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.

Summary:
Why GAO Did This Study

The states and the federal government have supported the development of electricity generation projects in a variety of ways. In recent years, state and federal supports have been targeted toward renewable energy sources, such as solar and wind, although there have been some supports for projects using traditional sources—natural gas, coal, and nuclear.
GAO was asked to examine state and federal supports for the development of utility-scale electricity generation projects—power plants with generating capacities of at least 1 MW that are connected to the grid and intend to sell electricity—for fiscal years 2004 through 2013. This report (1) identifies key state supports for these projects; (2) examines key federal support provided through outlays, loan programs, and tax expenditures for these projects; and (3) examines how state and federal supports affect the development of new renewable projects. GAO analyzed relevant legislation, agency outlay and loan program data, and interviewed stakeholders, including project developers and experts. GAO also surveyed state regulatory commissions about state policies. In addition, GAO modeled the impact of reducing federal tax expenditures on project finances.

What GAO Found

Key state supports, in the form of state policies, aided the development of utility-scale electricity generation projects—particularly renewable ones—in most states, for fiscal years 2004 through 2013. For example, most states have a renewable portfolio standard (RPS) mandating that retail service providers obtain a specific amount of the electricity they sell from renewable energy sources, which creates additional demand for renewable energy. In addition, most states supported new renewable and traditional projects through regulatory policies that set electricity prices, which allowed utilities to recover the costs of building new projects or purchasing electricity from them.
Federal financial supports aided the development of new projects, but limited data hinder an understanding of the effectiveness of tax expenditures. From fiscal year 2004 through 2013, programs at the Departments of Agriculture (USDA), Energy (DOE), and the Treasury (Treasury) provided supports including outlays, loan programs, and tax expenditures. For example, one Treasury program provided payments in lieu of tax credits and accounted for almost all of the $16.8 billion in outlays that supported 29,000 megawatts (MW) of new renewable generating capacity. Tax expenditures accounted for an estimated $13.7 billion in forgone revenue to the federal government for renewable projects and $1.4 billion for traditional projects. The two largest tax expenditures GAO examined—the Investment Tax Credit (ITC) and the Production Tax Credit (PTC)—supported renewable projects and accounted for $11.5 billion in forgone revenue. However, the total generating capacity they supported is unknown because the Internal Revenue Service (IRS) is not required to collect project-level data from all taxpayers claiming the ITC or report the data it does collect, nor is it required to collect project-level data for the PTC. IRS officials stated that IRS is unlikely to collect additional data on these tax credits unless it is directed to do so. Since 1994, GAO has encouraged greater scrutiny of tax expenditures, including data collection. Without project-level data on the ITC and PTC, Congress cannot evaluate their effectiveness as it considers whether to reauthorize or extend them.
Developers combined state and federal supports to finance renewable projects, and reducing these supports would likely reduce development of such projects. Demand created by state RPSs allowed developers of renewable projects to obtain power purchase agreements (PPA)—long-term contracts to sell power at specific prices. Federal supports, in turn, lowered developers' costs to build renewable projects, which allowed them to offer lower PPA prices than they otherwise could have. According to most stakeholders, these lower prices were then passed on to retail customers. Overall, if the level of support is reduced, fewer projects would likely be built. For example, GAO's modeling suggests that reducing the ITC or eliminating the PTC would likely reduce the number of renewable projects built because developers' returns would decline unless PPA prices increased to compensate for the reduction in federal support. The extent to which development would decrease depends on how states respond to reduced federal support and the associated increase in prices. For example, many states limit the amount retail prices could increase, limiting PPA price increases, which could reduce development.

What GAO Recommends

Congress should consider directing IRS to (1) collect and report project-level data from all taxpayers who claim the ITC and (2) collect and report similar data for taxpayers who claim the PTC.
DOE, Treasury, and USDA did not provide formal comments in response to a draft of this report.