Addressing the Unique Challenges to the Development and Deployment of Nuclear Power, Carbon Capture and Storage, and Renewable Fuel Power Technologies
To avoid the most harmful effects of rising greenhouse gas (GHG) emissions and criteria air pollutants while also meeting the growing demand for affordable, reliable, and secure energy supplies, the world must embark on a rapid transition to cleaner, low-carbon energy systems. Unfortunately, the current portfolio of cleaner power generation technologies is generally not price-competitive with established technologies such as natural gas- and coal-fired power plants, in part because pollution externalities are not fully incorporated into energy prices, limiting the incentives for the deployment of clean energy technologies (see EIA, 2016c). The historically low prices for natural gas in the United States are usually cited as the primary reason for this trend, although the cost of constructing a plant still is often lower than is the case for any other generation technology. Innovation in zero- and low-pollution technologies will require an expansive and integrated approach to established, emerging, and new technologies for electricity production, transmission, distribution, and storage. This chapter addresses several major electricity generation technologies with significant potential for dealing with the pollution problem, including carbon dioxide (CO2) emissions. These technologies include nuclear power, carbon capture and storage (CCS), and renewables. Each has specific characteristics and poses unique challenges for innovation and eventual deployment. The chapter examines these challenges and potential means for overcoming them.
Unique Challenges to Innovation and Deployment for Nuclear Power Technologies
In the United States today, nuclear power provides about 20 percent of total electricity and accounts for almost two-thirds of the nation’s low-carbon electricity generation, despite recent increases in the deployment of solar and wind power. In spite of its advantages, however, nuclear power faces formidable obstacles that are limiting its use in the United States.
New technologies might help to overcome these obstacles. Moving nuclear technologies forward, however, will require addressing several critical issues, including technical barriers, capital requirements, the regulatory framework, the market for nuclear plants, and risk management. Given the role nuclear power is already playing as a major source of low-carbon electricity generation and the potential for advanced nuclear technologies to expand this role in the future, the committee believes that serious consideration of improving the environment for nuclear innovation is warranted, and offers recommendations in this section as a means to that end.
Nuclear energy also is facing stiff headwinds elsewhere in the world. Rising costs and public concerns over nuclear safety have led some nations to scale back their nuclear growth plans, while others have retreated from nuclear power entirely. In some countries—most notably China, India, Russia, South Korea, and some Middle Eastern countries—there are ambitious plans for nuclear expansion. Several other countries are embarking on nuclear power programs for the first time, and still others are seriously considering doing so. But when all these national plans are combined with the expected retirement of much of the existing nuclear fleet as those plants reach the end of their life, the nuclear role in global carbon mitigation appears likely to grow only slowly in the coming decades and may even shrink (EIA, 2014a). In parallel with these developments, the center of gravity of the global light water reactor-based nuclear energy industry is continuing to shift away from the United States, as suppliers in Russia, Korea, and China gain competitiveness in international markets previously dominated by American, European, and Japanese vendors. As its global presence in nuclear energy diminishes, the United States is less likely to be able to shape the governance institutions needed for safe nuclear operations worldwide, and will also be less able to strengthen the security arrangements with respect to nuclear power and its fuel cycle that are key to achieving nonproliferation goals. For all these reasons, it is important as well to consider the potential role of nuclear innovation in an international context.
Domestic Outlook for Nuclear Energy
Most of the nation’s 100 currently operating nuclear power reactors, now largely amortized after having operated for 30 years or more, are supplying competitive, low-cost electricity to the grid. The nuclear fleet also has been directly responsible for the avoidance of both the thousands of premature fatalities and the adverse environmental impacts that would have occurred had the electricity they supplied been generated by fossil fuel power plants instead. However, most currently operating nuclear plants in the United States are expected to be retired between 2030 and 2050, and some will be shut down well before then. Four new reactors are under construction—the first new nuclear builds in decades—and a fifth is now being completed after a long delay. Aside from these five plants, however, there are no firm plans to build any more nuclear power plants in the United States to replace the existing nuclear fleet with new nuclear capacity, and the nation has no strategy for sustaining, let alone expanding, nuclear energy generation.
Five operating reactors have recently closed or will soon do so. Other as yet unannounced retirements may also occur in the next few years. Single-unit plants with relatively high operating and maintenance costs in locations with low wholesale electricity prices and unregulated power markets are most likely to be affected. Continuing uncertainties over the ultimate cost of addressing safety issues raised by the Fukushima accident, as well as the operational impacts of Fukushima-related issues, also may accelerate the retirement schedule of certain plants over the next few years. In its most recent projection, the Department of Energy (DOE) estimates that another 6 gigawatts (GW) of nuclear capacity will be retired before the end of the decade, leaving 98 GW of nuclear capacity in service in 2020, slightly less than the current capacity (EIA, 2014a).
Beyond 2020, the outlook is less certain. More than 70 percent of currently operating reactors have received approval from the U.S. Nuclear Regulatory Commission (U.S. NRC) to continue operating for an extra 20 years beyond the expiration of their original 40-year operating licenses (EIA, 2014a, pp. IF-35). Some are considering applying for a second 20-year operating license extension.
The principal reasons for both early plant retirements and the lack of new nuclear ordering are economic. With natural gas prices at today’s low levels, new nuclear plants and even some existing reactors cannot compete with gas-fired combined-cycle plants. The very high initial capital cost and the uncertainties associated with that cost are additional deterrents to new builds. Other factors that discourage utilities from considering new nuclear plant investments include the uncertain outlook for carbon pricing and for the inclusion of nuclear energy in state and federal low-carbon portfolio standards, as well as the continuing uncertainty over the government’s plans to manage the spent fuel from nuclear power plants.
According to DOE’s “reference” projection, only an additional 4 GW of nuclear capacity will be added between 2020 and 2040. DOE expects there will be no further retirements of nuclear plants during this period, so the nuclear capacity in service in 2040 will remain little changed from today. The assumptions underlying this projection are that annual operating and maintenance costs for nuclear units will remain flat throughout this period (in recent years they have been increasing at about 4 percent per year), and that all of the plants reaching 60 years of life during this period—representing roughly 50 GW of capacity—will apply for and be granted a second 20-year operating license extension.
These assumptions may well be optimistic. The regulatory framework for a second license extension is the same as that for a first extension, although the technical issues around aging are still being fully addressed (NEI, 2015). Operators still will need to assess individual plant safety and economics in determining whether to apply for a second license renewal. It therefore appears plausible that the existing nuclear fleet will shrink during this period rather than remain at its present size (EIA, 2014a).1
Since U.S. electricity consumption is projected to grow by 20 percent by 2040, the Energy Information Administration (EIA) estimates that the nuclear share of output will fall to about 17 percent of the total in the reference case, with fossil energy (principally coal and gas) still accounting for 66 percent of all generation at that time. DOE’s projections, though, are for far less decarbonization of the electricity system than would be required to achieve an 80 percent reduction in overall U.S. carbon emissions by 2050, as is called for by the United Nations (UN) agreements. According to a recent report of the Deep Decarbonization Pathways Project, a collaborative global initiative to explore how individual countries can reduce their GHG emissions, achieving the 80 percent mitigation target by 2050 would require almost complete decarbonization of the U.S. electricity sector, together with switching a large share of end uses from direct combustion of fossil fuels to electricity or fuels produced from electricity (Williams et al., 2014). Electricity generation would need to approximately double by 2050, while the carbon intensity of the power sector would have to decline to 3-10 percent of its current level.
The Deep Decarbonization analysis shows how this could be achieved through aggressive additions of solar, wind, nuclear, and CCS capacity in various combinations, together with a rapid acceleration in the rate of energy-efficiency gains (Williams et al., 2014, Figure 7 and Table 7). Of the four scenarios studied in that report—high renewables; high nuclear; high CCS; and
1The Energy Information Administration’s (EIA) (2014a) Annual Energy Outlook also includes an “Accelerated Nuclear Retirement” scenario, which assumes that operating and maintenance costs for nuclear power plants grow by 3 percent per year through 2040, and that all nuclear power plants not retired for economic reasons are retired after 60 years of operation. In this scenario, 42 gigawatts-electric (GWe) of nuclear capacity is retired by 2040 (see Jones and Leff, 2014).
a mixed case involving a balanced mix of renewables, nuclear, and natural gas with CCS in the electricity sector—the high nuclear scenario is associated with the lowest incremental cost relative to the business-as-usual case (Williams et al., 2014, p. 24).
International Outlook for Nuclear Energy
In other parts of the world, as noted above, the outlook for nuclear energy is mixed. Rising costs and public concerns over safety have led some nations to scale back their nuclear expansion plans, while others are phasing out their programs completely. But in still other countries there are ambitious plans for nuclear expansion, and some growth in the global nuclear sector overall is anticipated in the coming decades.
Today 444 reactors (388 GW) in 31 countries are providing more than 11 percent of the world’s electricity (NEI, 2016). About 77 percent of this capacity is in OECD countries, but most new nuclear capacity is being built in non-OECD countries. Sixty-three reactors (62 GW) are currently under construction (NEI, 2016), the highest total in 25 years (WNA, 2015). Almost two-thirds of the new capacity is in China, Russia, India, and South Korea, with China alone accounting for more than 33 percent of the total. Another 509 reactors (372 GW) are on order or in the planning stages, with 60 percent of this capacity again in China, Russia, India, and South Korea (and with China alone accounting for more than one-third of it). Several newcomer countries are in the early stages of implementing nuclear power programs or are seriously considering doing so, including the United Arab Emirates, Turkey, Bangladesh, Vietnam, Jordan, Lithuania, and Saudi Arabia.
On the other hand, since the Fukushima accident, several countries, including Germany, Italy, Switzerland, and Spain, have decided to phase out their nuclear programs. Japan itself, which before Fukushima had the world’s third-largest nuclear power program and was planning additional nuclear plant construction on a large scale, may also decide to phase out its reactors, all of which were shut down following the accident. Several other countries that previously were considering entering the nuclear field have decided not to do so. As in the United States, moreover, a large wave of nuclear plant retirements is likely to occur around the world before 2050. The average age of the world’s nuclear power plant fleet is almost 30 years (IAEA, 2016, Figure 7), and the International Energy Agency (IEA) projects that almost 200 reactors will be retired before 2040 (IEA, 2014).
Overall, the outlook is for moderate growth in the global nuclear energy sector. In its “New Policies” scenario, the IEA projects an increase of 60 percent in world nuclear generating capacity to 624 GW by 2040, with the share of nuclear power in global electricity generation increasing slightly to 12 percent at that time (IEA, 2014). The EIA projects an almost 90 percent increase in world nuclear capacity over the same period, and a slightly higher nuclear share of
14 percent in 2040 (EIA, 2013c). As in the United States, however, the net nuclear contribution globally, after taking account of current plans for both new construction and plant retirements, falls far short of what appears likely to be required if the world is to stay within the limit on average temperature rise of 2° C over the preindustrial equilibrium (IEA, 2014).2
Prospects and Obstacles for Innovation in Nuclear Power
The gap between current plans and the possible need for significant nuclear power growth in the future thus is wide, both in the United States and internationally. A continuation of current policies and approaches is unlikely to be sufficient to close this gap. Although plants built today are much safer than those from 40 years ago when the first reactors at Fukushima were built, nuclear energy is likely to require additional safety improvements, lower costs, and a better economic case, as well as more stringent and reliable security against the threats of nuclear proliferation and terrorism. Also, to compete effectively with incumbent, high-carbon technologies and fuels as well as new low-carbon alternatives, nuclear power will have to be adapted to the evolving characteristics of electric power grids, new ways of delivering electricity services, and the diverse needs of generators in advanced and developing countries.
Improvements in nuclear management and governance will be essential to achieving safe and secure nuclear operations and addressing public concerns about nuclear safety. But technological innovations in nuclear power plants and the nuclear fuel cycle may also be necessary to realize the potential of nuclear energy. Innovators seeking to commercialize new nuclear technologies in the United States face formidable obstacles, however. Long lead times, the high costs of development and demonstration, and the lack of a clear regulatory framework are all deterrents to private investment in new nuclear technology development. Government support for nuclear innovation, which played a decisive role in the early years of the nuclear energy industry, has been far more limited in recent years and has been criticized for its lack of direction. The current absence of a regulatory framework is especially problematic for private nuclear reactor developers, some of whom are reportedly planning to build their first full-scale reactors overseas because they think doing so in the United States will be impossible under the existing regulatory regime.
Commercializing nuclear-related innovations is an expensive, lengthy, and risky process. Even incremental improvements to existing nuclear technologies can take many years to develop, and if more far-reaching innovations are to be available commercially when age-related attrition of the existing nuclear fleet begins in earnest in the 2030s, large-scale development will need to begin now and be sustained throughout this period. The necessary level of public and
private investment will be substantial, and will require an effective partnership between the federal government and the nuclear industry.
Despite these obstacles, a growing number of groups in the U.S. industry, the national laboratories, and universities have launched efforts to develop more advanced nuclear power reactor and fuel-cycle technologies. These technical developments are intended variously to reduce economic costs and financial risks, enhance safety, facilitate nuclear waste management, and lessen the risks of nuclear proliferation. These initiatives range from incremental improvements in current light water reactor technologies to the development of alternative reactor systems with different types of fuel and coolant and different approaches to siting, construction, operation, and waste management, including sodium-cooled, gas-cooled, and molten salt-cooled reactors (see, e.g., Buongiorno et al., 2015; Forsberg et al., 2014; Hejzlar, 2013; Nathan, 2013; NuScale Power, 2013; Rawls et al., 2014). Several other countries also are developing advanced nuclear technologies (see, e.g., Chen, 2012; Kim et al., 2014; IAEA, n.d.; Sun, 2013). The output capacity of some of these designs is in the 1,000 megawatt (MW) range, similar to that of large conventional light water reactors, but others are more compact, in some cases ranging below 50 MW in size. Many are small, modular designs and would be constructed primarily in factories rather than in the field, as now. Most rely to a greater extent than conventional light water reactors on passive mechanisms to ensure safety, and some concepts approach the limit of “walkaway” safety, in which no external intervention by either operators or active engineered systems would be necessary for safe shutdown. Some of these designs are optimized to minimize waste production or to burn nuclear waste from other reactors. Others, by offering the capability for rapid and efficient load following, would be well suited to grids with large amounts of intermittent solar and wind power generation.
Views vary as to the economic feasibility of these new technologies and the lead times required for their commercialization. Their developers believe they have the potential to provide large amounts of low-carbon electricity safely and economically; others are more skeptical. But all would probably agree that there is at present no clear pathway to determining the commercial viability of these advanced systems.
Commercializing a new reactor technology would likely cost billions of dollars, and given the formidable financial risks involved, it is not credible that such an effort could be undertaken in the absence of public risk and cost sharing. DOE is carrying out early-stage research, mainly at its national laboratories, on a fairly broad range of reactor technologies. With one exception, however, it is not currently providing support for the downstream stages of the innovation process, and it has no plans at present to build prototypes of advanced reactors.3 (The
3 Until recently, DOE planned to build a prototype high-temperature gas-cooled reactor, the so-called Next Generation Nuclear Plant Project (NGNP), as is called for in the Energy Policy Act of 2005. DOE recently announced its intention not to proceed with Phase 2 design activities for this project (see GAO, 2014).
exception is DOE’s Small Modular Reactor [SMR] Licensing Technical Support Program. Under this nearly $500 million program, DOE is seeking to accelerate the commercialization of two small modular light water reactor systems by supporting the certification and licensing of these designs.4) Advanced reactor designs also are hampered by the paucity of suitable national facilities that can conduct tests at the high temperatures and high neutron flux densities that are required for many new designs.
The current nuclear plant licensing framework, administered primarily by U.S. NRC, is tailored to light water reactor technology. It has developed over many decades, and it is generally regarded around the world as providing a strong environment for licensing of established light water reactor power plant designs. It is less well suited to the task of licensing more advanced concepts. Even for small modular light water reactor designs, the cost to their private developers of navigating the regulatory process has been estimated at several hundred million dollars, and as noted above, DOE has provided complementary funds to help support such efforts. (Previously, DOE provided support for licensing of the AP600 and AP1000 pressurized light water reactor designs developed by Westinghouse.) For innovators developing non-light water reactor technologies, the regulatory hurdles are greater. For these technologies, there is no clear regulatory pathway at present in the United States, and the cost and time required to develop this pathway will be substantial.
Some experts, including many at U.S. NRC, believe that existing regulatory procedures, standards, and criteria could be applied to the new designs with relatively modest changes. Others argue that attempts to apply the current regulatory framework to reactor systems with fundamentally different design and safety features are unlikely to succeed, and that new frameworks will be needed to treat these differences effectively.
U.S. NRC has recently been considering a different regulatory approach that would place more emphasis on risk- and performance-based standards. In principle, this approach could lead to a so-called technology-neutral licensing framework for advanced reactors (U.S. NRC, 2007, 2012). Some developers, however, eager to move forward with their projects and anxious about the prospect of a lengthy, broad-based rulemaking for a generic licensing approach, may see an advantage in the development of regulatory standards and criteria specifically for their technologies.
A related issue concerns the procedures to be followed for advanced reactor licensing. Currently, U.S. NRC follows a one-step procedure in which the developer must make large investments in the technology before the design can be certified. The presumption underlying this approach is that once a design has been certified, a large number of identical reactors will be built based on the
4 One of the two companies participating in this program has substantially reduced its funding for SMR development and extended the project timeline into the early 2020s (see Nuclear Engineering International, 2014).
original license. While this is a sensible approach for licensing incremental advances in existing light water reactor technology, it is more likely that the designs for non-light water reactor technologies will evolve rapidly in the early stages of technology adoption as new information is generated by construction and operating experience. A one-step design certification framework would appear to be inconsistent with such a trajectory. Moreover, a regulatory approach that would require investors to commit billions of dollars in “all-or-nothing” funding for essentially the entire cycle of development, design, and commercial design optimization without a safety ruling from U.S. NRC would be a strong deterrent to privately financed efforts to commercialize advanced reactors.
An alternative approach, somewhat similar to the way in which the Food and Drug Administration (FDA) licenses new drugs today, would involve a staged licensing process,5 in which U.S. NRC would conduct a series of interim safety reviews and issue limited licensing decisions bearing on each successive stage of the development cycle, including pilot-scale prototype and full-scale precommercial demonstration projects, gathering additional information at each stage. The early regulatory feedback would reduce the financial risks to private developers by providing clear signals as to whether the new technology was likely to be able to meet final regulatory criteria, and would allow design changes to be made earlier in the development cycle when they would be less expensive in terms of both time and money.
At present, neither the technical nor the procedural aspects of U.S. NRC’s approach to advanced reactor regulation are known. Over the years, U.S. NRC staff have identified a number of specific technical and policy issues that would be associated with the licensing of advanced reactors,6 and in 2012 the agency produced a report requested by Congress addressing its overall strategy for preparing for the licensing of advanced non-light water reactors (U.S. NRC, 2012). But much about U.S. NRC’s approach remains uncertain, as the committee observed during its fact-finding activities. This uncertainty has already led some developers to decide to move some of their development activities outside the United States, even though a U.S. NRC license would
5 The FDA’s process follows, roughly, three stages. Stage one involves data from laboratory and other controlled-environment testing, such as animal testing. This stage would be analogous to simulations and laboratory testing for nuclear technologies. Stage two involves clinical trials. This stage would be analogous to test bed testing and demonstration projects. Step three is the actual application to the FDA, when the applicant summarizes the outcomes from stages one and two and formally requests FDA review. The FDA then conducts a preliminary review of the outcomes to determine whether a full review is warranted. If so, the FDA conducts a full review (see http://www.fda.gov/Drugs/DevelopmentApprovalProcess/HowDrugsareDevelopedandApproved/ApprovalApplications/InvestigationalNewDrugINDApplication/default.htm).
6 For U.S. NRC papers, memoranda, and other documents, see http://www.nrc.gov/reactors/new-reactors/regs-guides-comm/related-documents.html.
likely provide some commercial benefit in international markets (Behr, 2011). Other developers may follow suit. There are concerns that U.S. NRC may have neither the experience nor the resources to undertake this new and unfamiliar task in a timely way. Additional resources and a clear mandate, perhaps provided by Congress, may be needed to ensure timely action to establish a predictable, well-defined licensing process for advanced reactors in the United States.7
Other energy regulations may reinforce the disincentives for investment in nuclear innovation. Examples include the absence of a carbon price and the existence in many states of standards designed to promote the adoption of a portfolio of low-carbon technologies from which nuclear technologies have specifically been excluded. Another major obstacle is the structural underinvestment in innovation of all kinds by U.S. utilities (see Chapter 3). In addition, given widespread expectations of a prolonged period of ample natural gas supplies at relatively low prices, most electric power companies currently have little interest in developing and deploying alternative technologies for central station baseload generation. The disincentives for such investments have been reinforced in parts of the country where expanding wind and solar supplies are driving wholesale power prices down to low or even negative levels at times of high wind and solar output. Elsewhere, in states where vertically integrated utilities are still subject to traditional cost-of-service regulation, regulators often are reluctant to allow utilities to pass technology risk on to ratepayers even if there is a realistic prospect for a long-term reduction in costs.
A third obstacle that uniquely deters nuclear innovation in the United States is the continued lack of progress in resolving the spent fuel management issue. The absence of an agreed-upon national policy and plan for interim storage and final disposal of spent fuel is a major impediment to private investment in the development of advanced nuclear power plant technologies.8
All the technologies referred to above involve the fissioning of heavy atoms to release energy. The technology of controlled thermonuclear fusion, in which energy is released during the fusing of light atoms, is very different, and no functional fusion power reactor has yet been built despite many decades of R&D and the investment of billions of dollars. In magnetic confinement fusion, one of the two main approaches to achieving fusion, low-density deuterium and tritium fuel is heated to 100 million degrees while remaining contained for long enough by a powerful magnetic field for the fuel to react. In inertial confinement
7 At the time of this writing (2016), bills had been introduced in the U.S. Senate (S.2795) and the House (HR4979) that recognize the need to update the nuclear licensing regulatory framework.
8 For example, California law prohibits construction of any new nuclear power facilities until the California Energy Commission has determined that the federal government has identified and approved a demonstrated technology for either (1) the construction and operation of nuclear fuel rod reprocessing plants, or (2) the permanent disposal of high-level nuclear waste (1976 Cal. Stats., Ch. 196, § 1).
fusion, intense lasers or particle beams are used to compress and heat up a small frozen pellet of deuterium and tritium fuel (the “target”), yielding a microburst of energy (NRC, 2013a).
Significant advances have been achieved in both magnetic and inertial confinement fusion, but neither approach has yet demonstrated that it can produce more power than must be provided for operation. Progress has been slower than expected, and it remains to be seen whether a cost-effective, power-producing reactor can be developed. Nevertheless, the promise of fusion is so great that continued work is considered worthwhile. Sufficient fusion fuel exists to supply the entire world’s energy needs for millions of years. Furthermore, fusion power plants produce no GHGs and, if appropriately designed, little or no long-lived radioactive waste. However, achieving fusion at the scale needed for energy generation at a competitive cost is a formidable challenge, and the large and costly facilities needed to demonstrate its feasibility are so expensive that international collaboration is and will remain necessary.
Findings and Recommendations on Promoting Innovation and Deployment for Nuclear Power Technologies
A number of actions could be undertaken in the United States to create a more amenable environment for innovation in nuclear power technologies. These actions include reforming the regulatory and licensing framework; providing better support for demonstration projects; improving and expanding international cooperation for testing, demonstration, and deployment; enacting legislation to address spent fuel concerns; developing new mechanisms for addressing the funding gap for demonstration and adoption of low-carbon energy technologies; and reorienting the U.S. fusion program.
Finding 5-1: The current U.S. nuclear regulatory system has evolved for the purpose of licensing mature light water reactor power plant technology, but U.S. NRC will likely need to develop new regulatory approaches to address the needs of advanced, non-light water reactors.
Recommendation 5-1: U.S. NRC, on an accelerated basis, should prepare for a rulemaking on the licensing of advanced nuclear reactors that would establish (1) a risk-informed regulatory pathway for considering advanced non-light water reactor technologies, and (2) a staged licensing process, with clear milestones and increasing levels of review at each stage, from conceptual design to full-scale commercial deployment.
To implement this recommendation, U.S. NRC might accelerate its efforts to allow for consideration of advanced technologies based on risk- and performance-informed criteria rather than technology-specific prescriptive specifications. A staged licensing process for advanced technologies might provide interim reviews at each stage, from conceptual design, through precommercial pilot and full-scale demonstration facilities, to commercial deployment. Finally, U.S. NRC might consider stationing a small team of highly capable U.S. NRC experts, tasked with developing safety requirements for new kinds of reactors in cooperation with nuclear developers from the private sector, at an advanced research and test facility dedicated to that task. There they would work collaboratively with developers to learn about facility construction and operations and build the expertise needed for commercial licensing.
Finding 5-2: Pilot- or full-scale nuclear reactor demonstration projects are likely to cost hundreds of millions of dollars or more.
Much of this cost is not for the reactor itself but for the associated site costs, power block, and other infrastructure. A flexible, “plug and play” platform for qualified nuclear innovators could significantly reduce the cost of demonstrations. By providing sites for such facilities and by working with interested state governments to enable public financing assistance for demonstration projects, the federal government would encourage the emergence of new development consortia of nuclear innovators, prospective owner-operators, and financiers. As elaborated in Chapter 3, a national test bed would help innovators find partners and resources for effective testing of advanced technologies. Given the scale of capital required and the technological complexity of next-generation nuclear technologies, a dedicated facility capable of supporting private-party initiatives to test and demonstrate innovative nuclear technologies would be of particular benefit. Thus, a dedicated nuclear test bed would be a key component of the Technology Test Bed and Simulation Network proposed in Chapter 3.
The test bed site would be capable of hosting a broad range of advanced nuclear technology test and demonstration facilities. It would offer power and water supplies; postirradiation examination facilities for studying fuels and other materials; fuel transportation and storage facilities; security infrastructure; and comprehensive site characterization services, including environmental and seismic information. The fee structure for site services would be clearly specified in advance. These facilities and services would be available to both domestic and international nuclear development consortia.9 Responsibility for
9 At the time of this writing (2016), Idaho National Laboratory (INL) had test facilities, including a test reactor. This reactor, though, is a traditional light water design. INL’s facilities are available for free following a peer-review approval of research proposals. Also at the time of this writing, DOE’s Nuclear Energy Advisory Committee was nearing
safety oversight of the site would be shared between DOE and U.S. NRC. U.S. NRC would be responsible for facility licensing of prototype and demonstration advanced reactors as required by the staged licensing review process described previously.
Breaking the congressional deadlock on spent fuel management is essential to making progress on this issue. An especially important step to signal progress is to authorize away-from-reactor storage for spent fuel. The federal government should move to implement the recommendations of the Blue Ribbon Commission on America’s Nuclear Future, which lay out a comprehensive and practical approach to nuclear waste management.
Finding 5-3: The development of advanced nuclear technologies is very costly. Other countries also are working on such technologies and may provide a more hospitable environment for their development and deployment.
Recommendation 5-2: While the U.S. government should be cognizant of the importance to its environmental, economic, security, and climate policy goals of maintaining a healthy environment for nuclear innovation domestically, it should also support and encourage expanded international cooperation in testing, demonstration, and commercial deployment of advanced nuclear technologies.
Some private U.S. nuclear developers will look overseas to carry out or participate in testing, demonstration, and scale-up projects. The federal government should provide support for these efforts by enabling related contributions by U.S. national laboratories, universities, and regulatory organizations. This may also require a review and rationalization of U.S. nuclear export controls consistent with national security goals and policies on nuclear nonproliferation. Given the long lead time, large expense, and high regulatory and market risks of developing and demonstrating advanced nuclear technologies, it is unlikely that private companies will pursue these activities successfully without complementary public investments.
Financing and managing the demonstration and early-adoption stages of the innovation process for large-scale energy technologies, including nuclear, is a continuing challenge. There is a mismatch between interests and capabilities. As detailed in Chapter 3, venture equity investors are structured to finance technology development but not major project assets. Project investors are structured to finance large assets but not to take on the risk of technology scale--
completion of a report on an advanced test and/or demonstration reactor that would inform DOE’s Office of Nuclear Energy. The final report was expected in April 2016.
up. Buyers of power, such as utilities, are regulated to keep short-term costs down, but the cost of electricity generated by demonstration and “first few” projects will often be higher than that of electricity generated by the incumbent technologies, and this cost gap may persist for some time. The federal government has stepped in to help fill the gap in the past, sometimes with private-sector cost sharing, but many of these attempts have failed, and troubled projects have been common. New public funding mechanisms are needed that would also draw on private capital while avoiding dependence on the annual congressional appropriations process. One possibility is to build on existing state-level public benefit charges instead of creating a new funding mechanism, perhaps with an added incentive from a federally mandated innovation surcharge on either electricity sales or transmission. This type of approach would create a financing pool that could incentivize the formation of regional public/private energy innovation and deployment partnerships. One such approach would entail the establishment of Regional Innovation Demonstration Funds, as described in Chapter 3.
Lastly, the potential benefits of both magnetic and inertial confinement fusion are great, and significant technical advances continue to be made, even though progress has been slower than expected, and commercialization remains a distant prospect. Nonetheless, the tremendous potential benefits of fusion power warrant considering the adoption of a flexible U.S. investment strategy for fusion R&D that would incorporate a sensible balance between domestic and international collaborations as part of an overall program of strong support for the development of cleaner long-term energy options. A recent and laudable effort at expanding possible avenues for fusion development comes from an Advanced Research Projects Agency-Energy (ARPA-E) program designed to “create and demonstrate tools to aid in the development of new, lower-cost pathways to fusion power and to enable more rapid progress in fusion research and development.”10 Still, given the long timeline and large expenditures likely necessary to create a commercially viable system, it is important to give careful consideration to positioning the U.S. fusion R&D program appropriately relative to other long-term energy options, while balancing the multiple competing demands within research programs against the limited resources available to them and also retaining sufficient flexibility to adapt to new discoveries and opportunities.
10 For an Accelerating Low-Cost Plasma Heating and Assembly (ALPHA) program overview, see http://arpa-e.energy.gov/sites/default/files/documents/files/ALPHA_ProgramOverview.pdf.
The timing and scale of the energy and environmental challenges described throughout this report necessitate the use of a portfolio approach to achieve an increasingly clean energy sector. Given the likely role of fossil fuels in the future electric power generation mix for years to come and the dramatic reductions in GHGs that can be realized through CCS technologies, moving these technologies for both coal and natural gas generators through the development, demonstration, and deployment stages remains critical. This section examines the role CCS could play in the future global power generation sector; the status of CCS power-sector projects around the world; the range of market and nonmarket barriers to CCS; and discrete, implementable actions the federal government can take to support CCS technology development and deployment.
The Role of Carbon Capture and Storage in the Future Global Electricity Portfolio
The development of CCS technologies for fossil fuel-based electricity generating stations through research, successful technology demonstration, and eventual deployment at scale is an important component of an overall strategy for achieving an increasingly clean energy sector. To a large extent, the importance of CCS is driven by the sheer magnitude of available quantities of fossil fuels across the globe and their associated low prices. Prices for fossil fuels are currently very low. In February 2016, the average price of coal per million BTUs (MMBtu) delivered to the electric power sector was $2.17. While average delivered prices of natural gas have fluctuated, the recent price of $2.33 per MMBtu is near historical lows (the average 2008 price, by comparison, was $12.40 per MMBtu) (EIA, 2016e; FERC, n.d.).11 When production profiles of power generation technologies are considered, the levelized cost of electricity (LCOE) also shows the current cost advantage of fossil fuel-based generation. EIA estimates the LCOE for an advanced carbon-emitting gas plant entering service in 2022 to be more than 70 percent lower on a dollar per megawatt hour (MWh) basis than that for a pollution-free solar photovoltaic (PV) plant, and approximately 43 percent less than the cost for an offshore wind plant (EIA, 2015f), (2016g). (See Chapter 2 and Appendix B for more detail on estimates of the LCOEs for various technologies.)
Thus, EIA, IEA, and private-sector reference forecasts for energy use all project fossil fuel-based energy (i.e., coal, natural gas, and petroleum) to make up approximately 60-70 percent of energy inputs for power generation between
11 EIA Form EIA-923, “Power Plant Operations Report,” and predecessor form(s), including Form EIA-423, “Monthly Cost and Quality of Fuels for Electric Plants Report.”
2035 and 2040—a figure that is relatively consistent with current levels of use. 12 Additionally, even under more optimistic scenarios that assume successful commitments to and plans for reducing emissions, such as IEA’s “New Policies” scenario, fossil fuel generation still provides the majority of all electricity capacity (53 percent) in 2035.13 Therefore, not only is “legacy” power generation fossil fuel-based, but recent and anticipated capacity additions globally have been and will continue to be dominated by fossil fuels under a wide range of future scenarios. In fact, given the variability and intermittency of most renewable sources of power, fossil fuel plants are likely to continue to be used to compensate for the fluctuations in wind and solar generation (Oates and Jaramillo, 2013; Valentino et al., 2012).
Finding 5-4: Fossil fuels will remain a large and important component of the fuel mix for electricity generation in the United States and around the world for many decades to come.
There is general consensus that, to avoid the most dangerous and costly effects of climate change, the global average surface temperature increase should be limited to a maximum of 2° C over the preindustrial equilibrium (UN, 2015). This increase corresponds to an atmospheric concentration of GHGs of approximately 450 parts per million (ppm) or less, on a CO2-equivalent basis (IPCC, 2014b). However, because most GHGs, unlike conventional pollutants, remain in the atmosphere for generations, climate stabilization at any given temperature will require global aggregate CO2 emissions to fall at a rate far below that at which natural processes can remove them from the atmosphere. The long residence time and global dispersion of CO2 emissions in the atmosphere, in particular, make this reduction exceptionally challenging, and global emissions will need to fall to a small fraction of their current level by the end of the century to limit global average temperature increases to the 2° C level (IPCC, 2007). Because fossil fuels will be such a large and important energy source for many years to come, mitigating CO2 emissions will require decarbonizing fossil fuel-based electric power generation.
12 EIA’s Annual Energy Outlook 2014 “Reference Case” projection anticipates that 68 percent of total U.S. electricity generation in 2040 will be supplied from coal, natural gas, and petroleum. This is virtually identical to the percentage supplied from coal, natural gas, and petroleum in 2012 (calculated from EIA [2014a, Table A8, p. A-18]). IEA’s World Energy Outlook 2012 “Current Policies” scenario anticipates that fossil fuels will supply 66 percent of global electricity generation in 2035 (calculated from IEA [2012, Table 6.2, p. 182]). BP’s Energy Outlook 2035 projects that fossil fuels will make up more than 60 percent of primary energy inputs to power generation in 2035 (BP, 2014).
To date, various independent analyses have underscored the importance of CCS strategies in any successful effort to decarbonize power generation. For example, the Sustainable Development Solutions Network (SDSN) and the Institute for Sustainable Development and International Relations (IDDRI) have been engaged in ongoing analysis of deep decarbonization pathways for 15 nations (Australia, Brazil, Canada, China, France, Germany, India, Indonesia, Japan, Mexico, Russia, South Africa, South Korea, the United Kingdom, and the United States) at different stages of development, remaining cognizant of their differing circumstances and capacities (Williams et al., 2014). More than half of those countries would need to supply a substantial amount of their electricity from fossils fuels using CCS (Williams et al., 2014).
Other experts also have consistently highlighted the critical role of CCS technology in meeting the world’s climate goals. The Massachusetts Institute of Technology (MIT) states that (1) per Btu, coal is a low-cost “mainstay of both the developed and developing world, and its use is projected to increase”; (2) “because of coal’s high carbon content, increasing use will exacerbate the problem of climate change unless coal plants are deployed with very high efficiency and large scale CCS is implemented”; and (3) “CCS is the critical future technology option for reducing CO2 emissions” while allowing coal to meet future energy needs (MIT, 2007, p. x).
However, even under a dominant regime of switching from coal to natural gas (e.g., because of price impacts or lower emissions), technologies for drastically reducing emissions, such as CCS, will remain critical given the relatively high carbon content of natural gas compared with alternative fuels (e.g., renewables, nuclear) (C2ES, 2013). On a CO2 emission rate basis (pounds of CO2 per MWh), the conventional combustion of natural gas releases approximately 50 percent of the emissions produced by coal (EIA, 2014d). As reported by Biello (2014), Intergovernmental Panel on Climate Change (IPCC) Working Group III Co-Chair Ottmar Edenhofer stated in 2014, “We depend on removing large amounts of CO2 from the atmosphere in order to bring concentrations well below 450 [parts-per-million] in 2100.” Biello goes on to note, “Ultimately, he [Edenhofer] said, keeping global temperature rise to 2 degrees without any CCS would require phasing out fossil fuels entirely within ‘the next few decades’” (Biello, 2014).
Finding 5-5: Efficient and cost-effective technologies for capturing and either storing or utilizing CO2 and other GHGs from power plants will be a necessary and important component of a portfolio of measures for abating GHG emissions.
Status of Carbon Capture and Storage Projects, Market Barriers, and the Need for More R&D
As described in Chapter 2, CCS technologies have not yet reached performance or price levels that would make the widespread capture of CO2 from power plants commercially competitive, especially absent a price on emissions. In particular, while many component technologies are now or will soon be available, they have yet to be integrated into large-scale commercial projects (IEA, 2013).
Currently, 15 large-scale14 CCS projects are operational, 7 are under construction, and another 33 are in development or in the early planning stages around the world. These 15 projects represent a wide range of industries, including power plants, natural gas processing, fertilizer production, hydrogen production, and others (Global CCS Institute, 2016). The number of such projects in operation and under construction is double the number in 2000 (Global CCS Institute, 2016). Within the power sector, large-scale CCS projects are just now being realized (MIT, 2016). In 2014, the Boundary Dam Integrated Carbon Capture and Storage Demonstration Project near Estevan, Saskatchewan, in Canada commenced operations to become the world’s first large-scale CCS project for power generation, with a CO2 capture capacity of 1 million tons per annum (Mtpa). In the United States, one plant began generating power in 2016, construction began on another in 2014, one other is still in the planning stages, and another was canceled in 2016. Elsewhere in the world, 16 full-scale power generation CCS projects are in the planning stages as well (MIT, 2016).
Globally, 11 pilot-scale power generation plants with CCS (ranging from 1 MW to 50 MW) have completed demonstration (3 in the United States between 2008 and 2011), with another 8 currently in operation (2 in the United States) and 3 in the earlier planning stages (MIT, 2016). In addition, construction began in 2016 on a natural gas-fired plant that uses oxy-combustion technology to produce a high-pressure and high-quality “pipeline-ready” CO2 by-product (Net Power, 2014). Dedicated geologic storage has been demonstrated at a handful of these pilot-scale plants, and is also planned for several large-scale plants. However, all current large-scale power plants capture and transport carbon only for enhanced oil recovery (EOR) applications (MIT, 2016). (For more detail on the technology readiness of CCS technologies, see Chapter 2 and Appendix D.)
Although these data show that facilities and projects have demonstrated some of the critical aspects of CCS processes and engineering practice within
14 The Global CCS Institute measures projects in terms of the facility’s storage capability. Large-scale projects are defined as those capturing more than 0.8 million tons per annum (Mtpa). In contrast, MIT is measuring only power plants with CCS and differentiates large-scale and pilot projects by their electricity generating capacity, with pilot projects having a capacity less than 50 MW.
various regions and several different sectors, applications in the power sector still are only emerging. The “energy penalty” (the increase in energy input per unit of energy output) associated with power generation plants with CCS is not inconsequential: a pulverized coal plant, an integrated gasification-combined cycle (IGCC) plant, and a combined-cycle natural gas plant use 31 percent, 16 percent, and 17 percent more energy, respectively, than their non-CCS counterparts (Rubin et al., 2007a). Compared with theoretical minimums, as outlined in the technology readiness assessments in Appendix D, current technologies also use three times more energy to capture and compress CO2 than they would without CCS. Except for EOR applications, neither the thermodynamics nor current markets presently favor CO2 “utilization.” Theoretical calculations, however, do show that there is much to be gained from improving the technology.
Additionally, with respect to cost, a coal-fired IGCC power plant with CCS entering service in 2022 is projected to produce electricity at an average LCOE of approximately $82/MWh (in 2015 dollars), while the average LCOE for an advanced combined-cycle natural gas power plant with CCS is projected to be $87/MWh. Meanwhile, the LCOEs for new conventional coal-fired power plants and advanced combined-cycle natural gas plants would average an estimated $99/MWh and $59/MWh, respectively. Table B-1 in Appendix B outlines estimated costs of various emitting and nonemitting power generation technologies. It is important to note the distinction between those technologies that can dispatch on demand and those that cannot. The true costs of the latter are often higher because of the need for backup generation, storage, or other methods of dealing with their intermittency and variability. Even when various externalities are considered, both coal- and natural gas-fired power generation technologies with CCS technology still exhibit higher LCOEs than those without CCS.
Overall, while power generation plants with CCS cannot be expected to be less expensive than their non-CCS counterparts on a purely capital expenditure/technical basis, there is significant opportunity for research, development, and demonstration in CCS technology to begin leveling the playing field between fossil fuel-based power generation with CCS and alternative zero-carbon technologies such as wind. This opportunity means that while several pilot projects and one large-scale plant with CCS technologies are now operational, additional innovation and technological development are needed to make CCS technologies commercially competitive at the scale required for carbon abatement.
Key Nonmarket Barriers to the Development and Deployment of Carbon Capture and Storage Technologies
Operational concerns about CO2 capture and transport risks, as well as about the safety and integrity of CO2 storage in underground structures, are major nonmarket barriers to permanent geologic storage of CO2.
The operational concerns include perceptions about possible effects on water tables and other issues related to caprock and injection operations. Moreover, these concerns extend beyond those of the public and of environmental nongovernmental organizations (NGOs). In a February 2014 conversation with the National Association of Regulatory Utility Commissioners (NARUC), several commissioners expressed concerns about the lack of certainty with respect to suitable storage sites.15 DOE estimates that 180-240 gigatonnes of CO2 storage is available in oil and gas reservoirs and in unmineable coal reservoirs. DOE also estimates that 1,610-20,155 gigatonnes of storage is available in saline formations. While saline formations offer substantial opportunities, they are not as well identified or characterized as oil, gas, and coal reservoirs (NACAP, 2012).
The safety concerns include the possibility of carbon leakage, loss of well integrity, induced seismicity, and potential human health or other environmental impacts. Singleton and colleagues (2009) studied different notions of risk and public risk perceptions around the geologic storage of CO2. They concluded that while the public eventually will perceive CCS risks as similar to those associated with existing conventional fossil fuel technologies, the perceived risks will be higher in the interim because of the emerging nature of CCS and the paucity of demonstrations proving its safety (Singleton et al., 2009).
Another major obstacle to the development and deployment of CCS is the current lack of a uniform regulatory framework for managing the access to and use of underground pore space, siting and constructing CO2 pipelines, permitting or licensing storage activities on federal lands, and managing the long-term stewardship of closed injection sites (MIT, 2007). Additionally, several issues surrounding long-term liability and ownership of the performance/behavior of the CO2 in underground storage remain unresolved. Open questions include how best to address operational liability (liability associated with the actual capture, transport, and injection activities of CCS); climate liability (associated with potential leakage and contribution to thwarting of climate goals); and in situ liability (associated with possible CO2 migration within the rock formation or induced seismic activity) (de Figueiredi et al., 2005). Combined, these issues heighten the perceived risk faced by firms seeking to employ CCS. Finally, the inability of electric power utilities to routinely recover the costs of
15 Personal communication, NARUC commissioners, February 11, 2014.
The past inability of the government to take the lead on critical CCS issues has not inspired confidence among the power sector and represents another nonmarket barrier to CCS deployment and development. Since 2003, numerous restructuring and resiting efforts, cancellations, and other delays in DOE planned CCS demonstrations (FutureGen and FutureGen2.0) have left the public wary of the technical aspects of CCS and the industry wary of the type of sustained government support that can be anticipated for emerging technologies.
Finding 5-6: The risks involved in transporting and storing CO2 and the lack of a regulatory regime are key barriers to developing and deploying technically viable and commercially competitive CCS technologies for the power sector at scale.
Actions to Promote the Development and Deployment of Carbon Capture and Storage Technologies
One of the most important actions that can be taken to promote the development and timely widespread deployment of CCS technologies in the power sector is the implementation of enough demonstration projects to prove the technologies’ viability and efficiency at scale. CCS experts concur. MIT authors have urged that large-scale projects be undertaken to demonstrate the technical, economic, and environmental performance of an integrated CCS system as soon as possible. They also have suggested that several integrated large-scale demonstrations with appropriate measurement, monitoring, and verification are needed in the United States over the next decade, with government support (MIT, 2007). These demonstrations are important not only for establishing the technology itself but also for gaining the public’s trust (both in the effectiveness of the technology for large-scale storage and in government leadership). Implementing a comprehensive regulatory regime for the operation of CCS power generation projects is a second priority for realizing large-scale CCS (MIT, 2007).
Given the centrality of the cost differentials between coal- and natural gas-fired power plants with CCS and other clean power generation technologies, there are several actions the government can take to increase the competitiveness of cleaner fossil fuel power generation.
As discussed in Chapter 3, new approaches and increased funding are needed to strengthen the energy innovation system. Widespread adoption of CCS will require significant reductions in the cost and the energy penalties associated with CCS technologies. Given the importance of commercially
competitive CCS options to any global transition to a low-carbon future, increased research and development (R&D) efforts are needed to reduce the cost of CCS, including both retrofit and advanced combustion technologies. For example, DOE conducts CCS research at the National Energy Technology Laboratory (NETL), but the research is carried out under the Clean Coal Research Program and thus limited to coal.17 Given the fuel switch from coal to natural gas that is currently under way, it is important that CCS research be conducted on natural gas as well. Moreover, NETL currently lacks a test bed type of resource that could enable large-scale demonstration and testing of CCS technologies for either coal or natural gas.
Given the fiscal pressures on discretionary federal spending, the difficulties of demonstrating commercial projects at scale under federal/DOE guidelines, and other complicating factors, the committee believes that Congress’s consideration of this approach as a means of accelerating the development and demonstration of critical CCS technologies is warranted. One mechanism that might be considered for this purpose is the Regional Innovation Demonstration Funds proposed in Chapter 3. Additionally, cooperation between the federal government and regional utilities could help avoid jurisdictional issues that might occur with a federally mandated program. For example, DOE could cooperate with NARUC to design and develop possible funding mechanisms for supporting innovation efforts such as expanded research, development, and demonstration of a range of cleaner energy technologies that could include CCS. Again, this could be an important target of the proposed Regional Innovation Demonstration Funds.
The use of Pioneer Project Credits could provide incentives for innovation in and the deployment of CCS technologies. A limited number of targeted production tax credits could be offered to a pioneer tranche of natural gas-fired power plants employing carbon capture technologies. Such credits could be offered using both a reservation system (to assure project financiers that the credit could be used by the plant when built) and a reverse auction feature (to achieve the greatest possible benefits at the least cost to taxpayers). Prospective projects would compete against one another through a reverse auction, perhaps on the basis of dollars per ton of emissions avoided. This approach would promote continuous innovation while helping to ensure that the projects could be built at the lowest possible subsidy cost. Only those plants that achieved significant progress in planning (such as by securing key permits) would be allowed to reserve credits, and only those that actually operated and successfully reduced emissions would be awarded the production tax credit they had bid for through the reverse auction. Credits that were reserved but unused after a set period of time could be returned to the credit pool and made available to other
17 Given the large stock of existing coal-fired power plants in the United States, China, India, and other countries, it is likely that the stock of coal-fired power plants globally will increase in the coming decade, and DOE’s priorities for NETL need to include retrofitting of existing coal plants.
projects. In this manner, first-of-a-kind plants could be financed and built, and technologies could be tested under real-world conditions at scale.
Some of the early carbon capture projects have offset or plan to offset part of the high cost of carbon capture by leveraging the value of the captured CO2. Since CO2 is miscible with crude oil, it can be used to increase the amount of oil recovered from older oil reservoirs. Indeed, CO2 from natural underground sources and natural gas processing facilities is routinely used today to produce significant amounts of oil, particularly in the U.S. Permian Basin. The market value of CO2 used for oil recovery will vary with the market price of oil and other factors, but it is well below the level needed to serve as the sole justification for the cost of carbon capture from a power plant, at least at today’s oil price levels.
Congress could consider tax credits designed to bridge the price differential between the market value of CO2 used for EOR and the costs of carbon capture. These would best be narrowly and uniquely structured tax incentives for private-sector innovation at every stage, from R&D to construction of fossil fuel-fired power plants equipped with CCS. They could include Pioneer Project Credits for natural gas-fired power generation with CCS, CO2/Enhanced Oil Recovery Credits, and tax-exempt bond financing. These tax credits could be paid for through the elimination of current subsidies to incumbent, mature technologies. Such a tax credit for carbon capture technology applied to electricity generation and other industrial processes, made available through the same cost-saving innovation-enhancing reverse auction process outlined earlier, would only need to cover the difference between an oil producer’s willingness to pay for CO2 and the cost of its capture and delivery. Because the federal government derives revenue from each additional barrel of oil produced in this manner, some analyses suggest that the tax credit could be revenue-neutral or even revenue-positive over time.
Congress also could consider allowing the incremental capital spending associated with carbon capture (not the entire facility) to be financed using tax-exempt private activity bonds. This is the method often used from 1968 to 1986 to finance pollution control facilities such as flue gas desulfurization equipment and other advanced pollution control equipment at power plants owned and operated by investor-owned utilities. It also is the method often used today to finance privately owned solid waste, sewage, and hazardous waste facilities.
In addition, placing an economy-wide price on CO2 emissions equivalent to its externalities—for example, through a carbon tax—would, in the long run, be a direct and highly efficient way for Congress to help level the playing field between entrenched fossil fuel-based CO2-emitting power generation technologies and increasingly clean power generation technologies such as CCS. Given that fossil fuel facilities with CCS will cost more than equivalent facilities that lack the expense of carbon capture, as well as limited economic opportunities to use captured CO2, carbon pricing or an equivalent regulatory requirement may be a prerequisite for widespread deployment of CCS.
In a previous study (NRC, 2011), a National Research Council committee found that carbon pricing would be an important element of a comprehensive national CO2 mitigation program. According to that committee, “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” (p. 58). This issue is explored more fully in Chapter 2 (see Recommendation 2-2).
A supportive policy scheme for CCS projects would aid in the continuing demonstration of the technologies themselves and in harnessing public acceptance of long-term geologic storage of CO2 as the focus for the next phase of CCS development. Congress needs to establish a comprehensive regulatory framework for the transport and safe geologic storage of CO2. Such a framework would include two key components. First, it would feature a federal opt-in program for CO2 pipelines. This program would enable the Federal Energy Regulatory Commission (FERC) to supervise a mechanism whereby operators of such pipelines could apply to FERC for federal siting authority. Such authority, if granted, would allow the use of federal eminent domain authority to site a pipeline. In turn, the pipeline operator would be obligated to operate as a common carrier (but without FERC or other regulation of rates). Second, Congress would enact legislation declaring that underground CO2 storage is in the public interest and eliminate the uncertainties of the Class VI well category under the existing Underground Injection Control regulation. This new legislation would ensure access to pore space, establish arrangements for the management of long-term stewardship and liability for storage sites once they had been closed, and institute GHG accounting programs.18
Another possibility would be for Congress and the Environmental Protection Agency (EPA) to establish a framework for the development of long-term performance standards, formulated as agreements with industry in accordance with what is known as the “Dutch Covenant” model. This would be a framework for a collaborative public/private approach rather than an adversarial arrangement.
Recommendation 5-3: Congress should direct the EPA to develop a set of long-term performance standards for the transport and storage of captured CO2. This effort should include establishing management plans for long-term stewardship and liability for storage sites once they have been closed, as well as GHG accounting programs.
Electric power utility regulators have expressed concerns over the current lack of certainty about suitable dedicated geologic CO2 storage sites, hampering development. DOE could address this barrier and immediately begin facilitating the undertaking of large-scale demonstration projects by supporting a formal and comprehensive site survey, led by the U.S. Geological Survey (USGS), to identify and characterize suitable underground storage sites for the United States. Funding should be made available for updating this survey on a regular basis.
The risk of being unable to find a suitable site for CO2 storage in a timely and economical fashion is considerable. No commercially available services for CO2 storage currently exist, and while there are firms that conduct site characterizations and will drill test wells to verify a site’s suitability for storage, those activities have high costs in both time and money, with no guarantee of a satisfactory outcome for CO2 storage.
The ZeroGen project in Australia illustrates the challenges that can arise in identifying appropriate storage sites. That project spent 3 years and AUD$100 million on exploration, drilling, and testing, eventually leading to the conclusion that the area initially identified as promising could not sustain the injection rates required for the proposed 390 MW IGCC project. One of the key lessons learned from this project was that a “…large amount of expensive data gathering should be expected and while success rates might be higher than in the oil and gas exploration sector, failure rates and costs and delays are likely to be significant” (Garnett et al., 2014, p. 218).
Recommendation 5-4: USGS should identify and characterize CO2 storage sites.
The Role of Renewables in an Increasingly Clean Energy Future
Nearly every model and forecast of an increasingly clean energy system includes an expanding role for renewable electricity generation. Wind and solar tend to dominate the renewable portion of these forecasts, but other renewable sources, such as hydro (small, large, low-head), biomass, geothermal, and offshore, also have potential to contribute to a clean energy portfolio. Without taking account of price and the design of the nation’s electricity system, the size of U.S. renewable resources is adequate to meet the country’s long-term electricity needs. As discussed in this section, however, advances in economic, technology, and market structures will be needed if renewables are to be utilized
effectively over the mid- to long term for a major portion of the country’s electricity system.
Chapter 3 presents issues, findings, and recommendations related to effective pathways for innovation, scale-up, and deployment of increasingly clean power technologies. It argues for the need for a complex transition to newer technologies, both large-scale and distributed; new electricity grid models; new roles for the demand side of the energy market; a robust perspective on gaps that need to be addressed in the U.S. energy innovation system; regulatory reform from the local to the federal level; and differentiated roles whereby the federal government, states, regions, and the private sector would partner or take the lead. Across this diverse energy landscape, renewables are likely to play an increasing role in the clean energy future of the United States and the world. Renewable resources are by definition sustainable, with stable, predictable economics for a given project and small or no consumable fuel costs, and are not subject to the volatility that characterizes the prices of conventional fuels. While some renewables (biomass in particular) produce emissions, most produce zero use-phase emissions and have modest environmental and health operating impacts. These characteristics attract investment and attention around the world.
Current Challenges for Renewable Energy
Renewables have seen impressive cost declines in recent years, but the electricity they produce still generally costs more than most electricity generated from fossil fuels, particularly natural gas, in the United States. While the data are variable, Bloomberg New Energy Finance (BNEF) (2014a, p. 15) reported that “over a five-year period to the first quarter of 2014, the worldwide average levelized cost of electricity has declined by 53 percent for crystalline silicon PV systems, and 15 percent for onshore wind turbines.” Further, BNEF reported in October 2015 that the “levelised cost of electricity for H2 2015 shows onshore wind to be fully competitive against gas and coal in some parts of the world, while solar is closing the gap” (BNEF, 2015). “Over the same years, the cost per MWh of coal- and gas-fired generation has increased in many countries, with the notable exception of the US where gas prices remain much lower than elsewhere” (Best Energy Investment, n.d.). Lawrence Berkeley National Laboratory notes that prices for installed solar PV declined by 12-15 percent from 2012 to 2013, and U.S. distributed solar prices fell an additional 10-20 percent in 2014, with declines continuing into 2015, continuing a 6-year trend (Bolinger and Seel, 2015). The total cost reduction over the period 2009-2013 was close to 50 percent. Wind energy prices have fluctuated over the last decade, with increases from 2004 to 2009 being driven largely by rising capital costs for materials, primarily steel, but also including iron, copper, aluminum, and fiberglass (Lantz et al., 2012). Subsequent years have seen a reversal in that trend, with a capacity-weighted average installed project cost of approximately
$1,630 per kilowatt (kW), down from the cost of more than $2,200 per kW observed in 2009-2010 (Wiser and Bolinger, 2014).
In addition to price considerations, many renewable technologies are variable and cannot be dispatched in the traditional manner. High penetrations of variable generation may need to be balanced by flexible supplies or more responsive demand, including smart metering and distributed storage. The unpredictability of some renewable generators could pose management challenges for today’s electricity grid with substantial increases in deployment.20 For these reasons, modernizing the electricity regulatory system and grid management models (as discussed in Chapter 6) is important if the benefits of these technologies are to be fully captured.
Findings on Renewables
The challenges that need to be addressed if the deployment of renewables is to increase are structural in nature. As the National Research Council (2010a, p. 322) concluded:
The primary current barriers are the cost-competitiveness of the existing technologies relative to most other sources of electricity (with no costs assigned to carbon emissions or other currently unpriced externalities), the lack of sufficient transmission capacity to move electricity generated from renewable resources to distant demand centers, and the lack of sustained policies.
According to the National Research Council (2010a, p. 4), establishing renewables as a major source of energy in the future will require innovation not just in renewable technologies but also in grid technologies. “Achieving a predominant (i.e., >50 percent) level of renewable electricity penetration will require new scientific advances (e.g., in solar photovoltaics, other renewable electricity technologies, and storage technologies) and dramatic changes in how we generate, transmit, and use electricity.”
National Renewable Energy Laboratory (NREL) (2012) models a series of scenarios to analyze the grid-integration implications of generating 30-90 percent of U.S. electricity from renewable sources. The report concludes that it could be technologically feasible for renewable energy resources to “supply
20 The day-ahead predictability of wind is subject to fairly serious errors. At the 95 percent confidence interval required by the Electric Reliability Council of Texas (ERCOT), for example, errors are a bit more than 30 percent (see Mauch et al., 2013). And despite its inherent predictability, solar forecasting is not a mature science. For example, much of the variation in solar power is due to cumulus clouds that cause very fast and deep variations that have thus far proven resistant to forecasting techniques (see Curtright and Apt, 2008).
80 percent of total U.S. electricity generation in 2050 while balancing supply and demand at the hourly level,” with contributions coming from “all regions of the United States…consistent with their local renewable resource base” (p. 3). The report includes current existing nuclear and IGCC units but does not allow for new additions of either nuclear or IGCC units or fossil fuel technologies with CCS. In addition, the report includes only renewable technologies commercially available as of 2010. The authors also assume that grid technologies would improve system operations to “enhance flexibility in both electricity generation and end-use demand” (p. 5), and that both transmission infrastructure and transmission capacity access would expand. However, the authors caution that because solar PV and wind have little dispatchability, high “levels of deployment of these generation types can therefore introduce new challenges to the task of ensuring reliable grid operation” (p. 12). They also note that higher incremental costs would be a significant barrier to the deployment of renewable technologies at high levels and that improving performance and lowering costs would have the greatest impact on overcoming that barrier (NREL, 2012).
According to a different analysis published 2014, improving the penetration of renewables to 20-30 percent of electricity generation would be feasible if there were changes in the management and regulation of the power system (Apt and Jaramillo, 2014). The authors identify variability in power output as a key technical barrier that leads to a number of operational and regulatory challenges, and suggest a number of solutions for overcoming this barrier. Those solutions include better prediction of variability and strategies for reducing it; changes in the operation of power plants, reserves, transmission systems, and storage; improved planning of renewable capacity expansion; and implementation of new regulatory paradigms, rate structures, and standards.
Finding 5-7: The variability of renewable generation does not prevent the future expansion of renewable technologies, although high penetration of renewables likely will require investments in innovation to improve grid technologies, storage, and regulatory paradigms, among other changes.
Still, a broad range of needs and challenges for renewables will need to be addressed if these energy sources are to gain lasting economic and environmental value. These include
- innovation (both improvements in renewables and breakthroughs in storage);
- continuing reinvestment in renewable and grid technologies to support growth and drive consistent learning;
- consistent markets that encourage competition and cost-effective investments in economies of scale (e.g., Lueken and Apt , argue that the existing regulatory and market structures are inadequate
to encourage the required amount of storage for renewable integration);
- supportive, transparent, and flexible regulatory regimes that can adapt and evolve alongside a similarly evolving energy system; and
- investment in re-architected grids that are more reliable and efficient and can be designed to effectively manage, store, and use energy with significant renewable penetration and leverage distributed resources and smart demand.
These findings are aligned with the focus of the present report on innovation, the policy and financing consistency needed to support the development of competitive markets, pricing of environmental externalities, and the modernization of the electricity system necessary to fully embrace the value of renewables.
Renewables and Economic Growth Opportunities
Ongoing government support for innovation and encouragement of private-sector investment in renewable technologies could help the United States be a technology leader in the development and deployment of these technologies. U.S. expertise in innovation, entrepreneurship, manufacturing, and business is creating opportunities for a major U.S. role in the rapidly growing markets for renewables. Innovation is needed in systems, components, manufacturing, and integration. For example, despite increasing competition from China, which played a central role in the recent decline of the German solar industry, the outlook for solar PV production in the United States remains promising.
Recent announcements and discussions of plans for new solar PV manufacturing plants in New York State suggest a growing economic opportunity in renewable manufacturing. In September 2014, for example, SolarCity broke ground on a massive solar panel manufacturing facility in Buffalo, New York. The facility, when, and if, fully completed in early 2017 “is supposed to make a gigawatt worth of solar panels a year, in the one million square foot facility. SolarCity…[has] agreed to work with the state to spend $5 billion over the course of 10 years to build out and operate the factory, creating local jobs” (Fehrenbacher, 2014). In another potential manufacturing project, the world’s number two solar thin-film manufacturer, Japan’s Solar Frontier (with a major ownership share by Shell as a subsidiary of Showa Shell Sekiyu), is currently exploring the development of a factory in upstate New York (Ayre, 2014).
It is important for manufacturing investments in the United States to focus a portion of their product output on U.S. markets. Global corporations increasingly see renewable generation technologies addressing global markets, with opportunities to site multiple manufacturing facilities close to major market
adoption regions of the world and with opportunities to combine economies of scale with faster innovation cycles closer to customers and market channels. Leveling the playing field for global corporations considering investment opportunities for renewables in the United States and in other global market centers would require removing barriers to U.S. competitiveness while encouraging private-sector investment (NRC, 2012). The federal and state governments need to carefully consider tax, trade, and other policies that would encourage renewable manufacturing investments in the United States.
U.S. Markets for Renewables
Renewable resources vary considerably across the United States. Combined with regional electricity markets, state-specific policies, regulatory and market structures, and several thousand utility jurisdictions, this variation means a diversity of markets for renewables. One consequence of this diversity is important opportunities to learn and share the lessons from the most robust markets. Renewables are approaching competitiveness in some regions of the United States and exhibiting cost decline trends, with increasing competition, market economies of scale, improving technology, and supply chain and value chain efficiencies all helping to drive market improvements. Regions with the most cost-effective renewable resources and market development efforts offer recent examples of this approaching commercial competitiveness. In Colorado, for example, Xcel Energy in 2013 issued a broad “all source” solicitation so it could consider the most competitive proposals for wind, solar, and other resources, including natural gas. Xcel selected a diverse portfolio that would add 317 MW of natural gas, combined with 450 MW of wind and 170 MW of solar. Xcel describes how the “strong competition between resources and even between different types of resources yields a number of low cost resource combinations that could meet Xcel Energy’s needs” (Xcel Energy, 2013). This is but one example of how improvements in renewable technology and industry experience, combined with market pull and competitive solicitation mechanisms, are contributing to progress toward the competitiveness of renewables in regions with strong renewable resources.
While states have a range of pricing and procurement policies, incentives, standards, and models, many parts of the United States encourage competition for wind projects to win power purchase contracts and enable low-cost financing for construction. It is important to continue these trends in the near and mid terms while avoiding problems with inflexible policies such as feed-in tariffs and similar structures that lock in higher-than-necessary prices and delay market competition, maturation, and innovation.
Recommendation 5-5: As renewable technologies approach becoming economically competitive, states should seek to expand competitive solicitation processes for the most cost-
effective renewable generation projects and consider the long-term power purchase agreements (PPAs) necessary to enable low-cost capital for project financing.
The diversity of U.S. market policies on renewables with such market structures as renewable energy credits (RECs) has generally avoided policies that lock in higher costs. At the same time, the lack of consistent polices for market scale and the patchwork nature of renewable portfolio standards (RPS) as enacted by the states have hampered innovation and private-sector investment in renewables. In addition to varying prices for electricity, higher capital costs and slower market maturation than is necessary have resulted from inconsistent standards across states, differing pricing models, differing market mechanisms for receiving off-take and interconnect agreements, uncertain siting practices, and an inability to site and finance related transmission investments.
Although they have declined, installed PV prices in the United States remain twice as high as those in Germany and substantially higher than those in the United Kingdom, Italy, and France. A Lawrence Berkeley National Laboratory study attributes this disparity largely to differences in “soft costs,” which may be driven partly by differing levels of deployment scale (Barbose et al., 2014). Reductions in soft costs remain a major part of DOE’s SunShot initiative.
Finding 5-8: Consistent siting, streamlined permitting, clear and responsive interconnection processes and costs, training in installation best practices, and reductions in other soft costs can have a significant impact on lowering the cost of solar and other distributed generation renewable technologies.
Recommendation 5-6: DOE and national laboratory programs should provide technical support to states, cities, regulators, and utilities for identifying and adopting best practices—such as common procurement methods, soft cost reduction approaches, PPA contracts, structures for subsidies and renewable energy certificates, and common renewables definitions (taking into account regional resources)—that could align regional policies to enable more consistent and efficient markets that would support the adoption of renewables.
Renewable Portfolio Standards
State RPSs are an option commonly used to force utilities to increase their utilization of renewables, and they have created significant but still inefficient market pull. RPSs require that either utilities or, in jurisdictions with retail competition, retail electricity suppliers use renewable energy or obtain RECs21 for a minimum amount of their electricity sales, or that utilities procure a minimum amount of renewable generating capacity in their portfolio of electricity resources. An RPS sets a schedule of renewable energy or capacity to be obtained by specific years. Requirements generally increase over time. Many RPSs include a set-aside or carve-out that requires a minimum percentage or amount of the overall standard to be met using a specific technology, typically solar energy. An alternative or clean energy standard is comparable to an RPS, but permits some portion of the requirement to be met through investments in energy efficiency or the use of various nonrenewable alternative energy resources. For purposes of simplicity, the discussion here refers to state standards that include renewable energy requirements as RPSs.
RPSs have been important for the development of renewable energy resources. Currently, 29 states and the District of Columbia, accounting for 64 percent of U.S. electricity sales, have RPSs.22 Approximately 46 GW of new renewable generating capacity had been developed in these 29 states by the end of 2012, equaling two-thirds of all nonhydro renewable electricity generation capacity additions in the United States since 1998 (Heeter et al., 2014). An additional 8 states have adopted voluntary renewable energy goals (Heeter et al., 2014).23 Together these 36 states account for nearly three-quarters of U.S. electricity sales (EIA, 2013a).
21 RECs are often used to provide a uniform system for tracking the purchase and use of renewable energy. Such tracking ensures that the financial incentives created by a portfolio standard flow to the owners of covered renewable resources. Tracking services are provided by independent system operators (ISOs)/regional transmission organizations (RTOs) (e.g., ERCOT and PJM-Environmental Information Services [EIS]), states (e.g., Michigan Renewable Certification System, North Carolina Renewable Energy Tracking System, New York State Energy Research and Development Authority, and Nevada Tracks Renewable Energy Credits), and independent services (e.g., Midwestern Renewable Energy Tracking System, New England Power Pool Generation Information System, North American Renewables Registry, and Western Renewable Energy Generation Information System).
22 Arizona, California, Colorado, Connecticut, Delaware, District of Columbia, Hawaii, Illinois, Iowa, Kansas, Maine, Maryland, Massachusetts, Michigan, Minnesota, Missouri, Montana, Nevada, New Hampshire, New Jersey, New Mexico, New York, North Carolina, Ohio, Oregon, Pennsylvania, Rhode Island, Texas, Washington, and Wisconsin as of March 2013 (see www.dsireusa.org).
23 Indiana, North Dakota, Oklahoma, South Dakota, Utah, Vermont, Virginia, and West Virginia.
States have differing definitions of qualifying resources. Of the states with standards or goals, 10 allow solar thermal resources to qualify, 9 include energy efficiency, 6 allow combined heat and power, and 4 count certain nonrenewable resources (Heeter and Bird, 2012). Of the 29 states with standards, most provide some additional incentive that benefits solar energy resources. Fourteen states and the District of Columbia have a set-aside that must be met with solar resources;24 2 have a set-aside for distributed generation;25 and 3 provide triple or double credit for solar electric, distributed generation, or nonwind resources.26
Early RPS results have been achieved with relatively small impacts on retail electricity prices. In part, this small retail price increase is attributable to the directly measurable costs of RPSs. It may also be due in part to the federal production tax credit.27 REC purchases in competitive retail markets and utility-reported purchase costs in other cases have been small relative to total utility revenue. Most RPS policies include a cost containment mechanism: either a cap on total compliance costs as a percentage of average retail rates or an alternative compliance payment. These mechanisms typically limit compliance costs to 1-4 percent of average retail rates in the case of overall caps or 6-9 percent of average retail rates in the case of an alternative compliance payment and no overall rate cap (Heeter et al., 2014). A recent survey of state-level costs found that while there are substantial variations among states and from year to year, “Focusing on the most recent historical year available [2010 to 2012], estimated incremental RPS compliance costs were less than 2 percent of average retail rates for the large majority of states” (Heeter et al., 2014, p. v). However, incremental renewable energy costs—the additional cost per MWh for renewable energy in excess of the cost per MWh of nonrenewable generation—can be significant. The survey found that in restructured states, average renewable energy or REC purchases added $2-48 per MWh of renewable energy obtained. In other states, utilities reported that general RPS obligations, excluding the typically more expensive set-asides for solar or distributed generation, had incremental costs ranging from negative $4 to an additional $44
24 Delaware, District of Columbia, Illinois, Maryland, Massachusetts, Missouri, Nevada, New Hampshire, New Jersey, New Mexico, New York, North Carolina, Ohio, Oregon, and Pennsylvania as of March 2013 (www.dsireusa.org).
27 A prior National Research Council study found some complementarity between state-level RPSs and the federal production tax credit (PTC). That study commissioned modeling that produced estimates suggesting that the combined impact of both policies on new builds of wind power is only slightly greater than the impact of either policy alone. This finding implies that much of the wind power could be built with just the RPS (or the PTC), and thus a (possibly substantial) portion of the costs of compliance may have been paid for by the PTC. That study also found, however, that energy and economic models were not well suited to modeling the impacts of tax policies (NRC, 2013c).
per MWh of renewable energy. However, there is no standard methodology for reporting RPS costs. The costs in the survey may omit certain integration and system operating costs, and historical costs may not be representative of future costs as RPS requirements increase. Few states have conducted benefit-cost analyses of their RPS requirements (Heeter et al., 2014).
A modest RPS can either increase or decrease market prices. RPSs subsidize renewable resources and bring additional resources with low variable operating costs into energy markets. If there is a sufficient upward slope in the supply curve for generation, displacing higher-cost resources (and potentially lowering demand for the fuel serving those generation resources) can depress prices in independent system operator (ISO)/regional transmission organization (RTO) energy markets. In organized electricity markets with capacity pricing, however, the reduction in energy market prices may be offset by higher administratively determined capacity prices. Additionally, RPSs effectively impose a tax on retail suppliers that must pay for more expensive renewable resources or RECs. This has the effect of increasing prices. How these potentially offsetting effects play out given a low RPS requirement depends on the supply curves for renewable and nonrenewable generation and market structures. However, the impact on market prices becomes less ambiguous when RPS requirements increase. According to Fischer (2010, p. 117), “both the analytical and numerical modeling suggest that rate reductions are only likely at lower RPS shares. At higher RPS shares, in contrast, the implicit tax quickly dominates and electricity prices increase rapidly.”
The development of state-level RPSs is, in part, a response to the lack of a more comprehensive national policy for reducing carbon emissions. Local development of renewable resources provides an immediate, visible representation of state action to address climate change, even if its impact on global GHG emissions is minimal. An analysis by Resources for the Future suggests that state RPSs reduced U.S. CO2 emissions by 4 percent in 2010. The authors concluded that, “given that by 2010 the RPS have been in effect for only a few years in many states, this is a fairly significant impact. The gap between the two cases [with and without state RPSs] is likely to continue to widen as RPS are fully implemented across the nation” (Sekar and Sohngen, 2014, p. 10).
Consideration is being given to the continuation or expansion of RPS requirements to achieve higher levels of renewable energy deployment.28
28 RPS policies may be subject to reconsideration in some states. Ohio recently enacted a 2-year suspension of its RPS requirement, which in the absence of further legislative action would defer full compliance from 2025 to 2027. (Ohio also suspended energy-efficiency standards; its action on energy efficiency raises issues that deserve careful study in terms of the suspension’s potential to increase customer costs and slow economic growth.) Proposals have been made to repeal RPSs in 18 of the 29 states that have adopted such standards. See http://web20.nixonpeabody.com/energyblog/Lists/Posts/Post.aspx?ID=81&Title=Tough+Times+For+Renewable+Portfolio+Standards (accessed June 20, 2014).
Identifying the factors that may be important to the adoption of RPSs can involve a review of the arguments advanced and/or a study of the circumstances surrounding their adoption.29 RPS policies also may reflect efforts to limit other environmental externalities, reduce the cost of renewable technologies through enhanced learning by doing, enhance the reliability of distribution with distributed generation, promote the security of energy supplies, preserve water resources, and/or create local jobs in an emerging clean energy industry and potentially capture first-mover advantages (Fischer and Preonas, 2010).
Although RPSs have reduced CO2 emissions, RPSs are not the most cost-effective means of doing so. As indicated in a previous National Research Council (2010c) report, pricing GHG emissions provides the critical foundation for cost-effective reductions in GHG emissions and the basis for innovation and a sustainable market for renewable energy resources. Most studies of alternative renewable energy policies agree that a carbon tax or cap-and-trade system would reduce GHG emissions more cost-effectively than RPSs (see, e.g., Fischer and Newell, 2008; Fischer et al., 2013; Palmer and Burtraw, 2005; Palmer et al., 2010; Tuladhar et al., 2014). For example, Palmer and colleagues (2010) compare the cost of achieving a reduction in CO2 emissions using a national RPS—a 25 percent renewable standard by 2025—with that of a cap-and-trade policy achieving the same emissions reduction. They estimate that the RPS would have an average cost of $14 per ton of CO2 reduced, while the same reduction could be achieved in a cap-and-trade program for $4 per ton, or less than one-third the cost. This finding is not surprising. In requiring the use of renewable technologies, RPSs fail to recognize other actions, such as the substitution of gas- for coal-fired generation, that might reduce emissions more cost-effectively. RPSs treat all renewable generation equivalently, as if all renewable generation sources displaced comparable nonrenewable sources and had an equivalent net emissions impact. They lower the cost of selected clean energy technologies, but do not incorporate the social costs of carbon and other environmental externalities into the price of polluting resources, potentially distorting price signals for both consumers and other market participants (Borenstein, 2012; Nordhaus, 2013). Market-based environmental regulation that appropriately prices both GHGs and other environmental externalities will tend to produce and provide incentives for emission reductions more cost-effectively relative to comparable technology requirements.
Technology deployment incentives can create innovation benefits by supporting learning by doing.30 However, the appropriate incentive for promoting learning by doing is likely to be lower than the deployment incentives currently available from RPSs, tax credits, and other renewable energy programs.
General RPSs are not tailored to improving the reliability of distribution, promoting the security of energy supplies, preserving water resources, and/or creating jobs. There are many ways to improve the reliability of distribution. Greater reliance on renewable resources might help Western Europe reduce imports of natural gas or help California limit cooling water requirements. However, greater reliance on renewables also could increase dependence on imported rare earth elements. And while renewable generation will create some jobs, potentially offsetting job losses can be associated with increased power costs. Policies specifically designed to achieve these secondary benefits could be more cost-effective in meeting stated objectives. A cap-and-trade program could efficiently reduce and price GHG emissions. If a binding emissions trading system were implemented, RPSs would not necessarily produce additional emission reductions, but would likely increase overall compliance costs (Fischer and Preonas, 2010). In circumstances where a binding emissions trading system reasonably reflects pollution costs and creates an effective market signal for emission reductions, it would be beneficial for states or regions to evaluate the impacts of replacing RPSs with a cap-and-trade system and more modest, targeted incentives to produce learning-by-doing benefits. Savings from reduced renewable energy deployment incentives could be redirected to earlier stages of the innovation system, where greater public resources are needed to support the development and demonstration of new low-carbon technologies (see Chapter 3). Ultimately, when possible, states would benefit from seeking to ensure that their policies evolve to establish best practices for competition featuring market signals and other such mechanisms for participants.
Removing barriers to participation by government agencies and departments as active customers in state and regional markets for renewable energy would also improve opportunities for renewable generation. Steps to this end would include enabling federal facilities, such as military bases, to sign PPAs for renewable power. The Department of Defense in particular offers opportunities for renewables because of the size of its energy demand and budget, its global footprint, and its mandate to use renewables for 25 percent of its total energy needs by 2025. Executive Order 13693 goes a long way toward encouraging the federal government’s role as a leading consumer of increasingly clean energy by setting renewable and alternative energy and energy-efficiency targets for federal facilities.
Finding 5-9: Few states have conducted benefit-cost analyses of their RPS requirements and evaluated options for evolving their RPSs, learning from other states, and taking innovation and evolving models into account.
Recommendation 5-7: State and regional authorities should regularly arrange for independent evaluations of the effectiveness and cost of their policies for encouraging
deployment, competition, cost declines, reductions in financing costs, and other aspects of renewable energy technologies. They also should be encouraged to adopt evolving best practices for competition, including market signals and mechanisms, in their state renewable policies and programs.
Incentives, Subsidies, and Diverse Technology Market Growth
Subsidies are critically important to emerging technologies, particularly those with life-cycle benefits that are not priced. As discussed above, despite significant cost reductions in renewables in recent years, renewables in most areas of the United States still are not cost-competitive and continue to require subsidies as an important component of establishing a path to their eventual competitiveness. These subsidy levels have been declining for maturing renewables, with onshore wind having developed into the most cost-effective renewable. As of 2013, solar “cash incentives (rebates and performance-based incentives) have fallen by 85-95 percent from their historical peak in 2001-2002, and incentive reductions from 2012-2013 equal 40-50 percent of the drop in installed prices” (Barbose et al., 2014, p. 2). Federal subsidies, such as the investment tax credit for solar and the production tax credit for wind, that are targeted at deployment have demonstrated their effectiveness. That being the case, subsidies are best not designed to be permanent, but to have sunset provisions and to phase out over time on a technology-by-technology basis, with market tests that consider cost and progress toward unsubsidized competitiveness.
This type of approach to supporting technology development and early deployment does not constitute picking winners and losers. Incentives are applied across a class of technologies, not to a single product or company, with pricing mechanisms that decline over time, but there also are market tests for appropriate phase-out under actual market development conditions. These approaches encourage private-sector investment in innovation, infrastructure, and scale-up while avoiding the stop-and-start impacts of short-term extensions of tax credits.
Another principle for federal and state renewable policies involves appropriate regulatory and financing structures for projects with differing scales:
- Small, distributed generation projects (such as rooftop solar) reduce but are unlikely to economically eliminate owners’ purchases of electricity in retail markets. Appropriate pricing of interconnection with the power company and the grid and pricing for backup services, such as the price of utility-provided power when the distributed generation project is not producing enough power for the customer,
are important to maximize the value of distributed generation projects.
- Community-scale renewables provide virtual generation and energy management to multiple customers, and over time are expected to be combined with efficiency, demand response, microgrids, combined heat and power, storage, and other distributed energy approaches and resources. Community-scale projects need pricing and rate models that encourage innovation and competition, recognize the value of this distributed virtual system, and also incorporate the evolving role of the utility in integrating and managing the electricity system as an “Internet” network of networks.
- For utility-scale renewable generation, long-term PPAs have proven effective in incentivizing a number of projects around the country. The long-term PPAs have enabled low-cost project financing, since most renewable projects have high capital costs and little or no variable fuel costs.
Across all technologies and scales, it is important to emphasize that renewable deployment needs to take place in an increasingly competitive market, and to continue to reward learning and economies of scale, as well as projects with the best economics. Effective federal, state, and local policies need to be consistent with growing market signals that look out at least 5 years to encourage investment in innovation and development that will continue to bring down costs.
Reducing the cost of capital for renewable and clean energy projects is an important component of leveling the playing field. While this issue is discussed in greater detail in Chapter 7, it is important to acknowledge here the importance of federal and state policies to reducing the financing costs for zero-emission technologies.
Federal tax changes that would extend real estate investment trust (REIT) and master limited partnership (MLP) financing structures to zero-emission technologies could also help address financing issues related to renewable projects. In addition, many states are developing or considering so-called “green banks” to leverage low-cost state borrowing in combined public/private financing structures for lower-cost renewable and energy-efficiency deployment projects. The federal government might consider encouraging banks to participate in these green bank programs through approaches similar to the Community Reinvestment Act, which has enabled the deployment of increased private capital for local projects.
Utility Adoption Issues/Barriers
Chapter 6 reviews challenges associated with the regulatory structure of the electric power industry. Utilities play critical roles in the deployment of renewables, but current business models for utilities tend to be insufficient for adequately incentivizing the adoption of renewables. State and federal incentives and regulations need to encourage utilities to change their priorities and decision processes, but without being unduly burdensome.