Appendix II: Key Issues for the Back-End of the Nuclear Fuel Cycle

Seven macro propositions⁵² about the nuclear fuel cycle, in general, consistently arise in conversations on the back-end of the nuclear fuel cycle, in particular.

1. Uranium is either scarce or too expensive. Based on estimates of the world’s economically accessible uranium resources, the existing reactor fleet could run for more than 200 years at current rates of consumption. That is, given that the fleet of present-day reactors requires about 70,000 to 80,000 MT of natural uranium per year, estimates of identified and undiscovered natural uranium totaling 16 million MT would provide a roughly 215-year supply at today’s consumption rate. This estimate does not include extraction of uranium from seawater, which could potentially make available 4.5 billion MT of uranium—a 60,000-year supply at present rates. Thus, on a timescale covering the next several decades, a uranium-based fuel cycle appears to be sustainable.⁵³ On the cost side, supply and demand for uranium will determine prices in the long run. Long-term prices have recently been trading in the $50 to $75 per pound range and do not have an impact on choices for or against nuclear energy.⁵⁴ Thus, while there is the potential that the number of reactors will grow significantly—increasing capacity to somewhere between 400 and 500 GWe and causing the demand for uranium to rise markedly and result in higher costs for uranium ore—the price of uranium is not likely to be a critical factor in determining the practical deployment and sustainability of nuclear power.⁵⁵
2. The economic penalty associated with conventional reprocessing and recycling is outweighed by the noneconomic benefits that would accrue. In the past, advocates of conventional reprocessing have emphasized its contributions to extending fuel supplies and increasing energy-supply security. Today, the principal claim is that conventional aqueous reprocessing (that is, chemically partitioning the fissile material⁵⁶ and relatively small quantities of related actinide materials from the waste products) will facilitate and simplify the management and disposal of nuclear waste. To fully understand this assertion, it is important to ascertain how large the cost penalty associated with conventional reprocessing and/or recycling is likely to be. We cannot determine an exact answer because some of the most important contributing factors are uncertain or otherwise difficult to estimate. The greatest source of uncertainty, with the largest impact on overall cost, is associated with the chemical partitioning process itself. Other important uncertainties center on the cost of MOX fuel fabrication and the relative cost of disposing reprocessed HLW as compared to the direct disposal of used fuel.⁵⁷ However, if technology for advanced reactors included safer, more economic designs, and if these technology advancements included meaningful actinide consumption opportunities, the heat load and toxicity of the HLW stream would be substantially reduced. This key benefit of closing the fuel cycle (a benefit that is normally not included in costs for near-term back-end fuel services) would be a waste disposal game changer: specifically, it would jettison the siting of multiple HLW repositories,⁵⁸ one of the most contentious public policy bottlenecks that influence public acceptance of nuclear energy expansion.⁵⁹ As long as uranium prices remain in the $50 to $75 range⁶⁰ and, more important, as long as we lack deployable, cost-effective technologies to change dramatically the approach to waste disposal, the benefits of treating used fuel are not sufficiently compelling today.
3. Because fuel cycle expenses account for less than 10 percent of the total cost of nuclear electricity from unamortized nuclear power plants (capitalrelated costs account for most of the remainder), adopting a more expensive fuel cycle scheme that includes more advanced chemical partitioning techniques (that is, above and beyond conventional reprocessing technology) and fabricating MOX fuel would have a very small impact on the levelized cost of electricity paid by consumers of electricity. A long-term interim storage option may be a preferred alternative; this approach could be viewed as a long-term financial hedge if uranium prices spike and there are economical, safe, and secure technologies to close the nuclear fuel cycle.⁶¹
4. The current infrastructure (capacity that has already seen significant investments) for all types of chemical partitioning facilities is not fully utilized. To date, approximately 90,000 MT (of a total 290,000 MT) of used fuel has been conventionally reprocessed. Annual conventional reprocessing capacity is now approximately 5,600 MT per year, and some of this capacity is underutilized.⁶² Already deployed (though not necessarily operating) capacities include La Hague, France (1,700 MT/yr); Sellafield, United Kingdom (2,350 MT/yr); Mayak, Russia (400 MT/yr); Rokkasho, Japan (800 MT/yr); and Kalpakkam, India (275 MT/yr). Additional capacity could be deployed for both aqueous and pyrometallurgical processes.⁶³ There are expansion opportunities at the French and Russian facilities. Based on what already exists and is likely to exist (and be operational) within this time period, a shortage of conventional reprocessing or, in the future, advanced chemical partitioning capacity is not likely to become a bottleneck.⁶⁴
5. Individual policy decisions to develop indigenous enrichment and conventional reprocessing or, in the future, advanced chemical partitioning capabilities can be viewed on a case-by-case basis and do not have long-term implications. Siting new enrichment facilities or conventional reprocessing or advanced chemical partitioning facilities outside the current locations may send a negative signal, encouraging other states to pursue these technologies. Thus, analyses of potential indigenous fuel cycle facilities, while necessarily constrained by local conditions, must take the global context into account.⁶⁵
6. As a credible long-term interim storage program is developed, the geographic location for final disposal can remain in the exploratory stage, and the schedule for ultimate disposal can be deferred. Because long-term (but interim) storage is a viable technology, there are many credible scenarios for multinational storage as a relatively long-term endeavor (eighty to one hundred years). However, the siting of a long-term interim storage facility is likely to be inextricably linked to the identification of, and “early and positive” dialogue with, stakeholders on a final disposal site (or sites). Therefore, long-term interim storage can be an operative current-term back-end approach, with the full acknowledgment that progress toward establishing a final disposal site (or sites) cannot be deferred indefinitely.
7. Evolving a viable multilateral nuclear fuel supplier regime must take into account existing fuel supply arrangements. There are existing relationships among nuclear fuel suppliers and their customers; some of these relationships include conventional reprocessing (possibly, in the future, advanced chemical partitioning) and MOX services. The prospect of rolling back such services is bleak. Furthermore, the existing actors in the current fuel supply regime are likely to be key players in any future fuel cycle regime. Thus, their “buy in” to any proposed evolution of the international fuel supply market will be essential for successful and practical implementation of any such new regime.

ENDNOTES

52. On an individual, statebystate basis, some of these propositions may be at variance with policy considerations that a state may adopt to hedge future supply interruptions.

53. The 2010 edition of the so-called Red Book, the authoritative biennial report produced jointly by the Nuclear Energy Agency of the OECD (Organisation for Economic Cooperation and Development) and the IAEA, estimates the identified amount of conventional uranium resources. According to the Red Book, worldwide uranium resources, production, and demand are all increasing. Total identified uranium resources will last for more than 100 years at current consumption rates. The amount of uranium identified that can be economically mined rose to some 6.3 million tons, a 15.5 percent increase compared with the previous edition. The IAEA projects that nuclear power will expand from 375 GWe today to between 500 and 785 GWe by 2035. Such growth would cause an increase in uranium demand from 66,500 MT per year to between 87,370 and 138,165 MT. Based on geological evidence and knowledge of unconventional resources of uranium, such as phosphates, the Red Book estimates that more than 35 million MT will be available for exploitation. Given that in the entire 60-year history of the nuclear era the total amount of uranium that has been produced totals about 2.2 million MT, the availability of uranium is not a limiting factor at this stage of nuclear power development. For timescales stretching to the end of this century and beyond, the situation may be different. On that timescale, there are two options (not mutually exclusive) for dealing with potential uranium constraints: first, the fuel cycle could be closed to achieve very high (for example, above 90 percent) burn-up; second, an aggressive program could be launched to improve the ability to locate and recover uranium resources economically. A potential backstop for both options is the recovery of uranium from seawater. Currently, only Japan is pursuing this option in a significant way, and Japanese researchers are advocating recovery costs of $1,000 per kilogram. That is an order of magnitude more expensive than standard uranium production costs, but the Japanese experience suggests that an eventual goal of $150 per kilogram may be achievable. Natural uranium currently accounts for only 3 percent of the total cost of nuclear generation; thus, even $300 per kilogram would be attractive and well below the break-even cost for competition with a MOX fuel cycle scheme involving plutonium recycling in LWRs or fast burner reactors. See Richard K. Lester and Robert Rosner, “The Growth of Nuclear Power: Drivers & Constraints,” Daedalus138 (4) (Fall 2009): 19–30.

54. According to an interdisciplinary study from MIT, “The cost of uranium today is 2 to 4% of the cost of electricity. Our analysis of uranium mining costs versus cumulative production in a world with ten times as many LWRs and each LWR operating for 60 years indicates a probable 50% increase in uranium costs. Such a modest increase in uranium costs would not significantly impact nuclear power economics”; The Future of the Nuclear Fuel Cycle:An Interdisciplinary MIT Study (Cambridge, Mass.: Massachusetts Institute of Technology, September 2010), http://web.mit.edu/mitei/docs/spotlights/nuclear-fuel-cycle.pdf.

55. “This view does not reflect the argument that energy security proponents make: that enhancing ownership of uranium resources provides a security guarantee, or buffer, in case of temporal shortfalls or price spikes. If supply is interrupted, a relatively small stockpile would be needed— 200 MT of natural uranium, or 20 MT of 4.5percent enriched uranium per GWe/year (roughly 100 times smaller than BTequivalent coal, oil, or natural gas storage amounts)”; ibid.

56.The aqueous fissile streams are designed to include separated fissile plutonium.

57. Assuming all these services were available and were used as a partially open cycle, a U.S. nuclear power plant opting to use them would incur a total nuclear fuel cycle cost of at least 2.5 to 3 mills/kWh for back-end services. By comparison, the total cost for back-end services for an open or oncethrough fuel cycle is about 1.3 mills/kWh. The once-through fuel cycle includes a projected cost of disposal and long-term dry cask storage; see The Future of the Nuclear Fuel Cycle, 103.

58. Such an outcome would require a novel technological approach that would dramatically reduce the heat load and radiotoxicity of the waste packages destined for a HLW repository.

59. Various scientific researchers and their organizations are promoting a variety of advanced technologies that will have a momentous impact on solving the nuclear waste problem. Examples include the AIROX concept (being marketed today by General Atomics as a way to cap the generation of nuclear waste) and the Myrrha project (being developed and marketed by the Commissariat à l’énergie atomique as an accelerator/reactor concept to transmute nuclear waste). These technologies and many others await a favorable “proof of principle” verdict from the scientific and engineering communities. It is unclear if there will ever be investments sufficient enough to move such concepts to deployable technologies. For the purposes of achieving near-term consensus on the pressing safety and security issues pertaining to the back-end of the nuclear fuel cycle, we strongly believe that it would be counterproductive to promote these technologies as “game changers.”

60. However, Cameco’s CEO Tim Gitzel has warned that “[d]isruptions in mine production, the difficulty faced by development companies in raising funds for new mining projects, and the end of a Russian deal to supply uranium from scrapped atomic warheads may help create a supply deficit . . . and result in increases in uranium prices”; Christopher Donville, “Cameco’s Gitzel Says Investors Underestimate Possible Uranium Shortfall,” Bloomberg, December 5, 2011.

61. At present, advocates for using MOX assert that, at minimum, plutonium and uranium credits offset the added cost of fabricating MOX fuel.

62. Sellafield’s continued conventional reprocessing operations are currently at risk. On August 3, 2011, the National Decommission Authority (NDA) announced that it would close the Sellafield MOX plant, citing the significant negative impact to the Japanese nuclear industry in the aftermath of Fukushima.

63. The Korean Atomic Energy Research Institute’s (KAERI) advanced used-fuel conditioning process, known commonly as a pyrometallurgical process, is at the heart of negotiations for the renewal of the bilateral U.S.Republic of Korea nuclear cooperation agreement. KAERI plans to deploy a firststage facility in 2016 and become a commercial-scale demonstration plant in 2025. Further, one must keep in mind China’s eventual back-end plans and intentions, which are not likely to be firmly settled within the next decade while China thoroughly examines its technological options.

64. With regard to China’s expansion plans, it is possible (looking out several decades) that servicing China’s used fuel would require significant new conventional-reprocessing capacity.

65. We believe that an informal minimum threshold of 10 GW should be adopted before a state pursues front-end or back-end nuclear technologies.