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. 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). 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. 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, 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. 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.