, the administrative costs for IRS and the compliance burden on taxpayers. If policymakers conclude that additional data would facilitate examining a particular tax expenditure, additional considerations on what data are needed, who should provide the data, who should collect the data, how to collect the data, what it would cost to collect the data, and whether the benefits of collecting additional data warrant the cost of doing so would be important.

Nonetheless, since 1994, we have encouraged greater scrutiny of tax expenditures to help policymakers make more informed decisions about using such mechanisms as a means of supporting policies. For example, since 1994, we have found that substantial revenues are forgone through tax expenditures, yet policymakers have had few opportunities to make explicit comparisons or evaluate trade-offs between tax expenditures and federal spending programs. Based on these and other findings, we recommended that Congress explore opportunities to exercise more scrutiny over indirect spending through tax expenditures, and Congress took action by subjecting certain tax expenditures to closer examination. In addition, in 2005, we found that tax expenditures may not always be efficient, effective, or equitable and, consequently, we concluded that information on tax expenditures could help policymakers make more informed decisions as they adapt current policies in light of fiscal challenges and other overarching trends. We also concluded that reviews of tax expenditures could help establish whether these programs are relevant to today’s needs and, if so, how well tax expenditures have worked to achieve specific objectives and whether the benefits from particular tax expenditures are greater than their costs.

We have also previously concluded that limited data about specific tax expenditures can hinder analysis of their effectiveness. For example, in 2008, we determined that the data the IRS collected were insufficient for examining efforts to use a tax expenditure to encourage economic development on Indian reservations. As a result, we suggested that Congress consider requiring IRS to collect additional information about the tax expenditure. Similarly, in examining a broad range of tax expenditures in 2013, we concluded that it was becoming more pressing to determine whether tax expenditures were achieving specific objectives.

Additionally, the Government Performance and Results Act Modernization Act of 2010 established a framework for providing a more crosscutting and integrated approach to focusing on results and improving government performance. This act makes clear that tax expenditures are to be included in identifying the range of federal agencies and activities that contribute to crosscutting goals, and guidance from the Office of Management and Budget directs agencies to do so for their agency priority goals. Such information can be used to inform congressional decisions about authorizing or reauthorizing provisions in the tax code.

In requesting this report, Congress asked us to evaluate federal supports for the development of utility-scale electricity generation projects, for example, by providing information about how many projects were built, the technologies supported, and the amount of generating capacity added. The absence of project-level data for the ITC and PTC—such as is available for projects that took Treasury’s payments in lieu of these tax credits—precluded us from examining and providing this information. Without it, Congress and others do not have basic information about what has been supported, including how many projects used these tax expenditures or how much generating capacity was added. According to the Congressional Research Service, the ITC and PTC were designed to encourage the commercialization of renewable energy technologies.

Basic information is required for any evaluation of these tax credits, such as determining whether or not they were effective at encouraging development of new renewable projects.

Developers Combined State and Federal Supports to Finance Renewable Projects, and Reducing State or Federal Supports Would Likely Reduce Development of These Projects

Developers combined state and federal supports to secure financing for renewable projects, and these supports reduced the price paid for renewable electricity by retail customers. Reducing state or federal supports would likely reduce the development of renewable projects unless PPA prices increased to compensate for the reduction in federal support.

Developers Combined State and Federal Supports to Finance Projects, and Federal Supports Reduced the Price of Renewable Electricity

Debt and Equity Project financing through private markets generally takes two forms—debt and equity. Similar to a home mortgage, debt is incurred when a developer borrows funds with prescribed repayment terms—such as an interest rate and a specified number of payments. The lender has no ownership in the property but may be able to take over the property if the borrower does not make payments as agreed. In addition, in the event of a bankruptcy or other loan default, the lender typically has the first right to any assets. Equity is invested funds that give the investor an ownership interest in the operations and assets of a business and a right to a portion of any income remaining after payment of operating costs and payments on debt. The investor is not entitled to repayment if the project fails. Because investors consider debt to be less risky than equity, it is typically the cheaper form of private financing. However, lenders typically will not lend the total costs of a project and they often place limits on the amount of money they will lend by limiting the amount of the payment on the loan to a specified percentage of the expected income of the project.

Developers combined state and federal supports to finance renewable projects. As previously noted, state supports in the form of RPSs and RPGs mandated that retail service providers obtain a certain percentage or amount of the electricity they sell from renewable sources. These supports created additional demand for electricity from renewable sources. Retail service providers comply with this requirement by either generating their own electricity from renewable sources or by purchasing this electricity from a third party, such as an independent power producer. To purchase renewable electricity, retail service providers often issue solicitations seeking bids for PPAs—long-term contracts in which the retail service provider agrees to purchase power and which provides the developer with an expectation of stable revenue. In response to these solicitations, developers bid for these PPAs. Once bids are selected and developers are awarded PPAs, developers generally then attempt to secure debt and equity to finance their projects through private markets. In seeking project financing, developers combine the value of the revenues guaranteed in their PPAs and the value of the federal supports to secure favorable financing terms.

Tax Equity Partnerships In several cases, developers of renewable projects had to enter into complex financial partnerships—tax equity partnerships—to use certain tax expenditures. For example, the use of tax expenditures like the Investment Tax Credit and Production Tax Credit required developers’ tax liability to equal or exceed the value of the tax expenditure. Developers with substantial corporate profits generally had enough tax liability to be able to directly use these tax expenditures. However, developers with lower tax liability had to enter into arrangements known as tax equity partnerships with third parties—usually large financial institutions, such as investment banks—that had sufficient tax liability in order to use tax expenditures. Under these partnerships, the third party typically provided equity for the project in exchange for the right to use nearly all of the tax benefits and receive a share of the project revenues. According to stakeholders, the partnerships typically incurred legal, administrative, and other transaction costs that reduced the value of tax expenditures to the developers’ projects by 10 to 30 percent. Nonetheless, some stakeholders reported that tax equity partnerships were critical for projects to move forward.

Federal supports reduced the price of renewable electricity for retail customers by reducing the cost to the developers to build projects in two key ways. First, some federal loan programs reduced the cost of capital— i.e., the funds necessary to build the projects. For example, some stakeholders said USDA loan programs offered lower interest rates than were available through the capital markets, which lowered the overall cost of borrowing. Second, federal tax expenditures and payments allowed developers to recover some of their costs. For example, the ITC allowed developers to recover up to 30 percent of eligible project costs for solar and other qualifying renewable energy facilities by reducing the amount of taxes they owed. However, many stakeholders noted that, in some cases, developers needed to enter into complex financial partnerships—tax equity partnerships—to utilize federal tax expenditures, which reduced the value of the federal support to the developer. According to several stakeholders, the amount that developers can bid for a PPA depends on how much federal support the project expects to receive; therefore, these supports allowed developers to offer lower prices in their PPAs than they otherwise could have. These lower prices were then passed on to retail customers. In this way, these supports can be thought of as reducing the price of electricity that retail customers pay.

Reducing State or Federal Supports Would Likely Reduce the Development of Renewable Projects

Reducing state or federal supports would likely reduce the development of renewable projects. To understand the effects of changes to federal tax expenditures, we modeled hypothetical utility-scale solar photovoltaic and wind projects and found that reducing or eliminating the ITC or PTC would likely reduce the number of renewable projects built because either developers’ returns would decline or PPA prices would increase. For our analysis, we held investor rates of return—which stakeholders typically refer to as the internal rate of return—constant. We modeled the two projects with variations in the levels of the ITC—at 10 and 30 percent— and PTC—with no PTC and with the PTC at $0.023 per kilowatt-hour.

Our modeling suggests that reducing or eliminating federal financial supports could result in substantially reduced returns for developers, which could reduce the number of new renewable utility-scale electricity generation projects built. For example, in the case of the solar project, we found that with a reduced ITC and constant PPA prices, the developer’s returns could decrease by as much as 76 percent (see table 2). Likewise, for the wind project, we found that without the PTC, the developer’s returns could decrease by 68 to 109 percent—in other words, in the extreme case, the developer would lose money by developing the project. Our modeling results are consistent with the effects of past expirations of the PTC. As we have previously found, in the years following the PTC’s expiration, new additions of wind capacity fell dramatically.

Alternatively, we found that if we held the developer’s returns constant, a reduction or elimination of federal supports could mean that, for future projects to remain viable, electricity prices in PPAs would have to increase. Specifically, for the solar project with the lower ITC, we found that the electricity prices in PPAs would need to increase by 20 to 27 percent if developers were to maintain their returns. For wind projects without the PTC, we found that electricity prices would need to increase by 32 to 62 percent if developers were to maintain their returns (see table 3).

Placed in a broader context, because PPA prices are determined through negotiations between developers and retail service providers, the willingness of these providers and state regulators to agree to higher prices will likely constrain the ability of developers to maintain their returns. If expected returns from renewable energy projects are reduced past a certain point, developers may seek alternative investments, either in the energy sector or elsewhere. Collectively, the constraints faced by developers with reduced or eliminated federal supports would likely lead to a reduction in the level of investment in new renewable utility-scale electricity generation projects.

The extent to which development of renewable projects would decrease depends on, among other factors, how states respond to the effects of reduced federal supports. Specifically, reducing federal supports would reduce developers’ returns unless PPA prices increased to compensate for the reduction in federal support. The amount PPA prices could increase may be constrained by how close states are to completing their RPSs. Four of the 24 state regulatory commissions that responded to our survey question about progress made by investor-owned utilities toward completing their RPSs reported that they have either met or exceeded their RPSs (see fig. 4). In these states, if PPA prices were to increase beyond the prices available for other sources of electricity, renewable development would likely decline because investor-owned utilities would not be required to purchase the more expensive renewable electricity. However, assuming that RPSs remain the same in the 20 states that reported not having met their RPSs, investor-owned utilities will need to obtain additional renewable capacity even if the price to do so increases.

The amount PPA prices could increase may also be constrained by state cost-containment mechanisms. Cost-containment mechanisms are sometimes included in state RPS legislation to limit costs associated with RPS compliance. For example, some RPSs allow state regulatory commissions to freeze or delay RPS requirements if purchasing additional renewable energy forces retail prices to exceed a threshold deemed excessive. Of the 27 states that reported having an RPS in our survey, 18 reported having cost-containment mechanisms in place, and 8 reported having no such mechanism. Looking forward, however, some states may revise or implement cost-containment mechanisms if prices of renewable electricity increase. Some stakeholders noted that, in the absence of federal supports, developers would continue to build renewable projects to meet existing RPSs even if doing so increased electricity prices for retail customers, unless states had existing cost- containment mechanisms or implemented new ones.

Conclusions

The federal government has demonstrated a commitment to supporting the development of utility-scale electricity generation projects through a variety of federal programs. While agencies collect data on projects supported through outlays, loan programs, and some tax expenditures, including the Credit for Investment in Clean Coal Facilities, the IRS does not collect such data for the ITC or PTC—the two largest tax expenditures supporting new utility-scale electricity generation projects. The ITC and PTC have increased sharply in recent years—resulting in billions of dollars in forgone revenue to the government—and will continue to represent significant forgone revenue for years to come. Since 1994, our body of work on tax expenditures has encouraged greater scrutiny of tax expenditures to help policymakers make more informed decisions. Specifically, we have concluded that more data on tax expenditures would allow policymakers to compare and evaluate trade-offs between tax expenditures and outlays and loan programs. Data currently available on outlays and loan programs allow policymakers to understand how many projects and megawatts of new generating capacity were added with federal support, thus allowing for an understanding of how effective the programs were at encouraging the development of renewable projects. However, because basic information on the ITC and PTC are not available, it will be difficult for Congress to evaluate the effectiveness of these tax credits or compare them with outlay or loan programs as it considers reauthorizing or extending them.

Matters for Congressional Consideration

If Congress wishes to evaluate the effectiveness of the ITC and the PTC as incentives for the development of renewable utility-scale electricity generation projects as it considers proposals to extend the ITC or reauthorize the PTC, it should consider directing the Commissioner of Internal Revenue to take the following two actions:

Provide Congress with project-level data currently collected from taxpayers who claim the ITC in lieu of the PTC—such as the number of projects for which they are claiming the credit, the technology of the projects taking the credit, and the total generating capacity added— and make such data available for analysis. Additionally, take steps to collect and report the same data from all taxpayers claiming the ITC.

Take steps to collect project-level data from taxpayers claiming the PTC—such as the number of projects for which they are claiming the credit, the technology of the projects taking the credit, and the total generating capacity—and make these data available for analysis.

Agency Comments and Our Evaluation

We provided a draft of this report to DOE, Treasury, and USDA for review and comment. None of the agencies provided formal comments. Treasury provided technical comments, which we integrated as appropriate.

As agreed with your offices, unless you publicly announce the contents of this report earlier, we plan no further distribution until 30 days from the report date. At that time, we will send copies of the report to the appropriate congressional committees, the Secretaries of Agriculture, Energy, and the Treasury, the Commissioner of Internal Revenue, and other interested parties. In addition, this report will be available at no charge on the GAO website at http://www.gao.gov.

If you or your staff have any questions about this report, please contact me at (202) 512-3841 or ruscof@gao.gov. Contact points for our Offices of Congressional Relations and Public Affairs may be found on the last page of this report. GAO staff members who made significant contributions to this report are listed in appendix IX.

Appendix I: Objectives, Scope, and Methodology

This report examines supports for utility-scale electricity generation projects for fiscal years 2004 through 2013. Our objectives were to: (1) identify key state supports for these projects; (2) examine key federal financial supports provided through outlays, loan programs, and tax expenditures for these projects; and (3) examine how state and federal supports affect the development of new renewable projects and how reducing federal supports may affect such development.

To identify key state supports, examine federal supports, and examine how these supports affect the development of new renewable projects, we interviewed officials at the U.S. Department of Energy (DOE), U.S. Department of the Treasury (Treasury) and U.S. Department of Agriculture (USDA); representatives from industry trade associations; and project developers known to have received federal support to build projects. We then used the “snowball sampling” technique and selected stakeholders to interview who had experience or knowledge related to our objectives. We conducted semistructured interviews with nearly 50 stakeholders including project developers and owners; attorneys and experts who specialize in project finance; industry trade associations; nongovernmental organizations; banks that provide and arrange equity and debt financing; investor-owned utilities, municipally-owned utilities, and electric cooperatives; state energy agencies; and an independent system operator. Because this was a nonprobability sample, the information these stakeholders provided cannot be generalized to other stakeholders but provided valuable insights. See appendix II for a list of stakeholders we interviewed. To identify the number of utility-scale electricity generating projects constructed and the generating capacity added from 2004 through 2013, we analyzed data from the SNL Financial database. To assess the reliability of these data, we interviewed a knowledgeable individual at SNL Financial and reviewed existing information about the system. From this review, we determined that the data were sufficiently reliable for the purposes of this report.

To further examine state and federal supports that aided the development of these projects, we sent a Web-based survey to officials at state regulatory agencies in all 50 states, the District of Columbia, and five U.S. territories. Of those we contacted, 46 states and three U.S. territories responded, for a response rate of 88 percent. We asked survey respondents about: (1) regulatory commission responsibilities; (2) the role of the regulatory process in supporting construction of new utility-scale electricity generation projects; (3) the importance of federal and state supports relative to broader market conditions; (4) federal supports for new utility-scale electricity generation projects; (5) state supports for new utility-scale electricity generation projects; and (6) renewable portfolio standards and goals.

We solicited comments on an initial draft of our survey from knowledgeable officials at five state regulatory agencies and at the National Association of Regulatory Utility Commissioners—the national association representing state public service commissioners. We conducted pretests with them to ensure that (1) the questions were clear and unambiguous, (2) terminology was used correctly, (3) the questionnaire did not place an undue burden on survey respondents, (4) the information could feasibly be obtained, and (5) the survey was comprehensive and unbiased. We chose to pretest with five states that had renewable portfolio standards, as well as some that were traditionally regulated and some with restructured electricity markets. We conducted two pretests in person and four over the telephone. We revised the content and format of the survey as appropriate after each pretest based on the feedback we received.

We developed and administered the Web-based survey through a secure server. When we completed the final survey questions and format, we sent an e-mail on July 31, 2014, announcing the survey to the regulatory commissions in all 50 states, the District of Columbia, and five U.S. territories. On August 6, 2014, we notified them via e-mail that the survey was available online and provided unique passwords and usernames. We sent follow-up e-mail messages on August 14, 2014, and again on August 20, 2014, to those who had not yet responded. We then contacted all remaining nonrespondents by telephone. We sent a final e-mail that was copied to the regulatory commission’s chairperson on September 8, 2014 stating that we were extending the deadline for submission to September 12, 2014. The questionnaire was available online until September 22, 2014. We sent follow-up e-mails to officials at 14 state regulatory officials to clarify data about states’ renewable portfolio standards and regulatory responsibilities. We made some changes to the renewable portfolio standards data collected as a result of these conversations. As noted, surveys were completed by 46 states and three U.S. territories, for a response rate of 88 percent. Because this was not a sample survey, it has no sampling errors. However, the practical difficulties of conducting any survey may introduce errors, commonly referred to as nonsampling errors. For example, difficulties in interpreting a particular question, sources of information available to respondents, or entering data into the survey or analyzing them can introduce unwanted variability into the survey results. We took steps in developing the survey, collecting the data, and analyzing them to minimize such nonsampling error—including using a social science survey specialist to help design and pretest the survey in collaboration with GAO staff who had subject matter expertise. When we analyzed the data, an independent analyst checked all computer programs. Since this was a Web-based survey, respondents entered their answers directly into the electronic questionnaire, eliminating the need to key data into a database, thereby minimizing error. For a copy of our survey, see appendix III.

To examine key federal supports for these projects, we reviewed relevant legislation, previous GAO reports, and agency documents, and we interviewed agency officials. Using our previous reports, we compiled a list of federal supports for these projects, and during our interviews with stakeholders we asked which of the supports were key to the development of projects. The federal programs described in this report reflect those supports that stakeholders considered key for the development of new utility-scale electricity generation projects. We also collected and analyzed agency data on outlays, loan programs, and tax expenditures that supported these projects from fiscal year 2004 through 2013 as follows:

Outlays: We collected and analyzed data on outlays, projects and generating capacity added from USDA, DOE, and Treasury. To assess the reliability of these data, we interviewed individuals with knowledge of them. From this review, we determined that the data were sufficiently reliable for the purposes of this report.

Loan programs: We also collected and reviewed data from DOE and USDA on loan programs, projects, and generating capacity added. We used two methodologies to calculate the cost to the government of loan programs supporting these projects:

For DOE’s two loan guarantee programs, we collected net lifetime credit subsidy reestimates, including interest, for all the loan guarantees within our scope—those that supported projects of 1 megawatt (MW) or greater that were connected to the grid with the intent to sell electricity—as of the close of fiscal year 2013. Because only a subset of the loans in DOE’s portfolio is within our scope, our estimates will not match the estimates found in the fiscal year 2014 Federal Credit Supplement to the Budget of the U.S. Government. We added that net lifetime credit subsidy reestimate to the original credit subsidy estimate to calculate the estimated cost to the government of the loan guarantee as of the close of fiscal year 2013. We then summed those estimates to calculate the total cost of DOE’s loan guarantee programs. To assess the reliability of these data, we interviewed agency officials, verified our calculations with agency officials, and made changes as appropriate. From this review, we determined the data were sufficiently reliable for the purposes of this report and agency officials concurred with our results.

For USDA’s loan programs, we used USDA’s net lifetime credit subsidy factor reestimates, including interest, for each loan cohort (all loans guaranteed within a fiscal year) from the fiscal year 2014 Federal Credit Supplement to the Budget of the U.S. Government, and applied the reestimated credit subsidy factor to each individual loan. Only a subset of the loans in USDA’s portfolio is within our scope, therefore, our estimates will not match the estimates found in the fiscal year 2014 Federal Credit Supplement to the Budget of the U.S. Government. Because USDA does not calculate estimates on a loan-by-loan basis but does so on a cohort basis, applying a cohort’s subsidy factor to only those loans included in our scope represents an estimate of the expected cost to the government. To assess the reliability of these data, we interviewed agency officials, verified our calculations with agency officials, and made changes as appropriate. From this review, we determined the data were sufficiently reliable for the purposes of our report and agency officials concurred with our results.

Tax expenditures: We compiled estimates of forgone revenue to the government from energy-related tax expenditures calculated by Treasury and the congressional Joint Committee on Taxation (JCT) to estimate the cost to the government of supporting these projects. Both Treasury and JCT estimate the revenue loss associated with each tax provision they have identified as a tax expenditure. Treasury’s list is included in the President’s annual budget submission; JCT issues annual tax expenditure estimates as a stand-alone product. Both organizations calculate a tax expenditure as the difference between tax liability under current law and what the tax liability would be if the provision were eliminated and the item were treated as it would be under a “normal” income tax. Revenue loss estimates do not incorporate any behavioral responses and thus do not reflect the exact amount of revenue that would be gained if a specific tax expenditure were repealed. In general, the tax expenditure lists that Treasury and JCT publish are similar, although these lists differ somewhat in the number of tax expenditures reported and the estimated revenue losses for particular expenditures. Specifically, we used the most recent tax expenditure estimates for fiscal years 2004 to 2013 developed by Treasury and reported by Office of Management and Budget in the Budget of the U.S. Government for fiscal years 2006 to 2015. Similarly, we used the most recent tax expenditures estimates developed by JCT and reported in their Estimates of Federal Tax Expenditures reports for fiscal years 2004 to 2012. For fiscal year 2013 data, we used estimates from the 2012 JCT report, which reflect the provisions in federal tax law enacted through January 2, 2013. Although we present the tax expenditure estimates in aggregate, and the sums are reliable as a gauge of general magnitude, they do not take into account interactions between individual provisions. To assess the reliability of these data sets, we reviewed available documentation on the collection of and methods that were used in calculating the estimates. From this review, we found some limitations but determined that they were sufficiently reliable for the purposes of this report.

We did not analyze federal supports related to electricity end use or consumption, such as those designed to promote energy efficiency and conservation or to provide low-income energy assistance. In addition, because our scope was limited to supports for the construction of new utility-scale electricity generation projects, we did not collect data on possible electricity-related research and development funding by federal agencies, nor did we examine other financial structures, such as master limited partnerships, real estate investment trusts, or yield cos, which could have been used for the development of these projects.

To examine how state and federal support affect the development of projects, we conducted semistructured interviews with nearly 50 stakeholders, as noted above. We also modeled typical project finance structures—as identified by stakeholders—for hypothetical solar photovoltaic and wind projects using the DOE’s National Renewable Energy Laboratory’s (NREL) System Advisor Model. For information on our analysis, see appendix VIII.

We conducted this performance audit from August 2013 to April 2015 in accordance with generally accepted government auditing standards.

Those standards require that we plan and perform the audit to obtain sufficient, appropriate evidence to provide a reasonable basis for our findings and conclusions based on our audit objectives. We believe that the evidence obtained provides a reasonable basis for our findings and conclusions based on our audit objectives.

Appendix II: Stakeholders Interviewed by GAO

Appendix II: Stakeholders Interviewed by GAO Type of stakeholder For-profit developers: Utilities and independent power producers Caithness Energy Evergreen Clean Energy, LLC Exelon Generation Co.

First Solar, Inc.

NextEra Energy Resources, LLC Pacific Gas and Electric Company Nonprofit developers: Electric cooperatives and municipally-owned utilities American Municipal Power, Inc.

Associated Electric Cooperative Inc.

Brazos Electric Cooperative, Inc.

Appendix III: GAO Survey of State Regulatory Commissions

The contents of this appendix represent an approximation of how survey respondents viewed GAO’s survey online. In addition to the answer options provided, all survey respondents had the option to report “No answer” to each of the questions contained in this survey. Please see appendix I for additional information about how the GAO administered this survey.

Appendix IV: Additional Information about State and U.S. Territory Renewable Portfolio Standards and Renewable Portfolio Goals

The tables in this appendix reflect answers provided by officials from state regulatory commissions to survey questions about their state’s renewable portfolio standard (RPS) or renewable portfolio goal (RPG). Table 4 reflects answers for states and table 5 reflects answers for U.S. territories. States and territories that did not participate in our survey are not included in these tables.

Appendix V: Types of Utilities for Which Regulatory Commissions Regulate Electricity Generation Services

Tables 6 and 7 in this appendix reflect survey respondents’ answers to questions about whether regulatory commissions regulate retail rates for electricity generation services provided by investor-owned utilities, municipally-owned utilities, and electric cooperatives in their states or territories. States and territories that did not participate in our survey are not included in these tables. For more information about how we administered our survey, see appendix I.

Appendix VI: Outlays, Loan Programs, and Estimates of Tax Expenditures That Supported Utility-Scale Electricity Generation Projects

Table 8 in this appendix reflects outlays that supported utility-scale electricity generation projects for fiscal years 2004 to 2013. Table 9 reflects the estimated cost to the government of loan programs that supported these projects during this same time period. Table 10 reflects the estimated cost of tax expenditures for these projects during this same time period.

Appendix VII: Federal Supports for Utility- Scale Electricity Generation Projects by Agency

Tables 11 through 13 below provide descriptions, by agency, of the federal programs we identified that supported utility-scale electricity generation projects. The tables also provide information on supports that will or have expired, in full or in part, due to an expiration of legislative authority or some other expiration under the law as of the spring of 2015, as well as those supports that currently have no expiration.

Appendix VIII: Financial Modeling Methodology and Additional Analysis

We used the System Advisor Module (SAM) developed by the National Renewable Energy Laboratory (NREL), and, as noted below, a modification of SAM that we developed, to analyze the possible effects of actual and planned reductions in the value of the Energy Investment Credit, also known as the Investment Tax Credit (ITC) or the Energy Production Credit, also known as the Production Tax Credit (PTC) on renewable utility-scale electricity generation projects. These tax credits, among others, represent a key form of federal support for the construction of new renewable utility-scale electricity generation projects, and they can represent a significant portion of the total after-tax returns from investments in renewable energy projects. We used SAM to estimate the magnitude of these effects. This appendix describes our analysis of the role of the ITC and PTC on investments in renewable energy projects, and the effects of changes in the value of these tax credits on those investments by (1) providing an overview of SAM, (2) describing our use of SAM, and (3) providing the key results from SAM.

Overview of SAM

SAM provides energy performance and financing tools that are designed to facilitate investment and analytical decisions in renewable energy projects. These tools can provide information to participants in the renewable energy sector, including policy analysts and developers of renewable energy projects. SAM provides the flexibility to allow the user to input either highly detailed configurations of equipment and financing or generalized assumptions. For example, a solar flat-plate photovoltaic project could be specified in terms of individual solar panel and inverter modules installed with very specific details as to tilt and ability to track the sun, and with component-by-component acquisition and installation costs. Alternatively, the project can be described in a less specific manner, with an aggregate installation cost per watt.

SAM is composed of the following two modules:

Performance module: SAM can be used to analyze many aspects of the expected energy performance of large, utility-scale solar and wind projects. SAM also allows users to compare differences in how specific equipment may perform and can estimate equipment conversion efficiencies for specific modules of solar panels, wind turbines, and other equipment that can be used to develop estimates of electricity production. SAM also includes data on typical, as well as historical weather patterns for a wide range of locations.

Financial module: In SAM’s financial module, the user specifies values for cost and other financial characteristics, including the value of federal tax credits and accelerated depreciation for renewable energy property. The financial module begins with energy inputs automatically transferred from the performance module—specifically, the estimated amount of annual electricity generated. The financial module assumes that the project earns its revenues from sales of this electricity to an electric utility through a contract referred to as a power purchase agreement (PPA). The financial module generates a cash flow analysis over the life of the project given the specification of revenues, costs, and information about the nature of the investment in the project. The financial module is flexible in that different investment structures can be examined. Specifically, the project finance structures that can be analyzed in SAM include two partnership flip structures—a structure in which the vast majority of project cash and tax benefits and liabilities go to one partner until certain financial conditions are met, at which point they flip so that the other partner receives the vast majority of cash and tax responsibilities— and a structure in which the developer owns the project—referred to as the single owner structure. The user must specify other financial parameters, including desired rates of return for the investors— specifically after-tax internal rates of return (IRR)—project borrowing costs, and how project revenues and tax expenditures will be allocated among partners in the two partnership structures.

SAM’s ability to analyze different investment structures is important. As noted elsewhere in this report, some developers have to enter into complex financial partnerships—tax equity partnerships—with third party entities in order for the project to make use of these tax benefits. For this analysis, we examined two such partnerships as follows:

All equity partnership flip: In the all equity partnership flip structure, the developer and tax equity partner create a special-purpose entity, formed exclusively to build and operate the project, which is funded entirely by the equity contributions from both partners. The tax equity partner provides the majority of funding for the project in return for nearly all project revenues and tax expenditures (as well as any tax liabilities) generated by the project for a specified amount of time from the beginning of the project. This period of time, which can vary by project, depends on the tax equity partner’s desired rate of return and rules governing the tax expenditures used by the project. Once the tax equity partner realizes its required rate of return, the allocation of project proceeds “flips” so that the developer begins receiving the vast majority of project revenues and tax liabilities.

Leveraged partnership flip: The leveraged partnership flip is similar to the all equity flip, but substitutes some or all of the project developer’s equity investment with borrowed funds, referred to as debt. Project revenues and tax expenditures are still shared between the partners in the same manner as in the all equity flip; however, the existence of debt means that the project must make principal and interest payments before any revenues can be shared between the partners. Thus, if the project were to run into financial difficulties, the debt- holder would have a senior claim on project proceeds, so the tax equity investor would receive lower-than-anticipated returns. Several stakeholders told us that tax equity partners prefer arrangements in which their returns are not subordinate to debt, so leveraged structures are not commonly used. They also noted that when leveraged structures are used, tax equity investors require higher rates of return in order to compensate them for the higher risk.

In contrast to the partnership structures, the single owner structure, which we also modeled, is simpler in that there are no arrangements between the partners that must be negotiated and monitored. The owner makes the equity investment, typically accompanied by debt financing, and receives all available cash proceeds and tax benefits (or liabilities), but, as mentioned, this structure is not attractive to those developers without income tax liabilities sufficient to make use of tax credits.

The single owner and leveraged partnership flip structures involve debt- financing. SAM assumes that the project takes on as much debt as possible because debt is typically the least-costly funding source for a project. The maximum level of debt depends on two factors: the amount of cash available for debt service, and the debt service coverage ratio. The amount of cash available for debt service is a pretax measure of earnings defined as total revenue minus total expenses minus the amount set aside for equipment replacement reserves. The debt service coverage ratio is the ratio of cash available for debt service and the amount used for debt service, defined as the sum of principal and interest payments. If the ratio has a value of one, that means all available cash is used for debt service. For a given debt service coverage ratio, the maximum level of debt increases with the amount of cash available for debt service. For a given amount of cash available for debt service, the maximum level of debt decreases with the debt service coverage ratio. The debt service coverage ratio is selected by the user of SAM to represent constraints imposed by the lender. One implication of this aspect of SAM is that, as PPA prices increase, so will the amount of cash available for debt service and thus the share of debt in the project financing. Thus, higher PPA prices are associated with smaller equity investments.

The SAM financial module has two possible solution methods. Both solutions link project investments, returns on those investments, and the PPA price. In one solution mode, the module solves for the lowest PPA price that will provide the investor’s return on investment goal. For example, if an investment goal—i.e., an after-tax internal rate of return goal—is 12 percent, the module will determine the lowest PPA price meeting that goal. The second solution mode calculates the cash flows that would result from the selection of a particular PPA price. For example, if a PPA price of $0.07 per kilowatt-hour is desired, the module will determine the financial flows that result from that PPA price, including the rate of return an investor would earn with that price.

Our Use of SAM

In this section, we discuss our use of SAM. Specifically, we discuss: (1) the types of projects we modeled; (2) our investor rates of return targets; (3) installation and finance costs; and (4) aspects of the partnership structures related to equity shares and capital recovery by the project developer. We believe that our use of SAM to examine the possible effects of changes in the value of tax credits is an appropriate use of the model, and that SAM is sufficiently reliable for the purposes of this report. To make that determination, we met with NREL officials to learn about the development and uses of the module, and we identified peer-reviewed and other publications that used SAM to analyze various energy and financial performance issues related to investments in renewable energy. We also interviewed industry experts who had used the modules and shared our preliminary results with officials from NREL and other industry participants and analysts. Where applicable, we incorporated their comments into our analysis.

We modeled a hypothetical solar photovoltaic project and a hypothetical wind project, and we used SAM to examine the role of tax credits on investments in these projects. We located our hypothetical solar photovoltaic project in Phoenix with a generating capacity of 100 MW, and we located our hypothetical wind project in the state of Washington with a generating capacity of approximately 150 MW. The SAM performance module calculated that the solar photovoltaic project would generate172,975,664 kilowatt-hours of first-year energy for a capacity factor of 19.7 percent. Likewise, SAM calculated that the wind project would generate 530,041,600 kilowatt-hours of first-year energy for an implied capacity factor of 40.4 percent. We believe projects of these sizes and locations represented reasonable examples of utility-scale renewable energy projects.

For each of our projects, we assumed that the costs to install and operate the project would not change across the project finance structures we examined; however, total project costs varied because financing costs vary across the investment structures. For both types of projects, we assumed a project life of 20 years, PPA terms of 20 years, and PPA price escalation at the rate of 2.5 percent annually. After specifying project costs, return on investment targets, and other parameters as inputs to the module, which we describe in more detail below, we analyzed module solutions for each project in two tax credit environments, and compared the results between the two environments. First, we defined a more- generous tax credit environment—which, in the case of the ITC, was at the current level of 30 percent of the value of a qualified investment and, in the case of the PTC, was at the level of the PTC before it is scheduled to expire on December 31, 2014. In 2013, this value was $0.023 per kilowatt hour, which was then set to escalate over a 10-year period. We then defined a less-generous tax credit environment in which the ITC is 10 percent of the value of the investment—a level to which the ITC is scheduled to change in 2017—and there is no PTC—since the PTC is scheduled to expire at the close of 2014. We modeled the solar project using the ITC and the wind project using the PTC because, according to stakeholders, utility-scale solar projects generally use the ITC and utility- scale wind projects generally use the PTC. We modeled both projects with accelerated depreciation for renewable energy property.

In the more generous tax credit environment, we used SAM to calculate the PPA price that yields the investor’s rate of return target. We labeled this case as the base case. We analyzed the less generous tax credit environment in two ways. First, we used SAM to calculate the PPA price that provided the investor’s target rate of return in the new environment. This solution PPA price will be higher than the solution in the more generous case because the contribution of the tax credit to total after-tax returns is lower (in the solar photovoltaic project), or nonexistent (in the wind project). If the investor is to receive the same return on investment, the returns from energy revenues must increase to replace those lost with the reduction or elimination of the tax credit. Since the amount of electricity generated by the project does not change, the price at which this electricity is sold is the only mechanism by which higher revenues can be obtained. We labeled this solution as the higher PPA case. In the second solution concept, we maintained the PPA at the level found in the more generous tax credit environment, and we calculated the lower returns that resulted from holding energy revenues at this level while the returns from the tax credit were reduced or eliminated. We labeled this solution as the lower returns case.

For the leveraged partnership and single owner investment structures, the higher PPA case leads to a smaller equity investment by the tax equity investor and the single owner, respectively, because the share of debt financing increases along with increases in the PPA price. In the all equity partnership flip structure, the equity investment share of the tax equity partner does not similarly adjust within the module; rather, it is a parameter chosen by the user of SAM. Because the reduction or elimination of the tax credits would likely reduce the value of these projects to tax investors, and hence their willingness to invest in these projects, we chose to reduce the tax investor’s share in the investment from 60 percent in the base case to 30 percent in the less generous environment.

We specified rate of return targets for the investors based on information we collected in interviews with stakeholders, which included project developers and owners; attorneys and experts who specialize in project finance; industry trade associations; nongovernmental organizations; banks that provide equity and debt financing; and investor-owned utilities, municipally-owned utilities, and electric cooperatives. These stakeholders provided their opinions about investment return targets, including differences that might exist between photovoltaic solar projects and wind projects, and considerations that relate to the different investment structures we analyzed. We synthesized this information in providing specifications for our hypothetical projects, and while we believe that they represent contemporary features and conditions, target rates of return for actual projects vary. Table 14, below, shows the specific rate of return targets we selected for our analysis. Because the choice of target year is influenced by the duration of available tax benefits, we selected different target year values for the partnership flip structures for the wind project; specifically, we selected a 10-year target when the PTC was available to match the 10-year duration of the PTC. We intended for these projects, although hypothetical, to represent utility-scale projects developed by experienced developers with market-tested features. In particular, we did not intend for the rate of return targets we chose to include a premium that investors might look for as compensation for any extra risk that might result from projects that contained particularly risky components—such as untested technology.

Installation costs include the costs of acquiring and installing capital equipment, such as panels and inverters in the solar photovoltaic project and wind turbines in the wind project. Installation cost represents the most important determinant of total project costs, and hence affects the scale of the investment on which investor returns are calculated. We relied on studies of recent trends in solar and wind installations conducted by analysts at the Lawrence Berkeley National Laboratory. We discussed the issue of installed costs with several analysts and those familiar with recent trends in renewable energy project costs. We selected an installed cost per watt value of $2.00 for the solar photovoltaic project and an installed cost per watt value of $1.70 for the wind project. We believe that these values represent reasonable values for installed cost in the environment in which projects are currently being developed.

Total project costs vary across investment structures because of differences in the sources of investment funds. In the single owner and leveraged partnership flip cases, the projects are financed with significant amounts of debt, and there are fees and other costs associated with obtaining loans. Likewise, the partnership flip structures include costs to arrange the partnership and to negotiate the rules under which the partners share the proceeds from the project. Additionally, in the partnership flip structures, we assumed that the project pays the developer a development fee. Table 15 provides information on the values we specified for key cost variables.

As we mentioned above, in addition to tax credits, federal support is available to renewable energy projects through the use of accelerated depreciation for renewable energy property on certain equipment. We allocated 95 percent of the project costs into this depreciation category, and placed the remaining 5 percent into the 20-year straight line category. In the case of the solar projects, we reduced the tax basis by an amount equal to 50 percent of the dollar value of the ITC to reflect the basis disallowance treatment associated with the tax provisions governing the use of the ITC. We assumed that the project’s taxable income is subject to a state tax rate of 7 percent and a federal (corporate) tax rate of 35 percent.

In describing partnership flip structures, we mentioned the general rule that the vast majority of cash proceeds and tax benefits early in the project life are allocated to the tax investor, and that once the tax investor meets its rate of return target, the allocation of the proceeds flip, and the vast majority of them flow to the developer. One exception to this rule concerns the possibility of capital recovery by the developer in the all equity partnership flip. The SAM all equity partnership flip permits the developer to recover some or all of its equity investment in the early years of a project by receiving all of the cash proceeds for some period of time or until it recovers its equity investment, at which point the bulk of cash proceeds reverts to the tax investor until the time at which the investor’s rate of return target is met. The greater the share of cash that goes to the developer through capital recovery means that less of that cash goes to the tax investor. Thus, a more generous capital recovery selection in SAM increases the developer’s after-tax returns and reduces the tax investor’s after-tax returns. This in turn means that a higher solution level of the PPA price is required to meet the investor’s rate of return target if the developer’s capital recovery increases. Looked at another way, there can be different combinations of developer capital recovery and PPA prices that will meet the tax investor’s rate of return target, but they will result in different rates of return to the developer.

Because of our analytical focus on the effects of changes in tax credits, we wanted to hold both investor and developer returns constant when looking at the change in the solution value of the PPA price. That is, we wanted the solution PPA price in the higher PPA case to increase by no more than was necessary to meet both partners’ investment targets. To do this in the case of the all equity partnership flip, we modified the SAM financial module so that we could define an explicit after-tax rate of return target for the developer and meet this target by modifying the capital recovery feature in SAM. We specified the developer’s target year to be the end of the project life, and we specified a rate of return target of 10 percent.

Analytically, things are somewhat different in the case of the leveraged partnership flip, even though we wanted to hold the developer’s returns constant in the higher PPA case. Given the small equity investment by the developer and the presence of a relatively large development fee both occurring at the beginning of the project, we chose to express the developer’s returns in terms of the net present value of the total after tax returns, a dollar denominated value rather than in rate of return terms. To do this, we adjusted the size of the development fee paid to the developer so that the developer’s returns, defined in net present value terms, did not increase with the higher solution PPA. We used a discount rate of 10 percent to make this calculation; this is the value we selected as the developer’s rate of return target in both the all equity partnership flip and single owner structures.

Another aspect of the all equity partnership flip concerns the specification of the ownership shares of the partners. In the current environment, tax investors are generally the majority partners and, based on our interviews with stakeholders, we specified that the tax investor would have a 60 percent ownership share in the more generous tax credit environment. However, information from our interviews and studies by industry analysts also suggests that tax investors would be less willing to make investments at the same scale if the value of the tax benefits is reduced. We specified that the tax investor would have a 30 percent ownership share in the less generous cases we modeled (see table 16).

As can be seen from the material presented in this section, SAM requires the user to specify values for many factors that can influence the cost of investments and the returns to those investments. We interviewed many knowledgeable analysts and market participants to develop the values we used for our analysis, and we believe them to be analytically conservative. We recognize that the selection of different values for key factors will lead to different analytical results.

Key Results from SAM

Using SAM, we estimated that reducing or eliminating the value of tax credits increases the required revenues provided through PPAs by approximately 20 to 25 percent in the case of the ITC and approximately 30 to 60 percent in the case of the PTC. The module results suggest that the contribution of the tax credits to total after-tax returns are substantial, and that if developers and investors are to continue to meet their investment targets, projects that appear to have been financially viable in an environment with more generous tax credits would not be viable with less tax credit support without an increased contribution from energy revenue through a higher PPA price or reduced return on investment targets. For example, in the single owner case, the ITC provides approximately half of total after-tax returns when the value of the ITC is 30 percent of a qualified investment and about 23 percent of total after- tax returns when the ITC is reduced to 10 percent. Likewise, for the wind project, the net present value of the PTC is almost half of total after-tax returns when the PTC is in place, and of course makes no contribution to after-tax returns when the PTC is eliminated.

While the increases in calculated solution PPA prices were somewhat smaller in dollars per kilowatt hour for the wind project than for the solar project, when they were expressed in percentage terms, the wind project solution PPA price increases were much larger. The value of the PTC started at $0.023 per kilowatt hour, and increased over time. For the wind projects, the base case solution values were below $0.05 per kilowatt hour in each of the investment structures, so the magnitude of the tax credit was about half or more of the solution PPA price. In terms of the lower returns cases, the projects with debt financing took on the same level of debt as in the base case. This meant that there were large equity investments, but reduction or elimination of the tax credits reduced or eliminated those contributions to total after-tax returns. In the all equity partnership flip structures, the tax equity investor met its rate of return target, but the developer’s returns were substantially lower—35 percent in the solar project and over 70 percent in the wind project. In the leveraged partnership flip structure, the project cash flows never flipped, which meant that the tax investor was not able to meet its target rate of return even by the end of the project.

We do not characterize the PPA price or investment return changes shown in these tables as predictions of what will happen to electricity prices or to potential investments in and returns from utility-scale renewable energy projects. Some investment structures may become less favored, and other structures may become more favored in response to a change in the level or form of federal support. Nonetheless, we think that the results indicate that the reduction in federal support of renewable energy projects would put upward pressure on the level of PPA prices and downward pressure on the returns that could be reasonably expected by developers. As such, reducing the ITC or eliminating the PTC could result in a combination of the effects suggested in our modeling. Specifically, to compensate for the decline in federal support, developers might be willing to accept lower rates of return, and states might be willing to require utilities and other retail service providers to pay higher electricity prices. However, there may be limits to which these effects could offset a reduction in federal supports. Placed in a broader context, the willingness of utilities and their regulators to agree to significantly higher prices will likely constrain the ability of developers to maintain their returns on investment by negotiating PPAs with significantly higher prices. Similarly, to the extent that project lenders and investors have alternative investment opportunities, it seems unlikely that they would make financing cost concessions on a scale that would offset the reduction in federal support. Developers themselves are likely to have alternative outlets, either in the energy sector or elsewhere, in which to direct investments if expected returns from renewable energy projects are reduced to unacceptably low levels. Collectively, the constraints faced by project developers may lead to a reduction in the level of investment in renewable energy projects if reductions in the level of federal support in the magnitude examined here are observed.

Tables 17, 18 and 19 present the module’s results for the hypothetical solar project under the three ownership structures. In table 17 we express owner returns and in table 18, we express developer returns in terms of after-tax internal rates of return. In table 19, we express developer returns in terms of the present value of after-tax returns flowing to the developer.

Tables 20, 21, and 22 present the module results for the hypothetical wind project under the three ownership structures. In table 20 we express owner returns and in table 21, we express developer returns in terms of after-tax internal rates of return. In table 22, we express developer returns in terms of the present value of after-tax returns flowing to the developer.

Appendix IX: GAO Contact and Staff Acknowledgments

GAO Contact

Staff Acknowledgments

In addition to the individual named above, Jon Ludwigson (Assistant Director), Stephen Brown, Marcia Carlsen, Marissa Dondoe, Tanya Doriss, Cindy Gilbert, Carol Henn, Mitchell Karpman, Mary Koenen, Alison O’Neill, Dan Royer, Kelly Rubin, MaryLynn Sergent, Anne Stevens, and Barbara Timmerman made key contributions to this report.