Japan Moves Steadily Toward Reactor Restarts
The following is an InFocus piece published in the March 13, 2015 issue of the Nuclear Market Review.
This week marked the fourth anniversary of the March 11, 2011 tsunami-induced accident at the Fukushima Daiichi nuclear station in Japan, which led the nation to shut down all 48 of its remaining nuclear power plants. While concerns about nuclear power safety initially led to discussions of zero nuclear power generation or a dramatic reduction in operating nuclear plants, four years of rising energy costs and carbon dioxide emissions have forced Japan to reverse its course, even as it considers a future with reduced nuclear power generation. With stress tests ordered or completed at nuclear power facilities, new safety regulations and a new Nuclear Regulation Agency (NRA), the island nation is moving toward a measured return to nuclear power.
Japan Reviews 2030 Energy Goals
Japan’s new energy policy, issued in April last year by Prime Minister Shinzo Abe’s government, prioritized energy security, economic efficiency, and the reduction of greenhouse gas emissions. It reversed the previous government’s plans to gradually mothball nuclear power plants. The current government remains firm on its stance that nuclear power is an important baseload source for electricity. Prime Minister Abe continues to support the nuclear power industry and wants to restart nuclear plants that have passed upgraded safety regulations, although he wants to reduce future reliance on nuclear power. While policy discussions continue, the question that has emerged is: how much of a role should nuclear power play in Japan’s future energy mix? Today, the nation is moving toward an answer and on January 30, officials began considering 2030 targets for power generation, which includes a 15 to 20 percent contribution by nuclear power, compared to about 29 percent that was under consideration before the Fukushima accident in 2011. (A new energy plan with a 20 percent level for nuclear would be nearly the same level as renewable energy resources.) Members of a panel established by the country’s industry ministry will consider a revised energy plan and future power mix ahead of a Group of Seven meeting in June where climate change is likely to be discussed. Japan would need to have clear energy mix goals prior to this meeting to discuss its carbon emissions targets.
Regulators Clear Sendai, Takahama Plants for Restart
With safety reviews filed or underway for 19 reactors at 12 nuclear power facilities, Japan is moving steadily toward restarting the first units, which is expected to occur later this year. In September last year, the NRA granted clearance for the restart of Kyushu Electric Power Co.’s Sendai Units 1 and 2 (860 MWe PWRs); the agency is expected to complete the final inspections and appraisal of the Sendai units by June, which would permit Prime Minister Abe to offer the final approval, after receiving approvals in October and November late last year from the plant’s host community of Satsumasendai and the governor of Kagoshima Prefecture. While a June restart for the first reactors would follow April elections and give the government some flexibility in granting controversial restart approval, a spokesman for Japan’s Ministry of Economy, Trade, and Industry (METI) said earlier this year that an official restart date has not been decided. Just last month two more reactors were cleared for restart, with the NRA completing safety reviews for Units 3 and 4 at Kansai Electric Power Co.’s Takahama Nuclear Station in Fukui Prefecture. Although the NRA said the two 830 MWe PWRs meet safety requirements, two nearby prefectures are concerned about potential accidents and are demanding input into whether the restart should move forward. Kansai Electric, therefore, needs to address remaining NRA design upgrade issues and also reassure neighboring Kyoto and Shiga Prefectures about plant safety and evacuation procedures. The utility hopes to restart Units 3 and 4 later this year, possibly in November.
Lower Demand for Uranium in Post-Fukushima Period
In 2010, METI assessed the requirements of the newly revised Strategic Energy Plan of Japan. The plan prioritized energy security, environmental protection, and efficient supply, and more than doubled the share of generating capacity held by nuclear power and renewable energy by 2030, while reducing shares held by coal, natural gas, and petroleum. To achieve this, METI estimated that Japan would need to build nine additional nuclear power plants by 2020, and 14 by 2030, pushing uranium requirements above 30 million pounds U3O8 per year over 20 years. However, the events surrounding the Fukushima accident drastically altered the country’s uranium demand profile. (Editor’s Note: TradeTech has re-evaluated the impacts of Japan’s future uranium requirements and inventory management policies in its recently published Uranium Market Study 2015: Issue 1). [top]
Australian Uranium & Rare Earths Conference--Uranium Developers Focus on Costs, Long-Term Market
The following is an InFocus piece published in the July 25, 2014 issue of the Nuclear Market Review.
Junior uranium explorers gathered together with incumbent producers last week at the 10th annual Australian Uranium & Rare Earths Conference in Perth, Western Australia. Although overall attendance was reduced by ever-tightening budgets, the conference drew more than 200 participants from nearly 90 companies, including 25 uranium explorers and producers, members of the rare earths minerals community, investors, and government officials. While the mood of the conference was reflective of the uranium market’s latent price level, attendees remained positive as they focus on strategies aimed at shoring up resources and securing licenses in anticipation of readying assets for future production. With TradeTech’s Weekly U3O8 spot price at $28.50, many companies have settled into a period of preparation, positioning themselves to take advantage of better conditions in the future.
Western Australia’s Uranium Industry
Keynote speaker and Minister for Mines and Petroleum for Western Australia, the Hon. Bill Marmion, opened the conference with an overview of uranium mining activities in the state. Marmion spoke of writing the next chapter of uranium exploration in Western Australia while pointing out that, although rational people are recognizing uranium as a means to combat carbon emissions, uranium remains “an inconvenient truth.” Popular opposition to uranium remains prevalent, and despite recent political progress achieved in Western Australia and Queensland, Marmion declared that Australia needs to have a conversation regarding uranium.
Looking to the coming year, Marmion highlighted that the Western Australian government is set to position uranium and rare earths development as an economic priority. Marmion pointed out that his state is well positioned to feed into two important markets: India and the Middle East. He also spoke of Japanese Prime Minister Shinzo Abe’s recent visit to Perth, which involved discussions of a free trade agreement between Australia and Japan. Western Australia lifted its ban on uranium mining in 2008, which has spurred uranium exploration.
Juniors Continue Exploration & Plan for Production
Along with various demonstrations of exploration equipment and technologies, numerous exploration and resource development companies showcased their projects, many of them seeking investment funding for the coming year. Many presentations focused on the uranium market’s current supply and demand balance, and industry leaders described how they plan to position future production to best synchronize with the timing of what many see as an imminent price recovery.
Toro Energy’s Managing Director Dr. Vanessa Guthrie took a wider view of the uranium supply and demand balance by examining the historical relationship between demand, price, uranium supplies, and contracted production. It is this last variable that gained much attention during Guthrie’s presentation and beyond: when would the return of long-term contracting interest reduce inventories enough to provide incentive pricing for new production?
Guthrie pointed out that, working back from the point of price recovery, projects on average require around 10 years for development. Toro is positioning its JORC-compliant 76.5 million pound U3O8, six-deposit Wiluna project to take advantage of that timing, having completed drilling programs and submitted license applications for the Western Australian project over the last five years. Mining licenses have been granted for three of the project’s four tenements, and the company recently received subscription instructions from RealFin Capital Partners for the final A$500,000 (US$469,000) due under a $5 million (US$4.7 million) Subscription Agreement signed in late 2013.
Greenland Minerals and Energy Ltd. (GMEL) Executive Director Dr. John Mair provided an overview of the Kvanefjeld project, or which the company plans to draft an Environmental Impact Study and Social Impact Assessment, and submit an exploitation license application by 2015. The Kvanefjeld deposit contains JORC-compliant resources of 575 million pounds U3O8 and has an expected capital cost of US$450 million.
Greenland repealed its long-standing uranium mining ban in 2013, and subsequently, the Kvanefjeld project stands to become one of the world’s largest uranium and rare earths production centers. Greenland and Denmark are working toward a cooperation agreement while the project itself moves closer to regulatory review. GMEL owns 100 percent of the project and has had a memorandum of understanding in place with China Non-Ferrous Metal Industry’s Foreign Engineering and Construction Co. Ltd. since March 2014. Commissioning of the project could occur as soon as 2018.
Energy and Minerals Australia Ltd. (EMA) COO Julian Tapp spoke of growth in the rate of Chinese electricity consumption in the next 20 years, driven by an increase in per-capita income. Tapp highlighted current Chinese coal consumption and questioned the potential for coal to satisfy future growth in electricity demand, concluding that uranium is preferable over coal due to its environmental and cost benefits. However, the total amount of uranium required to meet the aggregated demand forecasted in Tapp’s projection outpaces all currently available supply.
EMA itself aims to satisfy some of that expected demand with its Mulga Rock project in Western Australia and, in perhaps the largest investment deal of the week, finalized a sizable equity raising campaign begun in May of this year. The company accepted $11.2 million in cash from Forrest Family Investments Pty for equivalent shares at $0.03 while converting $23.3 million worth of bank debt to equity shares at $0.038. Elimination of the company’s debt, previously managed by Acorn Capital Ltd. and its clients, Macquarie Bank Ltd., and Element Resources Fund, combined with the cash infusion, increased the company’s net assets by $34.1 million.
EMA will now move forward with a pre-feasibility study at the Mulga Rock project, which contains resources of 62.2 million pounds U3O8 and has an expected mine life of 15 years. The company expects to bring the project into the construction phase by 2016.
Bryn Jones, CEO of Laramide Resources, presented an overview of his company’s flagship Westmoreland Project, located in Queensland, Australia. The project contains a total JORC- and NI 43-101 compliant 51.9 million pounds U3O8 with potential annual production of 3 million pounds U3O8 per year for between 11 and 15 years. Laramide intends to complete a scoping study and then pursue mining permits and a partnering strategy in the coming year.
Paul Cronin, director of Anatolia Energy’s Temrezli project, provided an overview of Anatolia’s capital structure, shareholders, and management. Cronin described the project as a JORC-compliant 13.3 million pound U3O8 resource located in central Turkey, which is capable of producing 1 million pounds U3O8 per year for 10 years. Using Temrezli as a central plant, Anatolia also has regional expansion opportunities in West Sorgun and Sefaatli. Cronin also spoke of the looming supply deficit and the challenges facing new production centers as incentive prices required for new production remain out of reach. He also examined the different dynamics of the spot and term markets from a developer’s point of view, highlighting Anatolia’s expectation of increased long-term contracting in the coming years. Temrezli’s final feasibility study is slated for completion in October 2014, with production potentially commencing in 2016.
Greg Cochran, managing director of Deep Yellow Ltd., outlined his company’s projects in Namibia, including the JORC-compliant 45.1 million-pound U3O8 Omahola and 12.7 million- pound U3O8 Tubas Sand resources. The next steps for Omahola include a complete review and update of the project’s Preliminary Economic Analysis, with resource updates to follow on heap leach testing. A design drill program for the project’s MS7 deposit will commence as well. Progress has been steady at the company’s Tubas Sand project, which will employ physical beneficiation as a means of increasing asset value either via cyclone, teeter bed, or Marenica flowsheet processes.
Deep Yellow’s next steps include a plan infill and expansion drill program, and, subsequent to off-take discussions, an accelerated prefeasibility study & Definitive Feasibility Study. Today, Tubas Sand is environmentally permitted with a mining application lodged. Production by the end of 2016, is feasible with all agreements and supportive market conditions in place. Paladin Energy is a major shareholder (18.79%) in Deep Yellow, while exploration in Namibia is conducted by wholly owned Deep Yellow subsidiary Reptile Uranium Namibia.
Russel Bradford of JEM-MET provided a compelling view of project management in uranium resource development while AREVA’s Christian Polak presented an update of his company’s exploration activities in the Gobi desert of Mongolia. Aura Energy and Energia Minerals each announced the results of scoping studies for their respective projects, the Reguibat Project in Mauritania and Carley Bore project in Western Australia.
The Need for New Production
Conference participants generally agreed on the trajectory of future demand, with requirements growth and falling secondary supplies continuing to generate a notable increase in the need for new sources of uranium production. TradeTech defines the demand for mine production as Call On Mine Production (COMP). As Secondary Supply is largely price insensitive, it is deducted from total requirements to calculate COMP.
Contrasting this projected increase with today’s condition of oversupply, Paladin Energy Managing Director and CEO John Borshoff provided the audience with an analysis of the fuel market’s supply and demand balance that showcased a supply deficit in the coming years. With requirements growth forecasted through 2025, Borshoff identified a notable increase in the need for new sources of uranium production. He declared a need for the industry to support higher-cost projects in the years preceding any serious supply shortfall due to the lead-time required to bring new production online.
Paladin operates the Langer Heinrich project, 25 percent owned by China National Nuclear Corp., which has an annual production capacity of approximately 5 million pounds U3O8. Its Kayelekera project in Malawi was recently placed on care and maintenance until prices recover. Paladin has stated the project could be brought back into production with a lead-time of approximately nine months. [top]
DOE Faces More Pressure on Proposed Uranium Transfers
The following is an InFocus piece published in the July 18, 2014 issue of the Nuclear Market Review.
ConverDyn and US lawmakers are keeping the pressure on the US Department of Energy (DOE) as it prepares to release the first lot of material into the uranium market this year. Following the US convertor’s June 13 filing for declaratory and injunctive relief against DOE, part-owner Honeywell filed an injunction to block DOE’s July 15 uranium transfer, which has now been delayed until July 31, when a US District Court is expected to respond. In addition, lawmakers from uranium-producing states this week restated concerns about DOE’s uranium inventory disposition in their second letter this year to Energy Secretary Ernest J. Moniz.
ConverDyn Seeks Relief in District Court On June 13, ConverDyn, the sole US-based uranium convertor, filed for declaratory and injunctive relief against DOE and Secretary Moniz for violations of the US Enrichment Corporation Privatization Act.
Denver-based ConverDyn, a partnership between Honeywell and General Atomics, brought the action to stop DOE from unlawfully transferring large quantities of uranium currently in the US government’s inventory in various forms. The injunction, filed in the US District Court for the District of Columbia, states, “The transfers would have an immediate and ongoing impact on the market for uranium conversion services, would harm the United States’ domestic conversion industry, and threaten the United States’ energy security and energy dependence.”
ConverDyn claims the May 15 DOE Secretarial Determination is “arbitrary and capricious, and unlawful.” The new Determination will reduce sales and suppress prices of conversion services, cause higher production costs for conversion services, and drive detrimental changes in customer practices, according to the company. ConverDyn also states that DOE’s planned UF6 transfers also violate the USEC Privatization Act because the Department is not authorized to transfer the conversion or enrichment services component of the UF6, only the “natural uranium” or “low-enriched uranium” component. DOE is also in violation of the Act because it must receive fair value for the material, and DOE values the material at a price that is below fair market value, according to ConverDyn.
DOE & ConverDyn Express Their Views
In a July 7 DOE response to the ConverDyn lawsuit, Traxys, which markets US government uranium on behalf of the Department, said that “substantially all” of the uranium it expected over the next two years had been sold under futures contracts. DOE has stated that Secretary Moniz reasonably concluded that transfers of 2,705 tU (7.03 million pounds U3O8) annually from DOE’s inventories—which would amount to only 4.5 percent of total global supply—will not have an “adverse material impact” on the domestic uranium industries.
ConverDyn followed up on July 14, arguing in its court reply that “contrary to DOE’s arguments, the company will suffer serious and irreparable harm due to irreversible market impacts if DOE completes the transfers starting on July 31. The company argues that DOE applied the wrong standard in assessing adverse impacts. Rather than assess the harm from authorizing DOE’s transfers, as directed by the USEC Privatization Act, the Department turned the statutory requirement “upside-down” and instead assessed whether stopping the transfers would ameliorate all of the challenges facing the conversion industry. “In doing so, it relied on factors that Congress did not intend it to consider,” ConverDyn’s response stated. This week, Babcock & Wilcox was granted permission to file an amicus brief in the case by July 21. The court is expected to respond to the filings before the end of July.
Lawmakers Express Concerns
Members of Congress who represent uranium-producing states this week restated concerns about future DOE uranium inventory dispositions, in their second letter this year to Energy Secretary Ernest Moniz.
The July 14 letter expressed their “strong opposition” to the May 15 Secretarial Determination that authorizes transfers of DOE excess uranium inventories. The 14 US senators and representatives from five Western states asked Moniz to disclose the basis for DOE’s finding that the uranium transfers “will not have an adverse material impact on the domestic uranium mining, conversion, or enrichment industries.”
Inflation & Conversion Market Prices
Accounting for inflation, the nominal value of a kilogram of uranium as UF6 has risen dramatically in five periods: 1984-1990, 1993-1997, 2000-2005, 2011, and 2012-2013. However, accounting for inflation in the US dollar, which the US Bureau of Labor Statistics accomplishes by publishing an index with a 1982-1984 reference base, those peaks are nominal compared to 1983 dollars. It is clear that a great deal of inflation existed throughout those periods. In fact, adjusted for inflation, TradeTech’s May 31 Conversion Spot Price of US$7.50 (North America) and $7.75 (Europe) per kg spot would cost only $3.14 and $3.25 in real 1983 dollars—an 18.5 percent and 22.6 percent premium, respectively, to the June 1983 price of $2.65. [top]
Kazakhstan at Center of 2013 Uranium Production
The following is an InFocus piece published in the January 31, 2014 issue of the Nuclear Market Review.
Earlier this week, Kazatomprom released its 2013 uranium production figures and the state-owned uranium producer once again achieved significant growth in output. Kazakhstan continues to play an important role in the global uranium industry, and according to preliminary data, it will likely maintain the position as the world's largest uranium producer in 2013, a title the Central Asian nation has held annually since 2009.
Reporting 22,500 tU (58.5 million pounds) produced and 23,400 tU3O8 (51.6 million pounds) designated as exports on contracts, Kazakhstan’s total output supplied approximately 38 percent of 2013 global uranium production, according to preliminary total estimates. Accounting for its shares in various joint ventures, NAC Kazatomprom JSC itself was responsible for 12,600 tU (32.8 million pounds) or over 21 percent of global production, with 10,200 tU3O8 (22.5 million pounds) booked as sales on contracts. Revenue figures are forthcoming in the company’s annual financial report, which is expected to be released in April.
Kazatomprom’s reported 2013 production represents a 7.7 percent increase over 2012 figures (20,900 tU [54.3 million pounds U3O8 ]). In addition to its uranium production, the company also drilled 2,300 exploratory wells as part of an ongoing initiative to secure its uranium resource base. Continued exploration and increased production have some in the industry looking towards the Asian nation for signals of either continued growth or tempered production in the face of current uranium market prices.
Kazakhstan's Uranium Legacy
Kazakhstan is home to 25 percent of the world’s uranium reserves, second only to Australia. Yet, despite its vast resources, Kazatomprom has recently indicated that it intends to slow the rate of increase in uranium production it has pursued for the last decade. In stark contrast to its 2008 goal of quintupling production to over 70 million pounds by 2015, recent market conditions have compelled Kazatomprom to announce that it would curtail expansion of its uranium production and maintain output at 2013 levels. In late 2013, Kazatomprom Chairman Vladimir Shkolnik stated, “We’ve put the brakes on implementing uranium output expansions. The same goes for other elements of the fuel cycle.”
While uranium mining has been conducted in Kazakhstan for over 50 years, production has increased more than tenfold in the last decade from 4.5 million pounds U3O8 in 2000 to 58.5 million pounds U3O8 in 2013. Figure 1 shows uranium production growth from 2002-2013. Kazakhstan became the world’s leading uranium producer in 2009. Over the last decade, Kazatomprom’s revenue has increased in line with its production, achieving a noticeably rapid rise in the post-2008 period. Only recently has revenue faltered, due in large part to declining uranium prices, but it still remains above US$2 billion dollars (Figure 2). While continued increases in production are clearly being rewarded, diminishing returns are possible should prices resist a recovery in the coming years. In 2012, the majority of Kazatomprom’s sales were to China.
Exploration in the second half of the twentieth century indicated 50 uranium deposits, located in six provinces, most in the south-central regions of the country. Today, Kazakhstan is home to 16 active uranium mines—five are wholly owned by Kazatomprom and the remaining 11 are established joint ventures with AREVA, Uranium One (ARMZ), China Guangdong Nuclear Power Group, and Cameco.
A Role in the Global Nuclear Industry
The Kazakh government has pursued cooperative agreements with foreign governments and has been at the center of a Nuclear Threat Initiative proposal to create an international nuclear fuel bank (a low-enriched uranium stockpile owned and managed by the International Atomic Energy Agency available as a 'last-resort fuel reserve ' for nations developing nuclear power programs based on foreign sources of fuel supply services). Meanwhile, Kazatomprom has been active in developing facilities dedicated to water desalination, medicine, and the production of industrial consumables, in addition to its substantial uranium mining activities. In 2013, Kazatomprom opened a representative office in the USA, meant to help the company address opportunities in the North American market.
Kazakhstan currently directs the largest economy among the five Central Asian states. Since gaining independence, the country has enjoyed strong gross domestic product growth, which is expected to increase by 6 percent in 2013, 7.5 percent in 2014, and 7.1 percent in 2015, pushing Kazakhstan into the top tier of economic expansion. Underpinning this growth are initiatives such as the State Program for Accelerated Industrial-Innovative Development of Kazakhstan in 2010-2014, developed in accordance with the Strategic Plan for the Development of Kazakhstan till 2020. Kazakhstan has a deep history of involvement in all aspects of the nuclear sciences, and its latest incarnation as the world’s largest uranium producer is merely the most recent achievement by a country that looks to capitalize on a fully integrated nuclear fuel cycle services industry.
Editor's Note: An in-depth analysis of uranium production in Kazakhstan is featured in the upcoming Uranium Market Study 2014 Issue 1, in which TradeTech takes a forward-looking view of Kazatomprom’s uranium production trend.
2014: The Uranium Market & Japan in Transition
The following is an InFocus piece published in the January 10, 2014 issue of the Nuclear Market Review.
Since the earthquake- and tsunami-induced accident at Japan’s Fukushima Daiichi nuclear station in March 2011, the nuclear fuel industry has been proceeding with caution as it seeks assurances of market stability and direction. In addition to ongoing challenges to decommission the Fukushima reactors, other uncertainties, including potential Japanese inventory sales, ongoing US Department of Energy uranium inventory sales, political unrest and production cutbacks in certain regions, as well as supply-side consolidation, have continued to spur periodic market volatility. Today, the nuclear fuel market remains in a state of transition as participants continue mapping a course toward a future that sustains nuclear power growth and stability in the long term.
Japan’s Nuclear Power Sector in Transition Last month, Tokyo Electric Power Co. (TEPCO), operator of the Fukushima Daiichi nuclear station in Japan, said it would decommission two reactors at the site that were not badly damaged by the earthquake and tsunami in 2011, bowing to public pressure that the facility be permanently shut down. Workers have begun to remove fuel rods from one of the four Fukushima Daiichi reactors that were severely damaged by the March 2011 accident.
TEPCO had delayed making a final announcement regarding Units 5 and 6 (760 and 1067 MWe BWRs), while negotiations continued about the financing of the decommissioning process. The executive board has now acknowledged there will be no attempt to generate electricity from the Fukushima Daiichi plant again. While not an unexpected decision, it once again drew attention to the considerable challenges Japan’s nuclear power sector continues to face more than two years after the devastating accident at Fukushima.
In 2013, seven Japanese utilities applied for Nuclear Regulation Authority (NRA) safety inspections of 16 reactors at 10 plants. A great deal of attention is focused on this process, as passing these inspections is a prerequisite to any return to commercial operation for these units. While the NRA has claimed their safety standards will be the strictest in the world, utilities have endeavored to regain the confidence of both the public and political leaders of their respective prefectures, as the country itself comes to terms with the economic realities of life without nuclear power.
The Japanese government has taken the lead in financing the compensation for Niigata prefecture’s displaced population. So far, the government has allocated ¥9 trillion (US$86 billion) to TEPCO through its Nuclear Damage Liability Facilitation Corp. and maintains a ¥1 trillion (US$9.5 billion) reserve of emergency capital. Decommissioning the Fukushima reactors is estimated to cost ¥1.15 trillion (US$15 billion) and may take 30 years to complete. In December 2013, TEPCO announced a plan to restructure its business, accept early retirement from 1,000 employees, and off-load its compensatory obligation through the formation of a separate company, while becoming a holding company in 2016.
Before the Fukushima event, nuclear provided around 30 percent of Japan’s electricity, yet today that capacity is wholly unavailable. Figure 1 shows the state of Japan’s nuclear fleet, with approximately 10 percent of total capacity (installed and planned) lost and the balance in various states of assessment; 15.6 GWe of capacity is currently under review by the NRA.
With all plants are offline today, the country is spending an estimated ¥3 trillion (US$28.6 billion) on imported oil and natural gas in place of its lost nuclear capacity. This expense has placed great economic pressure on Japan and has created a trade deficit in a country already struggling with long-term economic stagnation. The effects are not limited to the electricity sector, either. The shutdown of Japan’s nuclear fleet has sent a ripple effect through the economy--while utilities have raised rates and imported fuels at a premium cost, communities surrounding nuclear plants have witnessed declining retail sales at businesses located near shuttered plants.
Surprisingly, some utilities themselves have remained profitable, though not by traditional retail sales of electricity alone. Five of Japan’s nine regional utilities posted a net profit for the latest reporting period, but many point to delayed maintenance work, rate hikes, and government support as the source of positive earnings. However, these results are likely unsustainable; Kyushu Electric Power Co. is posting deficits of ¥1 billion (US$9.6 million) each day as a result of its idled nuclear plants. TEPCO estimates that restarting its Kashiwazaki Kariwa station, the largest nuclear power facility in the world, could save ¥105 billion (US$1 billion) per month in fuel costs.
In 2013, the economic effects of reactor closures compounded, and utilities welcomed the opportunity to invite safety inspectors to their plants. Four utilities operating 10 PWR units at seven plants applied for inspections in August, while recently, ABWRs and BWRs have also joined the list of candidates for restart.
Officials are also warming to the idea of plants returning to operation. Haruhiko Izumida, governor of Niigata prefecture recently lifted his objections to nuclear power after TEPCO agreed to significant safety upgrades at Kashiwazaki Kariwa. TEPCO applied for inspections of Units 6 and 7 in September last year, and hopes to have all seven units in operation by 2016. Tohoku Electric Power Co. recently applied to have Onagawa Unit 2 inspected and intends to apply for inspection for Units 1 and 3 in the near future. Chugoku Electric Power Co. is seeking to have Shimane Unit 2 restarted, as well.
The NRA has stated its safety inspection process would take a minimum of six months per application; with 10 applications filed in August 2013, this self-imposed six-month deadline is fast approaching. TradeTech assumes, if utilities are permitted to restart these reactors, it will be after extensive review that could take at least six months, and likely 12 months or longer, for the first applicants, with longer review periods likely for BWR plants. Figure 2 shows 16 units currently slated for NRA safety review, with MWe capacity illustrated with green bars and assumed lifetime shown by black bars.
Projected restart dates are noted in orange, taking into account a minimum one-year review process. The effect of these 16 potential reactor restarts on Japan’s uranium requirements is estimated at approximately 5 million pounds U3O8 per year. [top]