New Projects, Nuclear, Reactors

Executive Roundtable on New Nuclear

Issue 11 and Volume 113.

Five executives share their thoughts on building new nuclear plants in the U.S. after a decades-long hiatus.


Site work for Southern Co.’s two new nuclear units at the Vogtle site in Georgia, where Units 1 and 2 have been in operation since the late 1980s. The project received its early site permit from the Nuclear Regulatory Commission in August and could be one of the first new nuclear plants built in the U.S. in decades. Photo, Southern Co.
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Power Engineering invited executives from Southern Co., UniStar, Entergy, Duke and NRG Energy to discuss their plans for building new nuclear units.

In a series of interviews, senior editor Nancy Spring spoke with Jim Miller, III, chairman, president and CEO, Southern Nuclear Operating; George Vanderheyden, president and CEO, UniStar Nuclear Energy, a Constellation Energy and EDF company; Mike Kansler, president and chief nuclear officer, Entergy Nuclear; Bryan Dolan, vice president of nuclear plant development, Duke Energy; and Steve Winn, CEO, Nuclear Innovation North America LLC (NINA), a partnership between NRG Energy and Toshiba. Condensed here, transcripts of the complete interviews are published in Power Engineering magazine’s Nov. 17 electronic newsletter.

Q: How important is getting a Department of Energy (DOE) loan guarantee?


James H. Miller, III, Chairman, President and CEO, Southern Nuclear Operating
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Miller: We feel strongly that the DOE loan guarantees are helpful to America, and I mean America as a whole, not just the nuclear power industry. But while the Vogtle project is a finalist in the loan guarantee program, in the final analysis—and I’ve said this on Capitol Hill—we are not depending on it to go forward. The Vogtle project is comprised of Georgia Power, Ogelthorpe Power Corp., the Municipal Electric Authority of Georgia and Dalton Utilities. There’s more than just Southern and Georgia Power in the mix and [we have] a long history of working together. Virtually every electric supplier in the state of Georgia finds its way into Vogtle 3 and 4, so it’s a state-wide effort.


George Vanderheyden, President and CEO, UniStar Nuclear Energy, a Constellation Energy and EDF company
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Vanderheyden: Federal loan guarantees are absolutely critical to our proposed new project at Calvert Cliffs in southern Maryland. We’re very pleased that the DOE has accepted us as one of the final four prospects for a loan guarantee. It’s become very clear to us given what’s going on in the greater economy—not just the U.S., the global economy—that private equity has no interest in investing in this project right now and the financial markets are not able to support a nuclear energy facility at this stage. It’s my firm belief that without a federal loan guarantee there literally would not be any new nuclear being pursued in this country.


Michael R. Kansler, President and Chief Nuclear Officer, Entergy Nuclear
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Kansler: When we were first going down this road that was one of our criteria, but I think it’s more important to make sure you have the right regulatory treatment in the area that you’re in—and it would be nice to have some partners to share in some of that financial risk.


Steve Winn, CEO, Nuclear Innovation North America LLC, a partnership between NRG Energy and Toshiba
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Winn: I think it’s critical. There are a couple of constraints on the finance markets in general when it comes to new nuclear. If you build one unit, you might be financing $4 billion to $5 billion worth of construction loan and then rolling that into a permanent financing and the U.S. financial markets are not quite ready for that. Even in a regulated environment, the amount of rate increases and the amount of new issuance required would cause the rating agencies and the financial markets to question, or to at least have limited appetite for, the total size of this the first time through. A loan guarantee of some sort—in our case through the U.S. government, through the Japanese government or both—is critical to get these first few plants done.

Q: When you consider a construction project of this size, what worries you the most?

Miller: It’s just the sheer logistical issues because of the many thousands of steps that have to be made. We get equipment literally from all over the world. Not all the buying has been done yet, but we estimate about 50 percent of the equipment will come from outside the U.S., so that’s a transportation problem, just making sure it gets here on time, at the right place. We’ve done construction projects and we know how to do that, but you have to stay up late at night worrying about things that can go wrong.

Let me add one thing. We’re not the first Westinghouse AP1000 under construction. There are four units under construction in China and we have the opportunity to draw on the Westinghouse expertise.

In round numbers, it will be about a $14 billion capital investment in Georgia, so if you are looking for a stimulus package, all you’ve got to do is look at Vogtle 3 and 4.

Vanderheyden: The thing you worry the most about is how many things are going to be first-of-a-kind, how many issues are you going to be the guinea pig for, so to speak, figuring out how to construct this new advanced nuclear technology. Critical to our decision-making to pick the U.S. EPR was the fact that it is already being built in Finland and the second plant is under construction in France. My guess is within the next quarter of the year there will be an announcement that they poured safety-related concrete and full construction of the Chinese EPRs will be underway. We have the opportunity to learn right now from three EPRs already under construction before we ever start Calvert Cliffs.

Our second most significant concern with the construction program is where we’re going to get the sufficient number of qualified workers to actually build the plant. We secured a project labor agreement with the building and construction trades in the AFL/CIO in April. We’re the first entity in the U.S. to have such an agreement with the labor unions. They are guaranteeing us that they will bring the skills and workers from anywhere in the country necessary to build this project. The intent is to deploy the sufficient number of union laborers that we need on the first project. From there we replicate that unit after unit after unit.

Kansler: We haven’t taken on this kind of construction project in the nuclear business in a long time, so finding the right expertise in the craft and the engineering and the construction management is going to be a chore because those guys are few and far between. They built those units 20, 30 years ago and we’re going to have a whole new crop of workers and management to run these projects. The sheer size of it worries me and also to make sure that we’ve learned lessons from our construction forays back in the seventies and eighties so that we don’t stumble on quality control issues and engineering and technical issues, and the project can go along smoothly.


Bryan Dolan, Vice President of Nuclear Plant Development, Duke Energy
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Dolan: Like any project, you want to have a well thought-through schedule and a good plan for managing the unknowns and the uncertainties. It’s all about a quality plan and a quality schedule and a quality risk management plan.

Winn: Our approach to nuclear development is about risk mitigation. In a regulated environment, it seems that the risk some of the developers are taking is around first-of-a-kind technology, incomplete design and a less straightforward licensing process because the design is not previously certified. On the other hand, they have the regulatory compact that allows for some level of guaranteed recovery. In our case, because of the design choice we made, we have limited first-of-a-kind engineering risk and less licensing risk, but since it’s in a merchant environment, slightly more exposure to the requirement to sign up long-term PPAs (purchased power agreements).

Q: Would it help if more major components were manufactured here in the U.S.?

Miller: Reactor vessels for Vogtle 3 and 4 will come from Japan and Korea, steam generators from Korea, heat exchangers from Italy. One of the things the nuclear renaissance in the U.S. will bring back to America is the skillset to make big, heavy pieces of equipment needed in an industrialized economy. We’ve let that skillset slip away, but Areva, Northrup Grumman, Babcock & Wilcox are all back, actively seeking to get back into the equipment and materials manufacturing process and that’s helpful to the entire country.

Vanderheyden: One of UniStar’s focus areas has been recreating the manufacturing infrastructure in the U.S. necessary to successfully build more than just one nuclear power plant. Our intention is to build a minimum of four identical nuclear power plants at various places in the country about a year or two apart. The plans will be standardized. That gives manufacturers of large and small components a very reliable sort of backlog of work that they can bid on. By getting that economy of scale of four units together, the manufacturers benefit and [we] benefit because we get better pricing.

We require in every one of our major contracts that the manufacturer recommits and re-opens U.S. manufacturing capability. Our first success was with our turbine generator manufacturer, Alstom. We signed a contract with them for four turbines, generators, condensers and some of the balance-of-plant components, which was close to a $1 billion contract. For that, Alstom has agreed to invest more than $200 million in their Chattanooga, Tenn., facility, creating about 350 new jobs, and they are going to bring their turbine manufacturing and assembly and balancing capability back to the U.S.

The other big one is the Areva Northrup Grumman facility in Newport News (Virginia). They plan to invest more than $360 million and create about 550 new jobs. Areva is our technology provider and we’ll have a very long-term relationship with them. We’re willing to invest in companies that are willing to invest in America.

Kansler: It would help the U.S. economy and it would be great for the U.S. to take the leadership role in the manufacturing sector for nuclear, but in reality it really doesn’t matter where it comes from as long as it gets here on time. I’d much rather see it being done in the U.S. because you can have a little more hands-on during the actual fabrication of the components, but it’s not a necessity.

Dolan: From our perspective, what’s most important is that we have quality components that can meet our schedule requirements. With new entrants coming into the market, that will give us greater assurance of that happening and enhance the competitiveness of the different suppliers.

Winn: Of the cost of a nuclear plant, about 50 percent will be labor and that will occur in the U.S., so the labor component will be from the U.S. anyway. Of the remaining 50 percent, which is material and equipment, between 20 percent and 25 percent will be from the U.S. just because it is cheaper to buy it here than to ship. The foreign component is between 25 percent and 30 percent and over time as the market for new nuclear components develops, it makes sense to onshore more of that, because you lower transportation costs, make it easier for the NRC [Nuclear Regulatory Commission] to inspect the facility that’s doing the work and you eliminate the potential for any foreign exchange risk. Four ABWRs [Toshiba’s Advanced Boiling Water Reactor] have been built in Japan already and there are seven more on order, so there is an existing manufacturing infrastructure for the components that we need to source. On the first units, we like the idea that the person who is selling us the equipment has actually built it before. At a minimum, 60 percent to 65 percent of the unit is sourced in the U.S. already. So then the intermediate problem will be to see how much of the remaining 30 percent to 35 percent we can pull in from Japan or overseas.

Q: How important is regulatory support?

Miller: We respect that they represent our customers, whether it’s the NRC in Washington or the Public Service Commission in our state locations, and as a result, they know when we tell them something they can rely on it as truthful and then make the appropriate decisions. They represent the customer and they see the wisdom in big baseload generation and the low cost of nuclear power. Because of that—not because of the relationship but because of the correctness of the decision—they are supportive.

Vanderheyden: What’s going on in Maryland right now is somewhat unique and that’s for Constellation Energy spokespeople to handle. But that’s really the strength of UniStar, my ability to say that. What the UniStar management team is focused on is the NRC licensing process. We are doing our license applications for the fleet of four power plants in a standardized fashion. In the technology and safety sections there are almost no differences because we are building standardized plants. In the environmental reviews of these projects there are differences because they are located at different sites. We have asked the NRC to focus all of their efforts on the Calvert Cliffs project to get that through the licensing processing as soon as possible. We have deferred resources away from the Nine Mile Point 3 COLA [combined construction and operating license application].

Kansler: If you look at the two states that could potentially be the home of a new nuclear unit, Lousiana or Mississippi, we have what I would call pretty good regulatory treatment for new construction. They are looking at construction-work-in-progress costs that accumulate during the project with the whole intent that once the project goes in service, assuming it remains prudent during its whole life, the rate shock to the customer is somewhat minimized because you’re starting to pay for it early in the cycle instead of getting one big price tag at the end when you put the project in service. The states understand that. The whole idea of the prudence reviews is they keep their hands in the project, they agree with it and your costs will be recovered.


Construction at Olkiluoto 3 nuclear power plant in Finland. The reactor is an Areva 1,600+ MWe EPR. Photo, Areva.
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Dolan: We have a very favorable set of statutes in South Carolina. It’s called the Baseload Review Act. You can go in and file the expected cost and schedule for the plant and get some assurance of recovery. It’s not a guarantee, but what it essentially does is it takes off the table the question of whether going forward is the right thing to do. We have not signed a contract and because of that we filed under a different provision that allows us to get assurance of recovery of our development costs. We received that assurance in both North and South Carolina, up to $230 million through 2009.

Winn: It depends on how you like oversight of your project to occur. If you sign a long-term power purchase agreement in the merchant market, you can build in a lot of the recovery mechanisms that exist in a regulatory framework.

From one perspective there’s more certainty during the construction phrase for a regulated company because some portion of their recovery is already occurring through a construction-work-in-process facility where they’ll get regulatory recovery for some portion of their investment during the construction process. But the downside of the regulated model is you’re open for regulatory review at the end of construction, so in the final prudency review the regulators may dissallow certain costs.

If you look at the first wave of nuclear plants, a pretty significant percentage of the ones with cost overruns were subject to regulatory dissallowance and it wasn’t necessarily clear that the regulatory model ultimately helped those utilities. We would not have had the regulatory dissallowance because we would have had a known fixed outcome at the beginning. You can make an argument either way.

The other aspect of being in a regulated market is who you are negotiating with for your return. In our case, we go to a counterparty and say this is how much the price for power is. If we can earn an excess return and still give him a fair price for power, we get to keep that excess return. In a regulated market that excess return is given back to ratepayers. My concern with that is earning a regulated return when I’m taking significantly more risk than I would on, say, a coal plant, is less appealing to me. The way the regulated guys solve that is through that consolidated construction-work-in-process facility and we solve it through an increased equity return.

Q: Is Yucca Mountain really off the table? If so, where should we go from here?

Miller: Let me be straightforward: Yucca Mountain is the best place for a long-term permanent repository for spent nuclear fuel. That is a very clear statement and belief on our part. They haven’t changed the Nuclear Waste Policy Act and the Department of Energy still has the legal obligation to accept spent nuclear fuel and they’ll just have to take their blue ribbon panel and the other studies they will do and devise a plan on a going-forward basis. In the interim, spent nuclear fuel can be and is currently very safely stored at reactor sites. The spent nuclear fuel issue is not a barrier to the nuclear renaissance.

Vanderheyden: I’ll simply tell you, I do not know. Whether we’re going to do long-term interim storage or reprocessing or what the next solution could be is a political issue in this country. It is not a technological issue, it’s not a safety issue. All over the world people know how to store used nuclear fuel and there are many places in the world where they know how to reprocess used fuel, because 95 percent of it is recyclable. Our country just hasn’t made that decision.

Kansler: I wouldn’t call Yucca Mountain 100 percent off the table. I think basically what the Obama administration has decided is, let’s back up, let’s put this blue ribbon panel together to assess what we should be doing with used fuel from the reactors. It doesn’t necessarily mean that Yucca Mountain is dead it just means that they are going to look at it again. We believe we are perfectly safe to store spent fuel in dry casks on site.

Dolan: We would support completing the license activities associated with the geological repository at Yucca Mountain. We understand the realities of what is happening with the administration, but the entire industry has invested a significant effort down this path, the site was chosen as the selected site and is a very good geological repository. We don’t think that option should be taken off the table. We think a public corporation should assume responsibility for used fuel management; something that can operate effectively outside the politics of an organization like the Department of Energy. We would support a centralized interim storage facility and we would be very supportive of pursuing reprocessing if fuel cycle economics make it cost-effective.

Winn: We have a contract with the DOE that obligates them to take the spent fuel and so we can and will store in wet storage at the site through roughly 2030 for the existing units and 2040 for the new ones. After that we’d switch to dry cask storage, which has a rated life of greater than 100 years. Sometime in the next 120 to 130 years the DOE and Congress have to decide how they want to handle ultimate waste storage. It’s not something that factors into the decision on whether to build the plant or not.

Q: Let’s talk about your choice of reactor technology.

Miller: We knew we wanted light water technology but we did an extensive technology review in 2005 and we decided on the Westinghouse AP1000 because of its design and our skillset operating Westinghouse PWRs [pressurized water reactors]. And it’s far enough in the NRC certification process. We began with a clean sheet of paper and we came up with the AP1000 as the best choice for Vogtle 3 and 4.

Vanderheyden: There are a couple of key reasons we chose the Areva U.S. EPR, or the U.S. Evolutionary Power Reactor. First and foremost, we believe it’s the safest, most secure technology available today. It has safety margins that far exceed what’s required by federal standards. This technology is costing us more than is required and we are more than willing to pay the extra capital costs that are required to get those safety margins. You don’t want the cheapest nuclear technology built in your back yard.

What really sold us on the technology was the fact that it would be built at least three, four or five times before we were building it in the U.S. The other big issue for us was that this plant would operate very, very efficiently. We’re a merchant generator; we care deeply about generating megawatts for the most efficient cost possible. The EPR is large—1,600 MW—and uses less fuel than the current designs so it reduces our fuel costs over time. The other key thing was the French and the Germans designed it for very, very short outages. We expect the outage cycles to be 12- or 24-month runs and we expect the outages to be in the 11- or 15-day range, which will generate very high capacity factors for us.


The heavy component assembly bay at Areva’s Chalon/St. Marcel facility in France. The Areva Northrup Grumman facility in Newport News, Va., is modeled after this facility. Photo, Areva.
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Kansler: The COLA applications that we put into the NRC for both Grand Gulf and River Bend were for the G.E. Economic Simplified Boiling Water Reactor, the ESBWR. We liked the inherent safety features of these machines. You’re not relying on equipment and power for them to safely shut down. In the event something goes wrong, it’s all based on physics. We liked the fact that the equipment—the number of valves and pumps—was significantly reduced from the current fleet. And they are easier to operate and they are larger units, so it would probably take less to operate them than it would the current fleet or even the advanced Gen II reactors like the ABWR.

Since we’ve delayed our projects, mainly because we couldn’t get anywhere with our vendors as far as coming to terms with moving forward with the ESBWR, we’re backing up to look at all the technologies that are out there to see what makes the best sense for our customers when we decide to move forward with a new reactor.

Dolan: We have not selected the technology for the Piketon project in the Midwest, but for the Lee site, our license application is built around the AP1000. We looked at a range of factors, like cost, schedule and synergy with our existing fleet. When we stepped back from all of that it pointed us in the direction of the AP1000. Their plan is to fold any lessons learned from the Chinese plants under construction back into our projects. It’s like having a practice run.

Winn: We like to be able to walk the lenders out to a site and show them one that’s running and say, “See, this is what we want to build.” When we evaluated the technologies, only one of the technologies had been built before and had an operating life—the ABWR has 12 years—only one had been built on time and on budget—the ABWR has been built four times on time and on budget—and only one technology had an active certification with the NRC. The AP1000 was certified by the NRC but has had some significant engineering changes to it since certification. From an operating perspective, knowing that Tokyo Electric turned on Kashiwazaki 6 and 7 and ran it at 100 percent capacity [the first non-outage year] meant that you could rely on the fact that the units worked.

Q: Could you estimate when you’ll start construction?

Miller: If you went to that plant site today you would say that construction has already begun. The Georgia Public Service Commission certified Vogtle 3 and 4 in March of last year. We were then able to begin what I call the blocking and tackling and we got our early site permit from the NRC on August 26 and had with it—and this is important—an associated limited work authorization, so we’re able to do some safety-related work. We are excavating right now, digging out 9 million cubic yards for both units. We have given Shaw full notice to proceed. We anticipate getting our COL in 2011, then additional safety-related work can be done.

Vanderheyden: Our parent companies have not yet made the decision to proceed with the project, but you can tell by this discussion that we are trying to move this project along as fast as possible. Our plans are to begin onsite preparation sometime in 2010. We are not going to begin full-blown construction until we receive the NRC license and right now that’s anticipated for 2012.

Kansler: We’re not in the first wave, we would definitely be somewhere in the second wave and in my opinion second wave is post-2020 for starting construction. We have a little bit of time to do our analysis of what are the best options—there are a lot of things you want to check off before you say we’re going to take on this behemoth and build a new nuclear reactor. It’s important for the country that the first wave does get under way to show that the process does work, that the industry can license and build these things the way they say they can because that will give a lot more people confidence.


A nuclear power plant heavy component ready for transport by barge on the Saône River at Areva’s Chalon/St. Marcel facility. Nuclear plant components are shipped all around the world. For Southern Co.’s Vogtle 3 and 4, reactor vessels will come from Japan and Korea, the steam generator from Korea and the heat exchangers from Italy. Photo, Areva.
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Dolan: Our timing really starts with our annual plan. Duke Energy Carolinas is required by North and South Carolina to submit an integrated resource plan. The plan looks at a range of scenarios and really forms the basis of what we do going forward. We submitted our annual plan to North and South Carolina on Sept. 1 and that plan had a number of conclusions related to new nuclear. New nuclear looked very favorable under a whole range of scenarios and assumptions. One conclusion was—and we’ve known this all along—that a regional approach, which is essentially a sharing in risk with a number of owners, is more favorable than going it alone just due to the sheer magnitude of a project like this.

Two of the scenarios we ran were a commercial operation date of 2018 and a commercial operation date of 2021. It showed that the commercial operation date of 2021 is better, and that’s primarily due to the softening economy. There’s no question we’ll need new nuclear for base load, it’s just a question of what’s the best timing for our customers.

Winn: We are targeting the end of 2011 or early 2012 to get a license, so we would hope to pour safety concrete shortly after that. You have to do site clearing and dig the hole and get ready so I would expect we have people actively working on the site beginning next year, doing safety-related construction early the second quarter of 2012. The units that were built in Japan were built from first safety concrete to fuel load in between 37 and 43 months, so we would expect that for the first unit we would be in operation in early 2016 and early 2017 for the second.

Q: Can there be meaningful CO2 reduction without nuclear power?

Miller: The U.S. wants to reduce CO2 emissions from power plants, but there are forest fires and automobiles and volcanos, there are many sources of CO2 besides power plants. But if you want to focus on that little slice of CO2 emissions, clearly nuclear is part of the mix going forward.

Vanderheyden: I do not believe it is possible to lower CO2 without the country making a dramatic commitment to nuclear energy as one of its main sources of power generation. My firm belief from working in the energy industry for more than 30 years is that in order for solar and wind to work, it’s going to need a very large reliable backup power supply source, which I believe should be nuclear energy.

Kansler: I believe renewables have a role to play but renewables are not baseload generation; they have to be backed up by fossil generation or nuclear because you can’t depend on them all the time. There aren’t many more rivers around the world that you can dam up to get a lot of hydropower. As far as a baseload source of electricity, until they figure out how to sequester, capture and store CO2, nuclear is the best option out there.

Dolan: I think EPRI [the Electric Power Research Institute] recently released a report that analyzed a portfolio of energy efficiency, renewables, clean coal and other technologies and nuclear played a fairly significant role. To get 41 percent reduction by 2030, new nuclear could play a role in 11 percent of that and that would require us building approximately nine plants the size of each unit we have on the drawing board and ultimately 64 GW by 2030 of new nuclear generation. In the Duke Energy Carolina service territory, we could reduce our carbon emissions by roughly 35 percent if we added two units as planned at Lee Nuclear Station. In 2008 for example, the operating U.S. nuclear plants prevented the emissions of almost 700 million metric tons of carbon dioxide had that power been generated from carbon-producing generation.

Winn: We think that new low-carbon baseload technologies are essential in the intermediate- to long-term to deal with greenhouse gases. There are 104 existing reactors in the U.S. The last one that came online entered operation in 1993, so if you assume a 40-year license life plus a 20-year life extension, that means the last of the existing nuclear fleet will be offline in 2053. Those 104 units are not emitting almost exactly the same amount of CO2 as the existing U.S. car fleet does. If we don’t replace the existing 104 reactors, assuming that they are replaced by more traditional technologies—gas and coal—it would be like adding 130 million new combustion cars to the U.S. marketplace. You’d still need 70 new units to replace the old units. Just on that alone, there has to be a nuclear renaissance, to not make the problem worse.

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Q: Any other comments you’d like to add to our discussion?

Miller: Because it is baseload, nuclear has a 40- to 60-year plant operating life. Many of the existing plants in the U.S. now will operate for 60 years and they will continue to provide that low-cost, reliable electric service. The U.S. has turned to nuclear very appropriately as the baseload generation choice of the future.

Vanderheyden: Nuclear energy was a technology invented in the U.S. and then was licensed and produced all across the globe and in the 30 years that the U.S. has not built a nuclear power plant, we have completely lost the manufacturing base of our economy and of this technology and we have given away our advantage to the rest of the world. I’ve commented on the importance that UniStar places on rebuilding the manufacturing infrastructure in the U.S. But what I haven’t commented on is that we must do this quickly. There is a limited supply of components and there is a limited supply of people that are capable of doing this and there are very limited companies that have the expertise to do it well. All those resources will go to the rest of the world and the U.S. could be left in a place where it cannot pursue nuclear energy because the rest of the world has taken all the resources. I worry about that a lot because the debate keeps on going and the timelines keep on moving out.

Kansler: I still believe that the nuclear renaissance is here. I think as we get on with these first wave projects we’re going to show that they can be done and then nuclear will come back in a big way.

Dolan: Nuclear power has excellent forward price stability. If you look at gas, heating bills and electric bills in areas that were heavily dependent upon gas in the last several years fluctuated widely because the cost of generation is so dependent on the price of fuel, whereas with nuclear, the price of uranium has very little effect on our cost of generating because the ore is just a small component of our cost of generation.

Winn: My hope is that we’re all successful so that we get these units up and operating because I think the market will be better for having competition between technologies. We need two or three victories in order for people to understand that it can be done in a disciplined fashion at a good cost in a way that can meaningfully change the climate picture for the U.S.

The Areva U.S. EPR

Areva’s 1,600 MW U.S. Evolutionary Power Reactor (EPR) is a third-generation pressurized-water reactor. Compared to older designs, the EPR boosts annual electrical output by 36 percent, cuts radiation exposure by 40 percent and uses 17 percent less fuel.


Construction of an EPR at EDF’s Flamanville-3 site in Normandy, France. EPRs are also being built at the Olkiluoto site in Finland and at Taishan, China. Photo, EDF.
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The U.S. EPR has a 60-year service life and special features including:

  • An axial economizer inside the steam generator that allows a high level of steam pressure for greater efficiency
  • A heavy neutron reflector that surrounds the reactor core, lowering uranium consumption
  • A doubled concrete shield designed to withstand the impact of a large airplane crash
  • A core melt retention system to provide corium confinement inside the reactor building.

The EPR can use different types of fuel, including mixed oxide (MOX) and can be operated at any power between 25 percent and 100 percent.

“We’re a merchant generator and we care deeply about generating megawatts for the most efficient cost possible,” said George Vanderheyden, president and CEO, UniStar Nuclear Energy. “The EPR is large and uses less fuel than the current designs.” As a result, UniStar expects outage cycles to be 12- or 24-month runs. Outages themselves are expected to be in the 11- or 15-day range, which should result in high capacity factors.

Westinghouse AP1000

The Westinghouse AP1000’s design builds on experience with the AP600. The new, simplified modular AP1000 has 83 percent less piping, 35 percent fewer pumps and 50 percent fewer valves. The AP1000 was the first Gen III+ reactor to receive NRC certification.


An AP1000 being built at the Sanman site in China. The Sanman project is the most advanced of the four AP1000s currently under construction in China. Photo, Westinghouse.
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The AP1000 has a 60-year design life and special features including:

  • Passive safety injection
  • Passive residual heat removal
  • Passive containment cooling
  • Several fuel options including MOX
  • Eighteen months between refueling

Westinghouse says that after the first units have been built, construction is expected to take 36 months from first concrete pour to fuel loading.

In October, the NRC informed Westinghouse that the company had not demonstrated that certain structural components of the AP1000 shield building can withstand design basis loads. NRC said progress on the shield building review will require the company to provide design modifications as well as testing.

Westinghouse said: “As a result of our understanding of the requirements, Westinghouse fully expected that the NRC would require additional analysis, testing or actual design modifications to the shield building. In fact, we had already begun to address certain portions of the design. We have fully committed the resources necessary to both quickly and definitively address the NRC’s concerns.”

Toshiba ABWR

The Toshiba Advanced Boiling Water Reactor (ABWR) is the evolutionary design of the last generation of Boiling Water Reactors (BWR) built in the U.S.


A schematic of Toshiba’s ABWR. Four ABWRs are operating in Japan, with seven more on order. Illustration, NINA/NRG.
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The first ABWR, TEPCO’s Kashiwazaki-Kariwa Unit No. 6, has been in commercial operation since 1996. Toshiba built Unit 6 in 51 months by using methods such as all-weather construction, prefabrication and modularization. Today’s ABWRs are built with more than 200 modules per unit, which weigh up to 1,000 tons each.

Toshiba’s ABWR features include:

  • A single-cycle, forced circulation boiling water reactor
  • Internal recirculation pumps to enhance safe operations while reducing plant size, cost and maintenance
  • A long-lived reactor pressure vessel using forged rings instead of welded plates
  • Multiple-integrated emergency core cooling systems to protect against possible loss-of-coolant situations
  • Thermally efficient, higher output turbine generator.

Four Toshiba 1,300 MW ABWRS are operating in Japan, with seven more on order.

“When we evaluated the technologies, only one of the technologies had been built before and had an operating life—the ABWR has 12 years—only one had been built on time and on budget—the ABWR has been built four times on time and on budget—and only one technology had an active certification with the NRC,” said Steve Winn, CEO, Nuclear Innovation North America LLC (NINA), a partnership between NRG Energy and Toshiba. “The AP1000 was certified by the NRC but has had some significant engineering changes to it since certification.”

G.E. Economic Simplified Boiling Water Reactor (ESBWR)

GE Hitachi Nuclear Energy’s (GEH) ESBWR is the next evolution of advanced Boiling Water Reactor (BWR) technology. The design has been simplified to improve safety and economics and increase plant security.


Schematic of the GEH ESBWR. Image, Nuclear Regulatory Commission.
Click here to enlarge image

The ESBWR features a passive safety design. Its simplified reactor design should translate into faster construction and lower costs; GEH estimates a 42-month construction schedule.

Features of the 1,520 MW ESBWR include:

  • The elimination of 11 systems from previous designs
  • Passive design features, such as passive containment cooling
  • Incorporation of operationally proven BWR features such as isolation condensers, natural circulation and debris-resistant fuel
  • 25 percent fewer pumps, valves and motors.

A GEH-designed Gen III+ reactor, the ESBWR is currently in the U.S. NRC Design Certification process.

“The COLA applications that we put into the NRC for both Grand Gulf and River Bend were for the ESBWR … We’ve delayed our projects, mainly because we couldn’t get anywhere with our vendors as far as coming to terms with moving forward with the ESBWR, [so] we’re backing up to look at all the technologies that are out there,” said Mike Kansler, president and chief nuclear officer, Entergy Nuclear.

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