The federal and state governments have supported the discovery, development, and maturation of new energy sources and technologies since America’s earliest days. Coal-, petroleum-, natural gas-, nuclear-, and renewable fuel-based electricity production each benefited in the earliest stages of development from targeted government policies intended to support and develop the industry. Most of these industries have fully matured, and as of this writing, each continues to benefit from targeted policies at both the federal and state levels.
Energy policies have focused on supply, usually aimed at increasing or maintaining production levels and decreasing or stabilizing prices (Adams, 2010). Common policies have included direct subsidies, exemption from or reduction of taxation, import controls, funding for research and development (R&D), indemnification, and the creation of government agencies intended to provide research and other direct support to an industry.
This chapter first provides a brief synopsis of historical supports made available to each major energy source in its nascent stages of creation and development, followed by a basic account of the level of current supports. The chapter then investigates various approaches to lowering the cost of capital and reducing risk to private capital for financing the deployment of increasingly clean electric power technologies.1 One key approach is to ensure that markets fully account for all costs, including pricing of externalities such as the costs associated with pollution, including oxides of sulfur (SOx), oxides of nitrogen (NOx), and greenhouse gases (GHGs). But as discussed earlier in this report, pollution pricing would not address institutional barriers and other market imperfections. Thus, another important approach is to enable financing mechanisms that lower or avoid up-front cost barriers by allowing implementation costs to be financed over time by project savings. The final
section explores ways of addressing barriers that remain at the deployment stage of increasingly clean electric power technologies.
The committee notes that quantitative measures of historical and current subsidies and the social cost for all environmental damage created by using different fuels and technologies in generating electric power are not currently available. More research is needed in this field, given the long life span of power plants.
The federal government’s involvement in the U.S. coal industry has a long history. In 1789, the then-new federal government imposed a modest tariff on imported coal, the goal being to protect nascent American industries from British imports. This tariff grew until, by the War of 1812, the import tariff amounted to 15 percent of the price of British coal (Adams, 2006). The government reduced the tariff by half following the war, but maintained it at levels sufficient to guarantee that domestic sources would dominate the new market until, in the 1870s, the United States became a net exporter of coal.
In 1879, Congress established the United States Geological Survey (USGS). While the USGS mission was to be scientific and military in nature, it was specifically charged with charting anthracite in Pennsylvania and coalfields generally. In effect, through USGS, the federal government subsidized coal exploration, and the accumulation of vital industry data became a national-level activity (Adams, 2006).
In the 20th century, the development of competition-restricting collusion between coal producers and railroads, in addition to major labor disputes within the coal industry, led to increased involvement in the industry on the part of the federal government. In 1902, for example, President Theodore Roosevelt set a precedent for federal intervention in the coal industry when a labor strike threatened energy supplies for the entire East Coast. The decision in a 1908 Department of Justice lawsuit against railway companies accused of price manipulation upheld the International Commerce Commission’s (ICC) ban on the ownership of mines by railroad companies, and in 1910, the U.S. Bureau of Mines was established, overseeing the creation of federal safety standards for mineworkers. As Adams (2006, p. 77) notes in his study on the political history of U.S. energy systems, “In all these cases, federal intervention in the nation’s coal trade preserved the nineteenth-century focus on high levels of production.”
Individual states had more extensive involvement with the early development of the coal industry. Beginning in the early 19th century, state governments enacted laws and policies designed to promote the large-scale
exploitation of domestic coal reserves and to keep the price of coal stable and accessible. In Pennsylvania in the 1830s, for example, the state legislature passed a measure exempting anthracite coal from taxation. In addition, by refusing to grant exclusive transportation rights to any one company, Pennsylvania lawmakers fostered competition among coal companies and thus kept the price of coal relatively low (Adams, 2010).
Petroleum and Gas
The petroleum industry similarly relied on the support of the federal government in its early development. From early in the 20th century, the federal government used the tax code to encourage the broadest possible exploitation of petroleum and gas reserves. In 1916, the tax code introduced the expensing of intangible drilling costs (IDCs) and dry-hole costs. In 1926, the Percentage Depletion Provision was incorporated into the tax code to allow the deduction of a fixed percentage of gross receipts rather than a deduction based on the actual value of the recovered resources (Pfund and Healey, 2011). The percentage depletion allowance, which still is available to selected taxpayers, is an alternative to cost depletion and is currently available only for domestic production by independent companies up to a maximum of 1,000 barrels per day (or 6 million cubic feet [MMcf] per day for natural gas), and cannot exceed half the net income from the property. The depletion rate is set at 15 percent gross production revenues. The most striking aspect of the percentage cost depletion allowance is that it can exceed the cost of the original investment over the life of the property, in effect providing a complete government subsidy for costs associated with the property’s purchase and maintenance (NRC, 2013c).
Through the mid-1980s, subsidies provided to the oil and gas industries constituted the largest federal energy tax provisions in terms of revenue loss. Between 1918 and 2009, these subsidies amounted to an historical annual average of $4.86 billion (Pfund and Healey, 2011).
The nuclear power sector is unique in that it is historically a product of federal-level policy making. Most federal subsidies for the nuclear industry have taken the form of support for R&D. Over the period 1948 to 2014, Department of Energy (DOE) R&D funding for the nuclear sector amounted to $97.44 billion (in 2013 dollars), nearly twice the amount provided for fossil fuel development, and the next-largest allocation of federal energy-related R&D funding after petroleum and gas (Sissine, 2014). From its earliest beginnings, moreover, this funding focused specifically on a concerted effort to develop a new electricity industry, an effort that slackened only with the decline of interest in nuclear production as a result of safety and financial concerns. By way of illustration, of the total amount spent since 1950 on exploring reactor concepts
and potential civilian and military applications of nuclear energy, some $42 billion (nearly 60 percent) was spent before 1975 (MISI, 2011).
Another significant policy in support of nuclear power operations is the Price-Anderson Act (PAA). The PAA has a dual purpose: to “protect the public and...encourage the development of the atomic energy industry” (Heal and Kunreuther, 2010; Rothwell, 2001, quoting the PAA).2 The PAA provides the nuclear power industry with blanket indemnity for tort liability, the first layer of protection being $200 million in private insurance provided through the American Nuclear Insurers, and the second being a set amount to be provided per reactor by nuclear plant owners following an accident at any nuclear power reactor. The value of this coverage totaled $9.3 billion in 2001, an amount that is certainly higher today because of both inflation and increased buy-in costs levied on the nuclear industry. During the early years of the U.S. nuclear power industry, producers argued that indemnity such as that provided by the PAA was necessary to enable them to shoulder other costs, such as those related to construction (Heal and Kunreuther, 2010; Rothwell, 2001).
In addition, the federal government is responsible for the regulation and safe management and disposal of spent nuclear fuel. Specifically, the Nuclear Regulatory Commission’s (U.S. NRC) Office of Nuclear Material Safety and Safeguards (NMSS) develops and implements U.S. NRC policy in this area (U.S. NRC, n.d.). Congress tasked DOE, aided by the new Nuclear Waste Fund, with the collection and storage of spent nuclear fuel, and mandated that DOE create a permanent storage site by no later than January 1998 (Garvey, 2009). While the creation of the permanent storage site at Yucca Mountain has been held up for many years, this mandate remains.
Large-scale hydropower in the United States owes its early development in the 1930s to extensive federal programs. A detailed accounting of those government expenditures is difficult because this development occurred in a complex policy environment. This is the case in part because federal dam-building projects undertaken by the Bureau of Reclamation and the Army Corps of Engineers in the 1930s and 1940s also had such goals as flood control and navigation (Pfund and Healey, 2011). Additionally, large-scale hydroelectric facilities function as wholly owned subsidiaries of the federal government, and so do not need to earn private rates of return. Thus, an argument can be made that they have served as an industry support dating back to the establishment of the Tennessee Valley Authority in 1933 (Tennessee Valley Authority, n.d.), the Bonneville Power Administration in 1937 (Bonneville Power Administration, n.d.), and other federally owned and operated electric power producers (Pfund and Healey, 2011).
2 Price-Anderson Act 42 USC 2012i.
Wind, solar, and geothermal electricity production represents a recent sector in the U.S. electricity market. Government support for this sector at the federal level takes the form of tax subsidies—specifically the production tax credit (PTC) and the investment tax credit (ITC).
The PTC was first enacted in 1992 and has been renewed or extended a number of times. It provides a rate of 1.5¢/kilowatt hour (kWh) over 10 years, adjusting with inflation so that as of January 2015, it provided 2.3¢/kWh for the first 10 years of electricity production generated from qualifying wind, geothermal, and biomass sources, or a credit of 1.2¢/kWh for other qualifying renewable sources (Heal and Kunreauther, 2010; Pfund and Healey, 2011). The ITC for alternative energy sources provides a nonrefundable tax credit for building solar, wind, geothermal, fuel cell, and microturbine energy generation facilities. The tax credit is given the year the facility enters service. The ITC first appeared in the Energy Tax Act of 1978 (PL 95-618) (Pfund and Healey, 2011). These credits lower the cost of electricity generated from renewable resources, encouraging their substitution for fossil fuels, and thereby tend to reduce GHG emissions (NRC, 2013c, p. 3).
In recent years, the renewable energy PTC and ITC have at times been allowed to lapse, with subsequent, short-term renewal in tax-extender packages. While eligibility was modified over this term to allow PTC subsidies to apply to a broader range of project starts, these on-and-off subsidies have created significant market uncertainty and have led to layoffs throughout the wind turbine, tower, and component supply chain. At the end of 2012, for example, the PTC was extended for 1 year through 2013. It was then allowed to lapse, and was subsequently extended in December 2014 retroactively for calendar 2014, lapsing again at the beginning of 2015. The latest renewal of the credit was enacted in December 2015 and applied retroactively to January 1, 2015. The most recent extension, in December 2015, included a phase-out schedule that differs for solar and wind. The phase-out for wind begins for construction initiated in 2017, with full phase-out at the end of 2019. The PTC for other eligible renewable energy technologies was extended only for construction initiated through the end of 2016 (DOE, n.d.-c).
Currently, eligible solar facilities qualify for an ITC equal to 30 percent of expenditures for construction commencing in 2016, phasing down to 10 percent in 2023 and beyond. Geothermal facilities qualify for an ITC equal to 10 percent of expenditures for construction initiated in 2016 and beyond, while large wind facilities qualify for an ITC that is gradually phased out until 2020. The ITC for other technologies expires at the end of 2016. Technologies eligible for the PTC can opt for the ITC instead if construction commenced prior to January 1, 2015; for construction initiated after that date, only wind facilities remain eligible to claim the ITC in lieu of the PTC (DSIRE, 2015).
A number of renewable energy technologies also receive tax benefits under the Modified Accelerated Cost-Recovery System (MACRS), which allows the owner to write off the value of some capital assets at a rate that exceeds their estimated useful life. Doing so reduces taxable income in earlier years by allowing a larger depreciation expense than is actually represented by how much of an asset’s usefulness is consumed in those early years.3
As a whole, subsidies for renewable energy technologies have increased over the past 10 years. Records of the last few years show a spike in investment in renewable sources due to the American Recovery and Reinvestment Act (ARRA), to the point where they exceeded investment in fossil fuel-powered production. However, the subsidy patterns that have defined the last few decades have, in the wake of the ARRA’s expiration, most likely returned to favoring fossil fuel (EIA, 2015c; ELI, 2009; Heal and Kunreauther, 2010; Pfund and Healey, 2011).
Renewable energy also is supported by state-level policies.4 One key policy promoting the deployment of renewable energy is the renewable portfolio standard (RPS) (see 5 use renewable energy or obtain renewable energy credits (RECs) above a minimum threshold amount of their electricity sales, or that utilities procure above a minimum amount of renewable generating capacity in their portfolio of electricity resources. RPSs set a schedule for renewable energy or capacity to be obtained by specific years. Requirements generally increase over time.
As of June 2016, 29 states6 and the District of Columbia had an RPS in force. These jurisdictions account for 63 percent of U.S. electricity sales (EIA, 2015d). Some sources attribute the development of approximately 46 gigawatts (GW) of new renewable generating capacity from 1998 through 2012 to state RPS requirements (Heeter et al., 2014, p. 1). This amounts to roughly two-thirds of all nonhydroelectric renewable electricity generating capacity additions in the United States since 1998. An additional 8 states have adopted voluntary renewable energy goals.7 Together these 36 states and the District of Columbia account for more than three-quarters of U.S. electricity sales (EIA, 2015d).
3 The depreciation schedule is based on the type of renewable technology. See Internal Revenue Service (IRS) Publication 946, IRS Form 4562: Depreciation and Amortization for further information.
4 A comprehensive list of salient state laws and regulations in effect as of the end of October 2013 is available in the Energy Information Administration’s (EIA) Annual Energy Outlook 2014 (EIA, 2014a, pp. LR-4-LR-9).
5 Either utilities or, in jurisdictions with retail competition, retail electricity providers.
6 Arizona, California, Colorado, Connecticut, Delaware, Hawaii, Illinois, Iowa, Maine, Maryland, Massachusetts, Michigan, Minnesota, Missouri, Montana, Nevada, New Hampshire, New Jersey, New Mexico, New York, North Carolina, Ohio, Oregon, Pennsylvania, Rhode Island, Texas, Vermont, Washington, and Wisconsin (DSIRE, 2016).
Finding 7-1: Short-term tax credit extensions lead to market uncertainty, increase investment risk for technology manufacturers and project developers, and contribute to an uneven playing field relative to market segments with long-term policies or economically mature and competitive technologies.
Subsidies for Research and Development
Government subsidies active at the demonstration phase of new technology development are difficult to track, so little research in this area is available. Because of its high profile, carbon capture and storage (CCS) does offer one possible window on this information. Specifically, the ARRA provided $1.52 billion of support for the exploration and implementation of CCS projects (ELI, 2013, p. 9). However, this was a short-lived program, allowed only under the now-expired ARRA.
From 1978 to 2010, federal funding for energy-related R&D amounted to $121 billion, $45 billion of which is accounted for by nuclear power. Meanwhile, $26 billion has gone to the coal industry, $26 billion to end use, $20 billion to renewable energy, and $4 billion to oil and natural gas (EIA, 2011). During the 10-year period 2005 to 2014, nuclear power remained the primary benefactor of DOE-directed R&D funding, receiving 27.4 percent, while fossil energy received 23.5 percent, renewables 18.5 percent, and end use/efficiency 15.8 percent (Sissine, 2014, p. 7).
Potential for Subsidies to Persist
Analysis of the history of U.S. subsidies for energy technologies, including electric power, suggests that a range of fossil fuel subsidies continue to support technologies and industries even after they have achieved maturity and a notional ability to function independently in an open market. Coal in particular benefits from a wide range of government supports despite being a well-established cornerstone of the U.S. energy economy. USGS continues to provide research services for the industry through its National Coal Resources Data System (NCRDS). In addition, current tax benefits include excess of percentage over cost depletion (Internal Revenue Code [IRC] Section 613), which allows taxpayers to deduct 10 percent of gross income from coal production (ELI, 2013). Other benefits include exploration and development expensing (IRC Section 617) and amortization of coal pollution control (IRC Section 169) (ELI, 2013). There are also a number of policies that some observers consider implicit subsidies to coal, such as exemptions from environmental regulation and rules regarding the assessed value of coal mining leases on public lands for royalty payments (GAO, 2013).
Petroleum and gas receive similar benefits. Intangible drilling costs are supported through oil and gas excess of percentage over cost depletion (IRC Section 613), which allows independent producers to deduct 15 percent of gross income earned from qualifying deposits. This deduction can exceed the cost of the asset developed and thus serves to subsidize its development (ELI, 2009; NRC, 2013c). Also providing tax relief to oil and gas producers are the exception from passive loss limitations for oil and gas (IRC Section 468(c)(3)) and oil and gas development expensing (IRC Section 617).
Finding 7-2: Subsidies can serve important public policy functions when they help to establish industries. When an industry is mature, it is ideally placed for stable competition.
Recommendation 7-1: Policies intended to support increasingly clean electric power deployment should be structured both to be as technology-neutral as possible—that is, performance- or outcome-oriented without regard to specific technology—and to include sunset provisions so that they expire either after a specified length of time or once a certain level of performance has been achieved. Proper use of sunset provisions could ensure that subsidies will not outlive their usefulness in effecting important public policy to assist in the initial development of critical industries. Such sunset provisions are best based wholly on performance criteria, thus eliminating unforeseen favoring of one technology over another.
As discussed above, each of the dominant electricity generation sectors, defined by fuel type, has historically been actively supported by government measures in its economic and market development. Beginning in the second half of the 20th century, and in particular following the oil shock and downturn in nuclear development in the 1970s, this pattern of government support took on a new shape. The current landscape is defined in part by government support mechanisms originally intended for nascent sectors of the economy that have since matured.
Master Limited Partnerships and YieldCos
Subsidies can be both direct and indirect, and policies can take many forms. One policy available for fossil fuels that is essentially unavailable to newer, increasingly clean power sources is the ability to create a so-called master limited partnership (MLP) that is traded on a public exchange. Currently, the use of MLPs is restricted to entities that generate income from qualifying natural resource activities or from transportation or storage of many fuels, including ethanol and biodiesel. The income in an MLP is treated as a “pass-through” for federal income taxes and is not subject to taxes at the entity level. Qualifying income includes earnings from transportation, processing, storage, and marketing of natural gas, crude oil, and related products. MLPs are less costly to the government than many other tax preferences since elimination of the corporate tax at the entity level is to some extent recaptured from the investor, who pays an income tax on all pretax income, not just the after-tax income received in the form of dividends. The Joint Committee on Taxation estimates that for the period fiscal year (FY) 2014-2018, the total cost of energy-related MLPs to the government will be $5.8 billion (Joint Committee on Taxation, 2014). The market value of these MLPs is approximately $500 billion. Legislation allowing renewable energy ventures to use MLPs was introduced in the 113th Congress (S. 795, H.R. 1696) but has not been enacted into law.
Wall Street has created another financing vehicle, known as YieldCos, to lower the cost of capital for increasingly clean energy projects until legislation permits companies to use MLPs. A company or sponsor that has a strong development record in building and operating sources of increasingly clean energy, such as solar farms, and has a pipeline of future development projects can establish a subsidiary. This subsidiary can acquire the parent’s operating assets that have long-term power purchase agreements with creditworthy entities, providing the subsidiary with a stable, predictable cash flow from which dividends can be paid. Shares in the subsidiary are sold to the public. The public shares pay dividends to the shareholders at attractive yields that are substantially lower than the return generally required by the equity investors in renewable energy projects. The lower yield acceptable to the YieldCo investor is justified because proven operating projects have eliminated some risks (such as cost overruns, construction risk, and operating risk). The YieldCo is able to view the operating results of the project portfolio before investing.
YieldCos have become attractive investments in cases in which the sponsor has a good development and operating record, which ensures that the dividend is secure. In the current economic environment, incremental yield shares of stock that pay yields well above the 10-year treasury rate are viewed as attractive. Furthermore, the dividends from a YieldCo qualify for lower tax rates relative to ordinary interest income, increasing their value to taxable investors. Still, there is concern that factors such as insufficient new investment opportunities, changes in tax law, difficulty renewing power purchase
agreements, or rising interest rates could decrease the value of YieldCos and thus their attractiveness to investors. Nonetheless, they warrant continued analysis given their potential to continue to lower the cost of capital for investments in increasingly clean electric power technologies.
Real Estate Investment Trusts
Real estate investment trusts (REITs) are another investment vehicle that could lower the costs of and increase access to capital for financing increasingly clean energy technologies. REITs resemble MLPs in three ways. First, REITs can be bought and sold on public exchanges, providing a conduit for capital from a large and diversified class of investors. Second, REITs provide investors with a stream of income generated from specific activities; they must pay at least 90 percent of their taxable income to shareholders through a dividend.8 Third, Congress created REITs as an exemption from the corporate income tax rules. Two additional key requirements for an REIT are that at least 75 percent of its total assets must be in real property or interests in real property,9 and at least 75 percent of its gross income must come from real-property activities or mortgages on real property.
The National Association of Real Estate Investment Trusts (NAREIT) estimates that there are approximately 1,100 REITs in the United States (NAREIT, n.d.-a). NAREIT also estimates that the number of publicly traded REITs has grown significantly over time, from 34 in 1971, with a market capitalization of roughly $1.5 billion, to 202 in 2013, valued at approximately $670 billion (NAREIT, n.d.-b). REITs therefore could provide a significant source of capital for financing the deployment of increasingly clean energy technologies, as long as those technologies meet the definition of real property or interests in real property. The authorizing statute defines interests in real property as including the ownership, co-ownership, or leasing of improvements on land, but does not define improvements. Instead, that determination is left to the Treasury Department, usually through private letter rulings (PLRs) from the Internal Revenue Service (IRS).
In June 2014, the IRS issued a PLR stating that photovoltaic (PV) modules are not an improvement because they are not inherently permanent and thus do not qualify to be part of an REIT, whereas the mounts and exit wires do qualify. PLRs, though, “are limited to their particular facts and may not be relied upon by taxpayers other than the taxpayer that received the ruling” (IRS, 2014); thus they may not be applicable to REITs other than the one that requested the ruling. Moreover, if PV modules were to be considered an improvement, they could also be at risk of no longer being eligible for other support mechanisms through
8 26 U.S.C. §856(c)(2)(A). REITs formed after January 1, 1980, must pay at least 95 percent of their income to shareholders as a dividend.
9 Or cash and cash items, or government bonds. Because investors expect income, though, REITs generally do not hold cash investments. 26 U.S.C. §856(c)(4)(A).
the tax code, such as the PTC or ITC. This situation has created a great deal of uncertainty regarding the eligibility of technologies such as solar and wind for REIT status. By contrast, IRS rulings have made clear that pipelines, including natural gas pipeline systems, are eligible for REIT status, exclusive of meters and compressors (IRS, 2014).
Finding 7-3: MLPs and similar tax and financing mechanisms, such as REITs, have a positive impact on lowering the cost of capital for energy projects.
Recommendation 7-2: The federal government should consider leveling the playing field by making proven financing mechanisms available to increasingly clean energy projects. One means to this end would be convening a roundtable of experts on increasingly clean energy financing to provide recommendations on new approaches for using federal financing programs to leverage and sustain capital investment in increasingly clean energy projects at all levels of the economy.
Enabling Financing Mechanisms
One critical challenge to financing increasingly clean electric power technologies is the often high up-front capital costs, even though the technologies may provide lower operating costs. Several mechanisms—such as on-bill repayment, energy service performance contracting, and property assessed clean energy (PACE) financing—could address this barrier to cost-effective projects. These mechanisms enable third-party financing so that electricity customers can finance projects that lower their energy use or shift them to greater use of distributed generation, and allow for the savings realized through those projects to pay for the projects over time. Some entity, however, still must provide the initial capital that will be repaid over time.
One such entity is known as a “green bank.” Green banks are in the planning or early deployment stage in a number of states. Essentially, a green bank blends public and private capital to fund the up-front cost of increasingly clean energy improvements. The intent is to spread the risk for either investor and to scale the market for projects. These entities can be housed within an existing state agency with administrative, rulemaking, and underwriting authority. Examples are found in New York and Connecticut. Green banks provide capital for development and implementation through a range of financing mechanisms, which include revolving loan funds, loan loss reserve pools, and commercial PACE (C-PACE) financing.
C-PACE is a financing mechanism used by local governments that allows commercial, industrial, and multifamily property owners to finance energy-efficiency and renewable energy improvements. The repayment of qualified energy improvements takes place through a voluntary property tax assessment, allowing local governments to finance the up-front costs of the improvements. Responsibility for repayment transfers to the next owner if the property is sold. Although many states have passed legislation enabling C-PACE, a lack of model legislation has led to states setting their own loan terms, qualifying retrofits, and target markets (PACE, n.d.).
The lack of standardization has prevented C-PACE from scaling to its potential within the private lending community. States continue to modify their existing C-PACE statutes accordingly. In the 2014 state legislative session alone, for example, C-PACE statutory changes were made in Maryland (HB 202), New Hampshire (HB 532), and Oregon (HB 4041), all of which had preexisting C-PACE legislation that needed to be modified. The lack of expertise and mature financial standardization remains a barrier to taking C-PACE to scale. Detailed, independent analysis of existing C-PACE and multifamily PACE policies would help determine whether statutory changes would enable programs to reach greater scale and operate more efficiently.
The federal government could support states’ efforts to overcome cost-of-capital barriers through green banks in a number of ways. DOE and the Treasury Department could undertake research to determine what role(s), if any, green banks could play. Depending on their findings, those departments could provide states with model legislation and regulations and key technical advice. Standardization of financial markets generally increases access and lowers costs. Thus, another possibility is to offer streamlined syndication assistance to help states design programs in ways that leverage private capital and low-cost financing mechanisms most effectively.
As detailed in 10 is that their price in the market has been higher, often significantly so, than that of conventional energy sources—a much more significant issue than the costs of capital associated with these technologies. As discussed in earlier chapters, a chief reason for this price differential is that the prices of conventional technologies do not reflect their full costs, particularly the “hidden” costs of pollution (externalities) (see also NRC, 2010b). As long as the first prices to purchasers for increasingly clean technologies remain high,
10 That is, once the technologies have matured to a technology readiness level of 8 or 9.
investors will continue to seek other investment opportunities. This barrier, in other words, does not stem directly from financing or from financial markets but from market imperfections in the electric power sector.
A chief way to alleviate this barrier is to implement policies that price the pollution caused by various technologies so that market participants will receive appropriate signals regarding their value. In simpler terms, this approach would bring the prices of increasingly clean technologies closer to, and even below, those of incumbent technologies. Market demand would pull from there, and investors would find investing in the deployment of increasingly clean electric power technologies more attractive, accelerating their market deployment.
Finding 7-4: Properly pricing pollution would cause market pull for increasingly clean energy technologies and attract more investors and investment capital to these technologies.
This finding aligns with and supports prior recommendations of the National Research Council (NRC, 2013c) and others that appropriate steps be taken to correct the market so it will give consumers appropriate price signals. It is important to bear in mind, though, that pollution prices would have their greatest impact on technologies that are technically developed enough to be ready for deployment. Pollution prices would have only small or modest effects on early-stage basic research and R&D.
One way to think about pollution pricing is as a very inexpensive insurance policy. Like any good insurance policy, it would diffuse risk to such a great number of people that costs borne by each person would be vanishingly small. The benefits, however, could be quite large. Focusing just on GHG emissions, the National Research Council committee that produced America’s Climate Choices (NRC, 2010c, p. 5) recommended that U.S. policy makers “adopt a mechanism for setting an economy-wide carbon-pricing system” as an important element of a comprehensive national mitigation program. According to that report, “most economists and policy analysts have concluded…that putting a price on CO2 emissions (that is, implementing a ‘carbon price’) that rises over time is the least costly path to significantly reduce emissions and the most efficient means to provide continuous incentives for innovation and for the long-term investments necessary to develop and deploy new low-carbon technologies and infrastructure” (NRC, 2011, p. 58). Further, “a carbon price designed to minimize costs could be imposed either as a comprehensive carbon tax with no loopholes or as a comprehensive cap-and-trade system that covers all major emissions sources” (p. 58).
This committee reconfirms those findings and the value of internalizing the cost of GHG emissions in the market price of fossil fuels. The committee takes no position on whether a carbon price would best be established as a tax or in a cap-and-trade regime; both approaches have advantages and disadvantages. A carbon tax is the most direct method for pricing carbon, but involves such
issues as how to adjust the tax over time and the point in the supply chain where the tax should be collected. More important, it neither defines nor guarantees a specific level of GHG reductions (Marron and Toder, 2014). A cap-and-trade system sets a specific limit on emissions but can entail greater administrative complexity and cost. In addition, past cap-and-trade proposals in Congress, as well as the experience of the European Union’s trading system, have demonstrated the tendency for lawmakers to include numerous concessions to stakeholders, which can reduce the effectiveness and transparency of the trading regime. An analysis of California’s carbon market suggests that state-level trading schemes may have similar tendencies (Cullenward, 2014).
Both approaches lead to secondary policy issues, including how to estimate the full costs of GHG emissions to society and how to allocate the revenues from carbon pricing. Past proposals on revenue allocation have included deficit reduction, clean energy R&D, climate change mitigation and adaptation measures, and compensatory decreases in corporate or personal income taxes (or increases in public assistance to low-income families that do not pay taxes) to mitigate the impact of energy price increases. The great need for expanded technology options to address the climate and other problems due to pollution suggests that any future revenues generated by carbon pricing would be well invested in the research, development, and commercialization of increasingly clean energy resources and technologies, in measures to reduce any adverse and regressive impacts on energy prices, and in efforts to mitigate and adapt to the impacts of climate change. While recognizing the importance of deciding how to use any future revenues from pollution pricing, the committee notes that an analysis of revenue recycling is beyond the scope of this study. The committee notes further that future deliberations regarding a national carbon pricing policy would benefit greatly from assessing the experience of the two regional cap-and-trade systems that have emerged in the United States.11
In addressing the issue of carbon pricing, the committee was keenly aware of the political divide involved. Simply stated, pricing of carbon emissions on a national basis is unlikely to be quickly embraced or easily implemented. With that said, the committee believes it is necessary and appropriate to acknowledge what other committees of the National Academies have concluded as to the benefits of pricing carbon emissions, concurring that no other policy could be more important and no other may be more necessary to meet the daunting challenge facing the United States and the world.
11 Nine northeastern states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island, and Vermont) participate in the Regional Greenhouse Gas Initiative, an emissions trading program. California launched its own emissions trading program in January 2013 and created a partnership with the Canadian Province of Quebec a year later, which is managed by the Western Climate Initiative. In 2013, the performance of both systems exceeded that of trading regimes in other countries.
Although Congress ultimately did not adopt cap-and-trade legislation in 2009, leading to a period in which global climate change ranked low on the national agenda, public discussion of market-based approaches appears to be intensifying as a result of the Environmental Protection Agency’s proposed regulation of carbon pollution from power plants, increasingly definitive climate science, extreme weather events, and encouragement from several prominent experts from both political parties to establish a price on carbon. The committee finds that the analysis contained in America’s Climate Choices (NRC, 2011) remains relevant and an important reference for a renewed national conversation about the most efficient ways to address climate change and to spur innovation in increasingly clean energy technologies.