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(26 June 2009)

Contents

The USA in 2007 generated 4388 billion kWh gross of electricity, half of it from coal-fired plant, 19% from nuclear, 21% from gas and 6% from hydro.  Total capacity is 1077 GWe.  Annual per capita electricity consumption is 12,400 kWh. 

In 2008 the 104 US nuclear power reactors generated a record 809 billion kWh and achieved an average 91.1% capacity factor.

US annual electricity demand is projected to increase from 4300 billion kWh today to 5000 billion kWh in 2030.

(NB:  US FY runs 1 Oct of previous calendar year to 30 Sept of that year.)
Background to nuclear power

The USA was a pioneer of nuclear power development*. Westinghouse designed the first fully commercial pressurised water reactor (PWR) of 250 MWe, Yankee Rowe, which started up in 1960 and operated to 1992. Meanwhile the boiling water reactor (BWR) was developed by the Argonne National Laboratory, and the first commercial plant, Dresden-1 of 250 MWe designed by General Electric, was started up in 1960. A prototype BWR, Vallecitos, ran from 1957 to 1963. 

* The first nuclear reactor in the world to produce electricity (albeit a trivial amount) was the small Experimental Breeder reactor (EBR-1) in Idaho, which started up in December 1951. In 1953 President Eisenhower proposed his "Atoms for Peace" program, which reoriented significant research effort towards electricity generation and set the course for civil nuclear energy development in the USA. The Mark 1 naval reactor of 1953 led to the US Atomic Energy Commission building the 60 MWe Shippingport demonstration PWR reactor in Pennsylvania, which started up in 1957 and operated until 1982.  

By the end of the 1960s, orders were being placed for PWR and BWR reactor units of more than 1000 MWe, and a major construction program got under way. These remain practically the only types built commercially in the USA*. Nuclear developments in USA suffered a major setback after the 1979 Three Mile Island accident, though that actually validated the very conservative design principles of western reactors, and no-one was injured or exposed to harmful radiation. Many orders and projects were cancelled or suspended, and the nuclear construction industry went into the doldrums for two decades. Nevertheless, by 1990 over one hundred commercial power reactors had been commissioned. 

* Fort St Vrain was a 300 MWe high-temperature gas-cooled reactor operating 1976-89.

 

map: Nuclear Energy Institute

Operationally, from the 1970s the US nuclear industry dramatically improved its safety and operational performance, and by the start of this decade it was among world leaders, with average net capacity factor over 90% and all safety indicators exceeding targets. Nuclear share of total electricity was 781 billion kWh in 2005, just under 20% of total. 

This performance was achieved as the US industry continued deregulation, begun with passage of the Energy Policy Act in 1992. Changes accelerated after 1998, including mergers and acquisitions affecting the ownership and management of nuclear power plants. Further industry consolidation is likely.



For US nuclear plant data, see Nuclear Energy Institute web site, nuclear statistics section. 

Contents

Industry consolidation from early 1990s

There are now 104 operating nuclear power reactors in the USA.  Four more are partly built and have valid construction licenses. All US plants are either Pressurised Water or Boiling Water Reactors (PWR, BWR), generically: Light Water Reactors (LWR).

At the end of 1991 (prior to passage of the Energy Policy Act), there was 97,135 MWe of "operable" nuclear generating capacity in the United States.  In March 2009 it was 101,119 MWe.  The small increase conceals some significant changes:

As of December 2008 over 124 uprates had been approved, totalling 5640 MWe. More are pending with the Nuclear Regulatory Commission (NRC) and applications for a total of 2900 MWe more are expected by 2013.

The largest US nuclear operator, Exelon, has plans to uprate much of its reactor fleet to provide the equivalent of one new power plant by 2017 - some 1300-1500 MWe.  In addition to increasing power, many of the uprates involve component upgrades.  These improve the reliability of the units and support operating licence extensions, which require extensive review of plant equipment condition.  Exelon has already added 1100 MWe in uprates over the decade to 2009.

A significant achievement of the US nuclear power industry over the last twenty years has been the increase in operating efficiency with improved maintenance. This has resulted in greatly increased capacity factor (output proportion of their nominal full-power capacity). In 1980 the average for all US reactors was 54%, by 1991 it was 68%, in 2001 it had risen to 90.7% and in 2007 it was 91.8%.  Exelon's 17 reactors achieved a capacity factor of 94.4% in 2001.

A major component of this is the length of refuelling outage, which in 1990 averaged 107 days but dropped to 40 days by 2000. The record is now 15 days.

All this is reflected in increased output even since 1990, from 577 billion kilowatt hours to 809 billion kWh, a 40% improvement despite little increase in installed capacity, and equivalent to 29 new 1000 MWe reactors.

In addition, average thermal efficiency rose from 32.49% in 1980 to 33.40% in 1990 and 33.85% in 1999.

Ownership and management consolidation


As of the end of 1991, a total of 101 individual utilities had some (including minority) ownership interest in operable nuclear power plants. At the end of 1999, that number had dropped to 87, and the largest 12 of them owned 54% of the capacity, slightly up on 1991. With deregulation of some states' electricity markets came a wave of mergers and acquisitions in 2000-1 and by late 2005 the top ten utilities had 68% of the capacity. Utilities are seeking to pay off or write off debt so that forward costs are largely cash.

However, new investment has occurred only in states which have deregulated their systems to rely on markets for pricing of electricity. There has been no sale of plants in states with traditional US cost-plus pricing.

Acquisitions have been skewed toward plants in regions with high electricity rates due to the potential for higher profit margins if the plants' production costs can be reduced. Of the 5,900 MWe involved to mid 2000, half was associated with plants having 1998 production costs above 2.0 cents per kWh. Sellers tended to consider the higher-cost plants as potential liabilities and were willing to get rid of them for a fraction of their book value, whereas the larger utility buyers considered the plants to be potential assets, depending only on their ability to lower the production costs. See Appendix 1: Power plant purchases.

In respect to the number of operators of nuclear plants, this has dropped from 45 in 1995 to 25 in 2007, showing a substantial consolidation of expertise.

Representing significant international rather than simply US consolidation, Constellation Energy in January 2009 accepted the Electricité de France (EdF) $4.5 billion bid for half of its nuclear power business – more than 60% of its production. The deal will give EdF a major foothold in the USA, with the share of 3994 MWe net at Calvert Cliffs in Maryland, and Nine Mile Point and Ginna in New York.  All the five reactors have been granted 20-year licence extensions, and the deal values them at about $2250/kWe net, but including fuel.  (The NY plants were bought by Constellation for $533/kW without fuel in that price earlier in the decade.)  EdF already owned 9.5% of Constellation itself, and had committed $975 million to the UniStar Nuclear Energy joint venture which it set up with Constellation to build, own and operate a fleet of US-EPR units in North America "with the … objective of leading the nuclear renaissance in the USA".   



Most of the of nuclear generation capacity involved in consolidation announcements has been associated with mergers, some of which failed due to regulatory opposition. 


The US$ 32 billion merger of Unicom and PECO Energy, the two largest owners of US nuclear generating capacity, to form Exelon was teh biggest, involving 14 reactors, plus three AmerGen units, total 17.  The 2000 merger of Carolina Power & Light and Florida Progress Corporation involved five reactors at 4 sites.  The 2001 merger of GPU with FirstEnergy (US$ 8.5 billion) involved four units.

In October 2008 Exelon bid $6.2 billion to take over NRG Energy, which owns 44% of South Texas 1 & 2, each 1413 MWe, and is planning two more units there.  A combined entity would have 47,000 MWe total, including 18,000 MWe nuclear.

Another means of consolidation has been via management contracts.  The Nuclear Management Company, a joint venture formed in 1999 by four Midwest utilities, was approved by the Nuclear Regulatory Commission as a nuclear operating company. It took over operation, fuel procurement and maintenance of eight nuclear units (4500 MWe) at six sites, which continue to be owned by the utilities, each with 20% of NMC. These remain responsible for used fuel and decommissioning. As with mergers, the main drivers for NMC were cost reductions and streamlined operations.  However, with sales of plants achieving consolidation in that way, only two plants (3 reactors) - Monticello and Prairie Island - remained with NMC and these had the same owner.  Accordingly the operating licence was transferred back to the owner and NMC was incorporated into Xcel Energy, the parent company, in 2008.


Regulation, & License Renewal

The Nuclear Regulatory Commission (NRC) is the government agency established in 1974 to be responsible for regulation of the nuclear industry, notably reactors, fuel cycle facilities, materials and wastes (as well as other civil uses of nuclear materials). Its focus is on safety.

In an historic move, the NRC in March 2000 renewed the operating licences of the two-unit Calvert Cliffs nuclear power plant for an additional 20 years. The applications to NRC and procedures for such renewals, with public meetings and thorough safety review, are exhaustive. The original 40-year licences for the 1970s plants were due to expire before 2020, and the 20-year extension to these dates means that any major refurbishing, such as replacement of steam generators, can be undertaken with confidence.

As of April 2009 the NRC had extended the licences of 52 reactors, half of the US total. The NRC was still thenconsidering 13 other licence renewal applications, and they are expected eventually for some 85 of the 103 US nuclear power reactors.

Also the NRC has a new oversight and assessment process for nuclear plants. Having defined what is needed to ensure safety, it now has a tightly-structured process to achieve it, replacing complex and onerous procedures which had little bearing on safety. The new approach yields publicly-accessible information on the performance of plants in 19 key areas (14 indicators on plant safety, two on radiation safety and three on security). Performance against each indicator is reported quarterly on the NRC web site according to whether it is normal, attracting regulatory oversight, provoking regulatory action, or unacceptable (in which case the plant would probably be shut down).

On the industry side, the Institute of Nuclear Power Operations (INPO) was formed after the Three Mile Island accident in 1979. A number of US industry leaders recognised that the industry must do a better job of policing itself to ensure that such an event should never happen again. INPO was formed to establish standards of performance against which individual plants could be regularly measured. An inspection of each member plant is typically performed every 18 to 24 months. 

Contents 

Preparing for new build

Today the importance of nuclear power in USA is geopolitical as much as economic, reducing dependency on imported oil and gas. The operational cost of nuclear power - 1.87 c/kWh in 2008 - is 68% of electricity from coal and a quarter of that from gas.

From 1992 to 2005 some 270,000 MWe of new gas-fired plant was built, and only 14,000 MWe of new nuclear and coal-fired capacity came on line. But coal and nuclear supply 70% of US electricity and provide price stability. When investment in these two technologies almost disappeared, unsustainable demands were placed on gas supplies and prices quadrupled, forcing large industrial users of it offshore and pushing gas-fired electricity costs towards 10c/kWh.

The reason for investment being predominantly in gas-fired plant was that it offered the lowest investment risk. Several uncertainties inhibited investment in capital-intensive new coal and nuclear technologies. About half of US generating capacity is over 30 years old, and major investment is also required in transmission infrastructure. This creates an energy investment crisis which was recognised in Washington, along with an increasing bipartisan consensus on the strategic importance and clean air benefits of nuclear power in the energy mix.

The Energy Policy Act 2005 then provided a much-needed stimulus for investment in electricity infrastructure including nuclear power. New reactor construction is expected to get under way early in the next decade.

In February 2007 the Electric Power Research Institute (EPRI) reported that it saw a need for 64 GWe of new nuclear generating capacity in the USA by 2030 - 24 GWe of it by 2020, with nuclear representing some 25.5% of output by 2030.

After 20 years of steady decline, government R&D funding for nuclear energy is being revived with the objective of rebuilding US leadership in nuclear technology.

 There are three regulatory initiatives which enhance the prospects of building new plants in the next few years.  First is the Design Certification process, second is provision for Early Site Permits (ESP) and finally combining the two is the Construction-and Operating Licences (COL) process.  All have some costs shared by DOE.

Design Certification

 Over the last 25 years the industry has been working closely with the NRC on certification of advanced Generation-III reactor designs. There are now four which have final Design Certification so that they can be built anywhere in USA and attract only site-specific licensing procedures.  These advanced designs are also being marketed actively overseas.  Other designs are at various stages of the certification process, at pre-certification stage or pending. 

The designs now having design certification and being actively marketed are:

-    the GE-Hitachi advanced boiling water reactor (ABWR) of 1300-1500 MWe, several examples of which are in commercial operation in Japan, with more under construction there and in Taiwan.  Some of these have had Toshiba involved in the construction, and it is now Toshiba that is promoting the design most strongly in the USA.

-    - The Westinghouse AP1000 which is the first late Generation-III (Generation III+) type.  It has a modular design to reduce construction time to 36 months and the first of them is being built in China.

Several more reactor designs are undergoing design certification or at pre-application stage:

-    GE Hitachi's Economic & Simplified BWR (ESBWR) of 1550 MWe was developed from its ABWR and has passive safety systems.  In submitting it to the NRC for design certification. Design approval is expected in 2009, with certification following a year later.

-    Areva NP has adapted its advanced EPR nuclear units from Europe for the USA.  Much of the work involved in developing this US EPR is making the necessary changes to output electricity at 60 Hz instead of the original design's 50 Hz.  A design certification application was lodged at the end of 2007, and the first unit (with 80% US content) is expected to be grid connected in 2015.  The main development of the type will be through UniStar Nuclear Energy, but other US proposals also involve it.  The 1600 MWe Generation-III+ EPR is being built by Areva in Finland and by EdF in France and has been selected for Guangdong, China.

-    Japan's Mitsubishi US-APWR design was submitted for design certification in December 2007.  This is a 1700 MWe design developed from one which is about to be built in Japan and evolved from Westinghouse technology.  The US-APWR has been selected by TXU (now Luminant) for Comanche Peak, Texas.


A fuller account of new reactor designs is in the paper Advanced Nuclear Power Plants .



Early Site Permits

The 2001 ESP program attracted four applicants: Exelon, Entergy, Dominion and Southern for Clinton, Grand Gulf, North Anna and Vogtle sites respectively - all with operating nuclear plants already but room for more. In March 2007 Exelon was awarded the first ESP for its Clinton plant in Illinois, after 41 months processing by the NRC and public review. The NRC then awarded ESPs to Entergy for its Grand Gulf site and Dominion for North Anna. Further ESP applications are pending. No plant type is specified with an ESP application, but the site is declared suitable on safety, environmental and related grounds for a new nuclear power plant.

Combined Construction-and Operating Licences (COL)

 In 2003 the DOE called for COL proposals under its Nuclear Power 2010 program on the basis that it would fund up to half the cost of any accepted. The COL program has two objectives: to encourage utilities to take the initiative in licence application, and to encourage reactor vendors to undertake detailed engineering and arrive at reliable cost estimates. For the first, DOE matching funds of up to about $50 million are available, and for the second, up to some $200 million per vendor, to be recouped from royalty.

In 2004 two utility-vendor consortia announced that they were seeking DOE funding for preparing COL applications for new reactors. A third utility-vendor partnership was formed in 2005 and rejigged in 2007.  A fourth partnership was formed early in 2008, and a fifth in February 2009:

Some utilities that are already part of the above consortia have plans to make submissions of their own. 

The COLs will be lodged with a particular design and site nominated, though the design certification need not be complete.  Dominion lodged its COL application in 2007, before full ESBWR design certification.  The NRC is expected to take at least three years to review each COL application, with decision anticipated in 2010 for the Dominion consortium and NuStart, since it originally intended to await design certification for both reactor types before choosing between them and lodging its COL application.  However, in 2007 NRC was estimating 42 months for processing the first few COL applications.

Neither ESP nor COL commits anyone to build anything, but they will expedite future plans for new build.

The Table below summarises announced and submitted COL applications.  By the end of 2008, 17 COL applications involving 25 reactor units had been lodged with NRC.  At least three more are expected in 2009.

One COL application, lodged by Exelon in September 2008 for a new site in Victoria county, Texas, was put on hold three months later after Exelon announced that it had decided to change the reactor technology from GE-Hitachi ESBWR.  Then Entergy and Dominion did the same for their ESBWR plans.  Exelon changed to the ABWR, from GE-Hitachi or possibly Toshiba.

Most of the COLs are for plants in regulated electricity markets, where state government and regulators allow utilities to adjust rates so that they can recoup financing costs of new plants over a longer period before the plants become operational.  This lowers the overall cost of each new plant and, ultimately, the price of electricity to the consumer.  Elsewhere, merchant plants are without regulated cost recovery and must bear all financing costs as part of the capital commitment, to be recovered after the plant becomes operational.

With about 15 companies and consortia prepared to lodge combined construction and operation licence applications for up to 33 new reactors, the US Nuclear Energy Institute said that they would have invested at least $2 billion by the end of 2007, and much more since.  This money is being spent on design and engineering work for new reactor types, on preparation of licence applications and in procurement of long-lead equipment such as reactor vessels and steam generators.  While not all the proposals are likely to go forward in the short term, some 40 GWe of new capacity is involved.  Financing will be a major challenge.

Other new capacity

While the focus is on new technology, TVA undertook a detailed feasibility study which led to its decision in 2007 to complete unit 2 of its Watts Bar nuclear power plant in Tennessee.  The 1180 MWe reactor is expected to come on line in 2013 at a cost of about $2.5 billion.  Construction was suspended in 1985 and resumed in October 2007 under a still-valid permit and is progressing on time and budget.  Its twin, unit 1, started operation in 1996.  Completing Watts Bar 2 utilizes an existing asset, thus saving time and cost relative to alternatives for new base-load capacity.  It was expected to provide power at 4.4 c/kWh, 20-25% less than coal-fired or new nuclear alternatives and 43% less than natural gas.

In the meantime, TVA has rebuilt Browns Ferry-1, which was shut down in 1985.  The 5-year refurbishment program also increased its power to 1155 MWe, similar to the newer units 2 & 3.  It already had an operating licence and started up in May 2007, with full operation the following month.

TVA also has a pair of uncompleted 1200 MWe PWR reactors: Bellefonte 1 & 2, and in February 2009 the NRC reinstated the construction permits for these.  However, TVA has not yet committed to completing them.  Construction was abandoned in 1988 after $2.5 billion had been spent and unit 1 largely (88%) completed.

Committing to new build

As well as the COLs, some utility companies have signed contracts with suppliers either for items of heavy equipment such as reactor vessels and steam generators, or have even proceeded to full engineering, procurement and construction (EPC) while the relevant COL applications are being processed, thus indicating a strong probability of actually building the plants concerned.  These are indicated in the COL Table, and details are in the COL appendix.

The table below lists current COL projects, and indicates where action has been taken actually to order or contract for aspects of their construction. For more details see NRC New Reactor Licensing and Appendix 2: Prospective COL applicants  

Announced COL Applications Pending  

Proponent(s) Technology MWe Site & utility -  licensee Lodgement Date Equipment contract
NRG Energy
ABWR x 2
2700
*South Texas, STP Nuclear / NRG Energy (merchant plant)
20/9/07

EPC 2/09
NuStart
AP1000 x 2
2234
Bellefonte, Alabama - TVA
30/10/07

Doosan?
Dominion
ESBWR ??
1520
North Anna, Virginia - Dominion
28/11/07

4/07
Duke Energy
AP1000 x 2
2200
Lee, South Carolina - Duke
13/12/07

Doosan?
Progress Energy
AP1000 x 2
2200
Harris, N Carolina - Progress
19/2/08
  
NuStart
ESBWR ??
1550
Grand Gulf, MS - Entergy
27/2/08

7/07
Unistar
US EPR
1600
* Calvert Cliffs MD - Unistar / Constellation (merchant plant)
7/07 and 13/3/08 

(Areva has ordered forgings)

Southern Nuclear Co
AP1000 x 2

2200
*Vogtle, Georgia - Southern

24/7/08

EPC 4/08
South Carolina Elect & Gas

AP1000 x 2

2234
Summer, SC - South Carolina Elect & Gas
31/3/08

EPC 5/08
Unistar, AmerenUE

US EPR

1600

Callaway, Fulton, Missouri - AmerenUE

28/7/08
now suspended

 (Areva has ordered forgings)
Progress Energy
AP1000 x 2
2200
Levy county, Florida - Progress
(greenfield site 15 km NE Crystal River)
30/708

EPC 12/08
Exelon
ABWR x 2
2700
Victoria county, SE Texas, Exelon (merchant plant)
3/9/08

preliminary
Detroit Edison

ESBWR

1550

Fermi, Michigan - DTE Energy

18/9/08

  
Luminant Corp
US-APWR x2
3400
*Comanche Peak Tx, Luminant / Energy Future Holdings (merchant plant)
19/9/08
Entergy

ESBWR ??

1550

River Bend LA - Entergy

25/9/08

  
Unistar

US EPR

1600
Nine Mile Point-3 NY - Constellation (merchant plant)

30/9/08
Unistar, PPL

US EPR

1600
Bell Bend, near Susquehanna, PA - PPL (merchant plant)

10/10/08

  
AEHI
US EPR
1600
Bruneau, Elmore county, Idaho, Alternate Energy Holdings Inc. (merchant plant)
Q2, 2009
  
Florida Light & Power
AP1000 x 2
2200
Turkey Point, Florida - FPL
30/6/09
Amarillo Power

US EPR x 2

3200
Amarillo, Tx, Amarillo Power (merchant plant)

late 2009

  
Blue Castle

?

?
Utah

2010

  
MidAmerican Energy
US EPR
 1600
 near Payett, Idaho, MidAmerican Energy Holdings  (merchant plant) ?  
Duke Energy / UniStar
 US EPR
 1600 Piketon, Ohio (DOE site leased to USEC) ?  
Total
34 units
44,000+
      

 * reference COL for reactor type           EPC - Engineering, Procurement and Construction agreement

NB: WNA reactor table from June 08 lists Watts Bar (1180 MWe), South Texas x2, Vogtle x2, North Anna, Summer x2, Grand Gulf or River Bend, Calvert Cliffs, & Levy county x2 - total 12 and 15,000 MWe as "Planned", on the basis of various announced commitments.

 Merchant plants are without regulated cost recovery.


Contents

Energy Policy Act 2005 

 

After much preliminary debate the Energy Policy Act 2005 comfortably passed both houses - 74-26 in the Senate and 275-156 in the House. It included incentives for the nuclear power industry including: 

Also $1.25 billion was authorised for an advanced high-temperature reactor (Next Generation Nuclear Plant) at the Idaho National Laboratory, capable of cogenerating hydrogen. Overall more than $2 billion was provided for hydrogen demonstration projects.  See later section on NGNP.

In 2006 it was spelled out that the 6000 MWe eligible for production tax credits would be divided pro-rata among those applicants which filed COL applications by the end of 2008, which commence construction of advanced plants by 2014, and which enter service by 2021.

In October 2007 DOE announced that it would guarantee the full amount of loans covering up to 80% of the cost of new clean energy projects including advanced nuclear power plants under the 2005 Energy Policy Act.  The first round of loan guarantees went to renewable energy and advanced gas (eg IGCC) projects, those for nuclear then still had to be authorised by Congress.

The Act also addressed climate change, requiring action on a national strategy to address the issue. In 2005 the USA emitted 5.9 billion tonnes of CO2 from energy use.

Contents 

Federal Loan Guarantees for New Plants

In mid 2008 the DOE invited applications for loan guarantees to support the construction of advanced nuclear power plants (up to $18.5 billion total) and uranium enrichment plants (up to $2 billion).  Loan guarantees are to encourage the commercial use of new or significantly improved energy technologies and "will enable project developers to bridge the financing gap between pilot and demonstration projects to full commercially viable projects that employ new or significantly improved energy technologies."  The loan guarantees are ultimately funded by the borrowers and are expected to act as a catalyst and reduce financing cost by demonstrating government support, without cost to the taxpayer. 
Any preliminary approvals issued in 2009 will be conditional upon the applicant receiving a COL from the Nuclear Regulatory Commission, and the first of these are not expected before 2010.
Applications were lodged in 2008, with a fee of $200,000 for the first part and $600,000 for the second part.  The DOE received 19 initial applications from 17 utilities to support the construction of 14 nuclear power plants involving 21 new reactors of five different designs.  Total capacity involved is 28,800 MWe.  The total requested came to $122 billion, significantly more than the $18.5 billion offered.  The aggregate estimated construction cost involved the 14 projects was $188 billion.  DOE also received two applications for enrichment plants, total $4 billion, against $2 billion on offer. 

In the light of the interest shown and the fact that the scheme is borrower-funded, the industry called for the amount available for power plants to be increased to $100 billion. 

Loan Guarantee Applications

  applicant Plant size MWe, type likely overnight cost first part second part
power plants Unistar Calvert Cliffs 3, MD 1600 EPR $9 Billion 31/7/08 accepted, short list May 2009
  Dominion North Anna 3, Va 1550 ESBWR
15/8/08  
  Exelon Victoria County, TX 1550 ABWR x 2   26/9/08  
  Duke Energy Lee, SC 1100 AP1000 x 2   29/9/08  
  PPL Corp Bell Bend, Pa 1600 EPR
29/9/08  
  Progress Energy Levy County, FL 1100 AP1000 x 2   by 29/9/08  
  Ameren UE Callaway, Missouri 1600 EPR   by 29/9/08 plans suspended
  Luminant Comanche Peak, TX 1700 APWR x 2   by 29/9/08 accepted
  Unistar Nine Mile Point, NY 1600 EPR   by 29/9/08 dropped out
  Entergy Grand Gulf, MA 1550 ESBWR   by 29/9/08  
  Entergy River Bend, LA 1550 ESBWR   by 29/9/08  
  NRG & CPS South Texas Project 1350 ABWR x 2   by 29/9/08 accepted, short list may 2009
  Slouthern & Oglethorpe Vogtle, GA 1100 APR1000 x 2
by 29/9/08 short list May 2009
  SCEG & Santee Cooper Summer, SC 1100 APR1000 x 2 $9.8 billion
 by 29/9/08 accepted, short list May 2009
fuel cycle USEC American centrifuge 3.8 M SWU $3.5 Billion 24/7/08 29/8/08
  Areva Eagle Rock enrichment 3.0 M SWU $2 billion 29/9/08 2/12/08

Contents 

Global Nuclear Energy Partnership (GNEP)

In February 2006 the US government announced a Global Nuclear Energy Partnership (GNEP) through which it "will work with other nations possessing advanced nuclear technologies to develop new proliferation-resistant recycling technologies in order to produce more energy, reduce waste and minimise proliferation concerns. Additionally, these partner nations will develop a fuel services program to provide nuclear fuel to developing nations allowing them to enjoy the benefits of abundant sources of clean, safe nuclear energy in a cost-effective manner in exchange for their commitment to forgo enrichment and reprocessing activities, also alleviating proliferation concerns." This was presented as a commercial and procedural complement to the Nuclear Non-Proliferation Treaty of 1970, but which also addressed global warming concerns.

GNEP goals include reducing US dependence on imported fossil fuels, and building a new generation of nuclear power plants in the USA.  Domestically, GNEP was based on the Advanced Fuel Cycle Initiative (AFCI), and while GNEP faltered with the advent of a new administration in Washington from 2008, the AFCI is being funded at higher levels than before for R&D "on proliferation-resistant fuel cycles and waste reduction strategies".  Two significant new elements in the strategy are new reprocessing technologies which separate all transuranic elements together (and not plutonium on its own) Ð starting with the UREX+ process, and Advanced Burner (fast) Reactors to consume the result of this while generating power.

The US Department of Energy offered $20 million for siting studies for used fuel reprocessing facilities which would be built under GNEP, and 13 sites were considered.

In January 2007 the DOE announced a new strategic plan for GNEP initiatives, including preparation of an environmental impact statement. It would assess three facilities: a fuel recycling centre including reprocessing and fuel fabrication plants, a fast reactor to burn the actinide-based fuel and transmute transuranic elements, and an advanced fuel cycle research facility. DOE envisaged the first two being industry-led initiatives.

The international component of GNEP meant that these first two facilities would need to be operating by about 2020 so that fuel services could commence as an inducement for other countries not to build enrichment and reprocessing plants.  GNEP involves fresh fuel supply and used fuel take-back by the USA, as well as by Japan and Russia. The plan also involves developing and deploying advanced proliferation-resistant reactors appropriate for the smaller power grids of developing countries, together with enhanced safeguards.

Encouraged by the response to GNEP, DOE proposed a two phase development for fuel recycling. In the near term it would deploy Areva's COEX process on a commercial scale. Then, after further R&D, the Urex+ process which will collect all transuranic elements (including plutonium) together for burning in an advanced burner (fast neutron) reactor. Wastes from the latter process would comprise only fission products, and thus be shorter-lived and easier to accommodate in a repository. In particular, the Yucca Mountain repository could accommodate US high-level wastes for the rest of the century rather than filling up in a decade. (See also later section Reprocessing Used Fuel)

In October 2007 DOE awarded $16 million to four industry consortia for studies by October 2009 to progress GNEP.  The largest share of this, $5.6 million, went to the International Nuclear Recycling Alliance (INRA) led by Areva and Mitsubishi Heavy Industries (MHI), with Japan Nuclear Fuel Ltd (JNFL), Battelle, BWX Technologies (now Babcock & Wilcox Company) and Washington Group International.  INRA was contracted to provide three major studies: technology development roadmaps analyzing the technology needed to achieve GNEP goals, business plans for the development and commercialization of the advanced GNEP technologies and facilities, and conceptual design studies for the fuel recycling centre and advanced recycling reactor.  Areva and JNFL are focused on the Consolidated Fuel Treatment Centre, a reprocessing plant (which will not separate pure plutonium), and MHI on the Advanced Recycling Reactor, a fast reactor which will burn actinides with uranium and plutonium.  These are the two main technological innovations involved with GNEP.  In this connection MHI has also set up Mitsubishi FBR Systems (MFBR).  INRA appears to have materialized out of a September 2007 agreement between Areva and JNFL to collaborate on reprocessing.  Its contract with DOE was extended in April 2008.

In June 2009 DOE cancelled the programmatic environmental impact statement for the Global Nuclear Energy Partnership "because it is no longer pursuing domestic commercial reprocessing, which was the primary focus of the prior Administration's domestic GNEP program."

The nuclear power industry is keen to see a permanent geological repository in operation, but also supports complementary long-term interim storage of used fuel and also development of advanced fuel processing technologies to close the nuclear fuel cycle. The latter include commercial reprocessing using proliferation-resistant technologies and development of fast reactors to consume actinides arising from this.

Internationally, the countries identified by DOE as likely participants in GNEP at both enrichment and recycling ends are the USA, UK, France, Russia and Japan. The USA and Japan agreed to develop a nuclear energy cooperation plan centered on GNEP and the construction of new nuclear power plants. (Japan also intended to participate in DOE's FutureGen clean coal project, which was abandoned but may possibly be revived.) A US-French agreement centered on GNEP was being developed, and one with Russia is in place.

Contents 

Uranium resources and mining

The USA ranks sixth in the world for known uranium resources in the category up to $130/kgU ($50/lb U3O8), with 339,000 tU (reasonably assured plus inferred resources, 2007).  Exploration expenditure more than doubled in 2007 from 2006 to $50.3 million, and maintained this level in 2008.

In the 1950s, the USA had a great deal of uranium mining, promoted by federal subsidies. Peak production since 1970 was 16,800 tU in 1980, when there were over 250 mines in operation. This number abruptly dropped to 50 in 1984 when 5700 tU was produced, and then there was steady decline to 2003, with most US uranium requirements being imported. By 2003 there were only two small operations producing a total of under 1000 tU/yr.

Most US production has been from New Mexico and Wyoming. Known resources are 167,000 t U3O8 in Wyoming, 155,000 t in New Mexico, 2000 t in Texas and around 50,000 t in Utah, Colorado and Arizona, all to $50/lb. Production potential is about 45% in situ leach (ISL), 55% conventional mining.

There was a considerable legacy of pollution from abandoned uranium mines and treatment plants, most dating from the 1940s and 1950s, and which was addressed in the 1980s.  For instance, the Uravan mill site on the San Miguel River in Colorado was designated a Superfund site and was cleaned up between 1987 and 2007 at a cost of over $120 million.  Historic mining and milling at Uravan included the production of radium, vanadium and uranium, leaving radioactive residues from the early 1900s through to the mid-1980s.  From the time Uravan mill began operating in the 1920s until it was shut down, it processed over ten million tonnes of uranium-vanadium ore, giving rise to a similar amount of uncontained tailings, and 1440 megalitres of liquid wastes were treated in the site rehabilitation program.

Uranium production from one mill (White Mesa, Utah) and five ISL operations totalled 1583 tU (1866 t U3O8) in 2006, 1748 tU (2061 t U3O8) in 2007, and 1503 tU (1774 t U3O8) in 2008 (EIA May 2009).  In 2008 Rosita became a sixth ISL production site before being shut down.

In mid 2009 the NRC issued a generic environmental impact statement (EIS) on ISL (or in situ recovery - ISR) mining in the western USA.  This will streamline but not eliminate the requirement for a Supplementary EIS for each new mine.  The NRC expects 17 applications for ISL facilities in the next couple of years, with each taking two years to process, including public participation.

Details of US uranium mining are in Appendix 3.

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Fuel Cycle


Enrichment and other front-end

There is now 14,000 tU/yr conversion capacity at the Honeywell-ConverDyn Metropolis plant.

For enrichment, the USA's 104 operating reactors require 12.7 million SWU per year, almost half of which currently comes from Russian high-enriched uranium. There is 8 million SWU/yr capacity at USEC's Paducah, Kentucky plant - the remaining one of two large diffusion plants commissioned in the mid 1950s. These represented the major US government involvement in the nuclear industry until USEC's privatisation in 1998. The Paducah plant has an electricity supply contract with TVA to 2012, and is likely to close then if its replacement at Piketon, Ohio is on schedule.

The National Enrichment Facility is a major centrifuge enrichment plant under construction at Eunice, New Mexico. It uses 6th generation Urenco technology from Europe, and was planned by the Louisiana Energy Services (LES) partnership - comprising Urenco, Exelon, Duke Power, Entergy, and Westinghouse. Construction of the $1.5 billion plant was licensed by NRC in mid 2006 and as agreed the three utilities then passed their share to Urenco which now wholly owns LES.  Utility support for the venture - initially amounting to $3.15 billion in orders - was crucial in persuading NRC that further US enrichment capacity was required beyond that provided and envisaged by USEC.

First production is expected in 2009, with full capacity of 3 million SWU/yr being reached in 2013. The new plant will be a major step forward in underwriting new US nuclear generating capacity and in ensuring security of fuel supply, with flexibility of operation enabling more energy input to produce more fuel from the same natural uranium feed if required.  In November 2008 LES announced plans to increase the capacity to 5.9 million SWU/yr, with total investment reaching $3 billion and the plant supplying half of US enrichment needs from 2015.  The incremental capacity will require NRC approval.

Then in April 2007 the NRC licensed construction and operation of USEC's American Centrifuge Plant in Piketon, Ohio.  The most recent cost estimate is around $3.5 billion,excluding finance, and utilising existing infrastructure, though a firmer cost figure will be confirmed by mid 2008. The American Centrifuge technology has been developed over many years by USEC, based on  work by the Department of Energy (DOE) in 1970s and 1980s.   The plant will be on the same Portsmouth site where the DOE's experimental plant operated in the 1980s, involving 1300 centrifuges as the culmination of a very major R&D program.  It is also the site of USEC's large Portsmouth diffusion plant which is now closed.  The prototype Lead Cascade started operation in September 2007 and the test program with it refined the design of the AC100 centrifuge machines (which are much larger than the Urenco centrifuges).  USEC expects to have the AC100 Lead Cascade with 40-50 machines in operation in the third quarter of 2009.  This AC100 Lead Cascade may later be integrated into a commercial cascade, but the machine design was superseded in 2009 by the "value-engineered AC100 machine", or ACR100 Mod 1, which will be deployed in the commercial plant, and is expected to deliver 350 SWU/yr each.

The full plant was expected to commence commercial operation by the end of first quarter 2010, reach 1 million SWU capacity a year later and achieve full 3.8 million SWU annual capacity at the end of 2012.  However, early in 2009 this was slowed pending funding through the DOE Loan Guarantee Program.  The plant will use only 5% of the power of the old diffusion plant it replaces.  The licence authorises 7 million SWU/yr enrichment up to 10% U-235, though normal levels today are only up to 5%, which is becoming a serious constraint as reactor fuel burnup increases.  In March 2009 USEC said that it had commitments for $3.3 billion of services from ten customers including leading utilities in the USA, Europe and Asia, and amounting to more than half of the initial sales from the plant.

In mid 2007 Areva Inc announced that it proposed to build a new 3.3 million SWU/yr $2 billion centrifuge plant in the USA to supply domestic enrichment services.  It submitted a licence application to NRC for this Eagle Rock Enrichment Facility in December 2008 with a view to operation early in 2014, ramping up to full capacity in 2019.  It would be similar to Areva's new French plant and would be built at Idaho Falls, near DOE's Idaho National Laboratory.  It will be owned an operated by Areva Enrichment Services LLC.  In 2009 it notified a planned doubling in capacity to 6.6 million SWU/yr.

Global Laser Enrichment: In 2006 Silex Systems in Australia and GE Energy received US government approval for development in the USA of the SILEX uranium enrichment process using laser technology. This approval clears the way for development and eventual full commercial production under a licence agreement with Silex. GE (now GE-Hitachi, GEH) is funding the development and making a series of payments to Silex. It will then pay a royalty on revenues from commercial production. GE said that "commercialisation of the SILEX enrichment technology is a crucial part of GE's long-term growth strategy for the nuclear business." SILEX was rebadged as Global Laser Enrichment (GLE).

In October 2007 the two largest US nuclear utilities, Exelon and Entergy, signed letters of intent to contract for uranium enrichment services from GEH.  The utilities may also provide GEH with facility licensing and public acceptance support if needed for development of a commercial-scale GLE plant.  GEH is preparing a GLE test loop at Global Nuclear Fuel's Wilmington, North Carolina fuel fabrication facility - GNF is a partnership of GE, Toshiba, and Hitachi, while GLE comprises GE (51%), Hitachi (25%) and Cameco (24%).  If the test loop results are positive, GEH will move ahead with full-scale production plans.  Preparations for licensing a commercial plant at Wilmington, North Carolina, envisage a start-up date of 2012, with annual capacity of 3.5 to 6 million separative work units (SWU).  In January 2009 GEH submitted the first part of its licence application for the Wilmington enrichment plant. 

New US Enrichment Capacity 

  type status capacity (million SWU/yr) start-up full production
Urenco/ LES Urenco centrifuge construction 5.9 2009 2015
USEC American centrifuge construction 3.8 2010 2012
Areva Urenco centrifuge planned 3.3 or 6.6
 2014 2019
GEH/ GLE laser planned 3.5 - 6.0 2012?  

Deconversion of UF6 DU tails from enrichment has not so far been undertaken on any large scale in the USA, but International Isotopes Inc (INIS) is planning a 6500 t/yr plant in Lea county, New Mexico, near the LES enrichment plant.  INIS plans to start construction in 2011, subject to raising capital.  Initial capacity is for about 575 cylinders of HF6 per year. 

Some 1300 to 2300 tonnes of anhydrous hydrofluoric acid with 450 tonnes of fluoride gas will be produced per year and the depleted uranium will be stored as more stable U3O8.  Preceding this proposal an agreement was signed in 2005 between LES and Areva to make use of the latter's technology in deconverting LES' DU tails.  Areva NC has operated a small deconversion plant in association with its fuel fabrication plant in Washington state.  DOE envisages further deconversion plants at Portsmouth/ Piketon, Ohio and Paducah, Kentucky.

Fuel fabrication occurs at six plants operated by Westinghouse, Areva NC and GEH, with total capacity over 4000 t/yr.

In 2009 Areva's 35 year-old Richland fuel fabrication plant was the first to receive a 40-year licence extension from the NRC.

In December 2007 the USA and Russia agreed to relax US import restrictions to the extent of specified quantities of low-enriched uranium.  These are trivial initially but jump to 485 tonnes enriched U representing some 3 million SWU per year in 2014 after the program importing blended-down Russian military material expires. This is enough to refuel nearly one fifth of present US nuclear plants.  By defining uranium enrichment as a service, not a good, a US court in 2006 opened the way to ending years of protection from Russian and EU imports. 

Military surplus and other government stocks

The US government earlier declared 174 tonnes of military high-enriched uranium (HEU) to be surplus and available for civil power generation. A start has been made on downblending this by Nuclear Fuel Services in Tennessee, and the first fuel fabricated from it has been shipped to Tennessee Valley Authority (TVA) power plants.

In 2008 DOE's National Nuclear Security Administration (NNSA )was negotiating with TVA to release a further 21 tonnes of HEU under the program, which would yield about 250 tonnes of LEU, some of which might be sold to other utilities.

In June 2007 the NNSA awarded contracts to Wesdyne International and Nuclear Fuel Services (NFS) to downblend 17.4 tonnes of HEU from dismantled warheads to be part of a new international Reliable Fuel Supply program.  NFS will dilute the material in Tennessee to yield some 290 tonnes of low-enriched uranium (4.95% U-235) by 2010. Wesdyne, the prime contractor, will then store the LEU at the Westinghouse fuel fabrication plant in South Carolina to be available for the Reliable Fuel Supply program - an international fuel reserve. In June 2009 NNSA awarded a further contract ($209 million) to NFS and Wesdyne for 12.1 tonnes of HEU which will yield some 220 tonnes of LEU by 2012.  The first batch of LEU will be available for use in civilian reactors by nations in good standing with the International Atomic Energy Agency that have good nonproliferation credentials and are not pursuing uranium enrichment and reprocessing technologies. The fuel - worth some $500 million at current prices - would be sold at the current market price. The second batch of LEU is to provide fuel supply assurance for utilities which participate in DOE's mixed-oxide fuel program utilising surplus plutonium from US weapons.  To cover the cost of the project, Wesdyne will sell a small part of the LEU on the market over a three to four year period. (The scheme is consistent with international concerns to limit the spread of enrichment technology to countries without well-established nuclear fuel cycles. Russia has agreed to join the initiative.)

NNSA in 2005 announced that it was committing about 40 tonnes of off-specification HEU to the Blended Low-Enriched Uranium (BLEU) program.  This material would be used by TVA.  

In March 2008 the Dept of Energy announced a policy for dealing with uranium which was surplus to defence needs.  The inventory, totaling nearly 59,000 tonnes of natural uranium equivalent, was as follows:

  tonnes U   Natural U equivalent
US high-enriched U from  unwanted weapons
 67.6 HEU 12,485
US natural U 5156 Natural U as UF6 5156
Russian natural U* 12,440 Natural U as UF6 12,440
Off-spec non UF6 4459 DU / Unat / LEU 2900
Depleted U > 0.35% U from historic DOE enrichment
 73,500 DU 29,950
Total     58,931

* natural uranium exchanged under the 1993 agreement whereby Russian blended-down uranium is supplied to US utilities – effectively Russian-origin stocks.

The DOE plan shows a total of 22,700 tonnes of its uranium entering global markets before the end of FY2017, but with no more than 10% of US annual requirements being delivered to the market in any one year - apart from an allocation for the first cores of newly built US reactors.  In line with this, the annual quantity coming from dismantled weapons and re-enriched depleted uranium increases steadily to reach 1920 tonnes U in 2013 and then continues at that level, totalling 15,000 tonnes U.  From 2010 to 2015, another 7700 tonnes U from Russian-origin stocks is allocated for the first cores of newly-built reactors in the USA.

The DoE will maintain a uranium reserve of 670 tonnes U - equivalent to about 20 power reactor reloads - for energy security reasons.  This will be kept as low-enriched uranium stored either at the DoE's Portsmouth or Paducah sites, or may be kept as part of a commercial entity's working inventory.

Almost half of the uranium used in US nuclear power plants currently comes from Russian weapons-grade military uranium, downblended in Russia.  Under this program, by January 2009, 350 tonnes of high-enriched uranium has become some 10,500 tonnes of low-enriched uranium for reactor fuel, representing 65 million SWU of enrichment and about 14,000 warheads, at a cost of US$ 5.5 billion (paid by electricity consumers).

The US government has also agreed to dispose of 34 tonnes of weapons-grade plutonium by 2014, incorporating it (with depleted uranium) into mixed-oxide fuel. Duke Energy has used four mixed oxide (MOX) test fuel assemblies incorporating this weapons-grade plutonium (fabricated in France) at its Catawba-1 nuclear power reactor.  This was to prepare for possible use of MOX for 20-40% of the cores of Catawba and McGuire reactors from about 2010, using fuel fabricated in the USA from surplus weapons plutonium - now totalling 61.5 tonnes. 

Construction of the new MOX plant for this at the DOE Savannah River site in South Carolina was authorised by NRC early in 2005 and construction started in August 2007 when funding became available.  It is being built by Shaw Areva MOX Services under a $2.7 billion contract to the DOE's National Nuclear Security Administration, which will own the plant. (Most MOX plants use fresh reactor-grade plutonium comprising about one third non-fissile Pu isotopes, this uses weapons plutonium with more than 90% fissile isotopes.)

Weapons-grade plutonium in MOX test assemblies has been burned at the Saxton prototype reactor in the mid 1960s, and some MOX was burned in other US plants before 1977.

(see also paper on Military Warheads as a Source of Fuel)

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Nuclear Wastes 

US policy since 1977 has been to forbid reprocessing of used fuel and to treat it all as high-level waste, which the government is responsible for finally disposing of in a deep geological repository. Utilities have paid over $19 billion into the Nuclear Waste Fund for this, mostly through a 0.1 cent/kWh levy towards final disposal, so that by September 2008 it had accumulated over $31 billion, including interest. The fund is growing by about $750 million per year from utility inputs and $900 million from interest.

It is the responsibility of utilities to store this used fuel on site until it is taken over by the federal Department of Energy for final disposal in a geological repository. Such a repository is not yet available and the DoE defaulted on its 1998 deadline to start accepting used fuel, which has put pressure on storage space at many power plants.

In mid 2009 there is still no national repository, and the well-advanced plans for one have been put on hold by presidential decree.  This is simply the latest in a series of blocking moves compounded by lack of resolve in Washington.*

* After several years of failure to get matching bills through both houses of Congress, early in 2000 the House of Representatives finally passed the Nuclear Waste Policy Amendments Act 2000 by 253 votes to 167, matching the earlier Senate passage of the legislation by 64 to 34. However, the President then vetoed it.

The Bush Administration sought to make some urgent headway on the matter, and several reports in 2001 suggested no insurmountable scientific or technical problems with the proposed repository site in Nevada. The US Energy Secretary recommended that the site be approved as the nation's permanent repository. This was strongly supported by Congress and signed into law in July 2002.  The DOE submitted a licence application to the Nuclear Regulatory Commission in June 2008.

A 70,000 tonne high-level waste repository has been planned at Yucca Mountain in Nevada. This would take 63,000 tonnes of used reactor fuel, 2333 t of naval and DOE used fuel and 4667 t of other high-level wastes, all from 126 sites in 39 US states. As of 2008, there was some 58,000 tonnes of civil used fuel awaiting disposal and about 12,800 tonnes of government used fuel and separated high-level wastes.  The total increases by about 2500 tonnes per year.  Recent studies by the Electric Power Research Institute show that the repository could hold at least 286,000 tonnes and possibly 628,000 tonnes of used fuel and high-level wastes, rather than the arbitrary 70,000 tonnes set by Congress in 1982.

Meanwhile storage space at some operating nuclear reactors has run out and at 40 of the 65 nuclear sites pool storage is being supplemented with dry cask storage.  Of the total inventory of 58,000 tonnes of used fuel, 10,700 tonnes was in dry cask storage as of early 2008.  By 2017 it is anticipated that practically all nuclear power plant sites will need dry storage which will then hold 22,300 tonnes of used fuel.  

Under new standard contracts with DOE, proponents of new reactor construction must undertake to store used fuel on site indefinitely, so that DOE does not become liable for delays.  The contracts specify that DOE will begin removing used fuel within 20 years of the first refueling.  As of January 2009, 19 such contracts had been signed under the NRC’s Waste Confidence Rule.  They are a prerequisite for new reactor licensing and for licence renewals, and reflect the degree to which the NRC is confident that used fuel from US power reactors can be safely managed.  The rule states that the NRC is confident that a repository (not necessarily Yucca Mountain) will be available 50 to 60 years after a reactor operating licence expires.

Before budget cuts and policy announcements early in 2009 which threatened to abort the project, the latest DOE estimate of when Yucca Mountain repository might be operational was about 2020-21, with some expansion of the original 70,000 tonne capacity.  The total cost in mid 2008 was put at about $96 billion (in 2007 dollars) for its construction, operation for 110 years, decommissioning from 2133 and the transport of used fuel to it.

The increased storage costs at nuclear plants due to the DOE defaulting on its obligation to start taking used fuel from utilities in 1998 have prompted legal action.*

 *In 2004 Exelon reached agreement with the US Justice Department on recovering up to $300 million in storage costs for its used fuel to 2010. The agreement covered all of Exelon's 17 nuclear reactors, and the cash came from tax monies, not the Nuclear Waste Fund. In 2006 the US Federal Court awarded $143 million in damages to three related New England utilities and $40 million to the Sacramento Utility District for the same reason - the former had had to build dry storage facilities. Then $43 million was awarded to Pacific Gas & Electric.  In 2007 Duke Energy negotiated $56 million on same basis for three plants, plus ongoing costs. Then Xcel Energy was awarded $116 million for costs associated with three reactors from 1998 to 2004 and Entergy Arkansas was awarded $48.6 million for costs to 2006.  Progress Energy was awarded $82.8 million in 2008.  Other utilities have been suing the federal government to achieve the same result and billions of dollars are involved.

The failure of DOE to relive the utilities of used fuel as legally required has led to the industry calling for reform of the DOE civil nuclear waste program by creating a new government entity to assume all obligations for used fuel.  It is suggested that the new entity should enter into a public-private partnership which builds interim storage and recycling facilities.

As well as the DOE Yucca Mountain enterprise, Private Fuel Storage LLC (PFS) planned to store used fuel on a site in Utah for up to 40 years pending disposal. PFS is a consortium of eight utilities impatient with DOE. In February 2006 the NRC issued a 20-year licence for a 40,000 tonne centralised surface dry storage facility on land owned by the Skull Valley band of the Goshute Indians.*  But ongoing state government opposition led to the Department of Interior then disapproving the Goshute-PFS lease and the use of public land as a transport corridor to the planned facility.  This decision is being appealed but the proposal is not proceeding.

* PFS then offered the facility to the Department of Energy for use from 2008 pending Yucca Mountain repository opening, suggesting that it would be very much cheaper for DOE than leaving the used fuel at reactor sites.  While fuel ownership was originally intended to remain with utility customers, the proposal to DOE was that it would take ownership at the reactor site (as was legally required by 1998) and be responsible for moving it to PFS, and ultimately to Yucca Mountain. 

In the light of this the Nuclear Energy Institute in 2007 started a search for communities willing to host interim storage sites for used fuel.  It received several offers and by mid 2008 had reduced the possibilities to two.  A commercially operated facility on a 400 ha site is envisaged for each.

In 2005 a National Academies' report on security of interim storage of used fuel at US reactors was released. It said that some pool storages at reactors may pose a risk due to possible high temperature combustion of fuel cladding in the event that water is drained due to terrorist attack, but that the likelihood of terrorists using spent fuel for a 'dirty bomb' is very low. The report strongly favoured dry cask storage on security grounds. The NRC and the industry said that the report exaggerated the risks and did not take full account of safety measures implemented since 2001.

In 2006 the National Academies reported on transport of high-level wastes, finding that there are "no fundamental technical barriers to the safe transport of spent nuclear fuel and high-level radioactive wastes in the US". It said transport by road or rail was low-risk radiologically due to "rigorous international standards and US regulations" on packaging it.

For low-level wastes (LLW)* there is a facility at Barnwell, South Carolina, for LLW from that state, New Jersey and Connecticut and another run by EnergySolutions at Clive, Utah, which accepts class A LLW (about 90% of all LLW) from all over USA.  A new one was licensed in Texas in 2009, for class A, B & C LLW and run by Waste Control Specialists, which will also take Vermont's and DOE LLW.  The company is also seeking to take LLW from other states.  Otherwise storage is at reactors. 

*Class A low-level waste contains radionuclides with the lowest concentrations and the shortest half-lives; Classes B and C contain greater concentrations of radionuclides with longer half-lives.  Class A LLW must be contained for up to 100 years, Class B waste for up to 300 years and Class C waste for up to 500 years. 

Reprocessing used fuel   

Despite US policy forbidding reprocessing, new energy bills in 2005 explicitly revived the prospect. In particular the report accompanying the $31 billion energy and water funding bill approved by the Senate Appropriations Committee in June 2005 emphasised the need for new nuclear energy technologies. DOE's Advanced Fuel Cycle Initiative (AFCI) would receive $85 million to develop fuel cycle technologies for Generation IV reactors including reprocessing and using fast neutron reactors to destroy long-lived components of wastes.  A major driver for reprocessing is reduction in the volume of high-level wastes, possibly obviating the need for any stage 2 of the Yucca Mountain repository.

Apart from military experience with metal fuel, the USA has some experience with reprocessing oxide fuels - the small West Valley NY plant operated 1966-72, and a 1500 t/yr plant at Barnwell SC was built but not commissioned due to changed government policy. It is now demolished.

Part of the Senate's AFCI allocation was earmarked to study "deep burn-up of nuclear fuel" and related research. This is a General Atomics concept which involves incorporating separated actinides from reprocessing into refractory fuel particles which can be used in high-temperature reactors. (Fuel for these reactors is in the form of TRISO particles less than a millimetre in diameter. Each has a kernel of uranium oxycarbide, with the uranium enriched up to 14% U-235. This is surrounded by layers of carbon and silicon carbide, giving a containment for fission products which is stable to 1600¡C or more.) The long-lived actinides incorporated into such fuel would be turned into short-lived fission products. It is claimed that 95% of the plutonium-239 and 60% of the other actinides would be destroyed.

Under AFCI the Argonne National Laboratory is planning an engineering-scale demonstration of the UREX+ process for reprocessing used fuel. Several variations of this have been developed by DOE, but the idea is that it will separate out uranium, transuranic elements (plutonium, neptunium, americium & curium together), and fission products. From the last, technetium, cesium and strontium may be further separated for transmutation. The transuranics will be burned in fast neutron reactors. It is estimated that using this process, the effective capacity of the Yucca Mountain repository could be increased fivefold and much better utilisation of uranium achieved. (see also Processing Used Nuclear Fuel for Recycle paper)

Congruent with this the US Nuclear Energy Institute has said that the US nuclear industry needs to plan for recycling used fuel. This is to reduce the long-lived radioactivity arising from it so that in a relatively short time high-level wastes become no more toxic than the original uranium ore. This means recycling and burning all the long-lived actinides, which is most efficiently done in fast neutron reactors such as four of the six generation-IV designs.

In November 2005 the American Nuclear Society also released a position statement saying that it "believes that the development and deployment of advanced nuclear reactors based on fast-neutron fission technology is important to the sustainability, reliability and security of the world's long-term energy supply."  The statement envisaged on-site reprocessing of used fuel from fast reactors.

In mid 2006 a report by the Boston Consulting Group for Areva and based on proprietary Areva information showed that reprocessing used fuel in the USA for recycle, using the Coex aqueous process, would be economically competitive with direct disposal of used fuel. The cost increment relative to direct disposal is offset by the value of recycled fuel. The COEX process has been developed by Areva from that used today in the four operating reprocessing plants in France, UK, Russia and Japan. A $12 billion, 2500 t/yr plant was considered, with total capital expenditure of $16 billion for all related aspects.

Under GNEP, an engineering-scale demonstration (ESD) plant for reprocessing is planned for operation from 2011. The 10-25 t/yr ESD is designed to prepare the way for a 2000 t/yr full scale plant.

A possible site for an initial reprocessing plant is at Morris, Illinois, which is the only licensed away-from-reactor wet used fuel storage facility in USA. It is adjacent to the Dresden nuclear power plant and currently stores about 700 tonnes. It was the site of GE's Midwest Fuel Recovery Plant, a small reprocessing plant built in the early 1970s but declared inoperable in 1974. 

Contents 

Decommissioning reactors

Nearly 30 civil prototype and commercial reactors are being or have been decommissioned in the USA. A few have been totally dismantled so that the site is released for unrestricted use, notably Fort St Vrain, Big Rock Point and Shoreham. The majority are in various stages of dismantling or safestore.

The Nuclear Energy Institute reported in 2006 that of the total $32 billion estimated to decommission all eligible nuclear plants at an average cost of $300 million, about two-thirds has already been funded. The remainder will be funded over the next 20 years (the average nuclear plant is licensed for 40 or 60 years). 

See NRC Fact Sheet. 

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Government R&D

Research and Development on nuclear energy has taken place at a number of Department of Energy laboratories, as well as at universities.

In 2005 a number of nuclear energy research programs moved to the Idaho National Laboratory, (INL) formed from two existing entities on the same site - the Idaho National Engineering and Environmental Laboratory (INEEL) and Argonne National Laboratory West (ANL-W). Over 6000 employees work at the INL site.

INL focuses on advanced, next-generation nuclear power systems for both electricity and hydrogen production on a very large scale. It leads US participation in the Generation IV International Program, and will develop the US Next-Generation Nuclear Plant (NGNP) in connection with that. In 2005, $1.25 billion was authorised for the NGNP, capable of cogenerating hydrogen.

INL also plays a major role with the Office of Civilian Radioactive Waste Management in developing procedures for high-level waste disposal, envisaged to be at Yucca Mountain.

INEEL was established in 1949 as the National Reactor Testing Station and for many years had the largest concentration of nuclear reactors in the world - 52 different reactors were designed and tested there. ANL-W had been the testing site for research by the University of Chicago, and worked closely with INEEL. It also was developing spacecraft power systems for NASA. All this work was under DOE auspices.

Several of the DOE laboratory sites have legacy wastes requiring clean-up, and programs are in place to achieve this. At INEEL a major clean-up is underway and should be largely completes by 2012

Under its Nuclear Hydrogen Initiative the Department of Energy has selected two teams to investigate the economic feasibility of producing hydrogen using power from existing reactors. A following phase will involve demonstration. One team led by GE Global Research will look at the alkaline electrolysis technique and another team led by Electric Transport Applications will pursue electrolysis using proton exchange membranes, based on a pilot plant in Arizona which produces 212 m3 per day.

Related to this, the University of Texas has approved a scheme to build a $500 million high-temperature reactor at Andrews campus, based on General Atomics Modular Helium Reactor (MHR) and involving DOE's Sandia National Laboratory. A 2012 completion date is envisaged for the High Temperature Teaching and Test Reactor Energy Research Facility.

The US Energy Information Administration (EIA) published an analysis of US government energy subsidies and R&D support in 2007, totaling $16.6 billion - double the 1999 level.  Of this, $6.75 billion was related to electricity production, and $6.0 billion of this was split between R&D and subsidies.  Apart from transmission and distribution ($875 million), the balance was $1.55 billion for R&D in anticipation of future benefits and $3.55 billion in subsidies for present production.  The $1.55 billion for R&D comprised $922 million for nuclear, $522 million for coal and $108 million for renewables - which currently supply 19.4%, 49% and 2.5% (apart from hydro) of US power respectively.  Nuclear R&D comprised $319 million for new nuclear plant design and proliferation-resistant fuel cycle, $350 million for clean-up of nuclear energy and research sites and $253 million for Idaho facilities and related management.  Two thirds of coal R&D was for "clean coal" programs.

The $3.55 billion for subsidies was by way of tax credits, with the lion's share going to coal-based synthetic fuel which achieves some emission reduction.  Nuclear got $199 million and renewables $724 million (0.025 cents/kWh and 0.71 c/kWh respectively).  The nuclear subsidy was entirely due to a change in tax rules related to decommissioning, under the 2005 Energy Policy Act.  The renewables subsidy was mainly for wind, at 2.3 cents/kWh.

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Next Generation Nuclear Plant (NGNP) 

In 2004 the DOE sought a partner to develop the Next Generation Nuclear Plant (NGNP), a Generation-IV high-temperature gas-cooled reactor, as its leading concept for developing advanced power systems both for electricity and hydrogen production on a very large scale. A $2 billion pilot plant demonstrating technical feasibility is envisaged by 2021 at Idaho National Laboratory (INL) but with international collaboration.

If successful, the NGNP "will be smaller, safer, more flexible and more cost-effective than any commercial nuclear plant in history. The NGNP will secure a major role for nuclear energy for the long-term future and also provide the US with a practical path toward replacing imported oil with domestically produced, clean, and economic hydrogen." The DOE goals for a commercial NGNP are: electricity at less than 1.5 c/kwh, hydrogen at less than 40 c/litre gasoline equivalent, overnight capital cost less than $1000/kw dropping to half that.

Three companies were awarded $8 million in contracts for preconceptual NGNP design: General Atomics, Areva, and Westinghouse/PBMR. In July 2007 DOE announced that it was seeking to move to the next stage of defining safety and functional requirements, cost estimates and schedules.

The NGNP licensing plan was submitted to Congress by the DoE and the NRC in August 2008.  It features a high temperature gas-cooled reactor configured to provide heat up to 950°C for a range of industrial uses particularly hydrogen production, or electricity generation.  It would be built at Idaho National Laboratory from 2017 and could operate in 2021.  Some regulatory changes would be needed to cope with the innovative design, along with different procedures for used fuel.  NRC expects to take five years to organize for the NGNP, allowing licence application in 2013.

Three reactor designs fit the NGNP specification: General Atomics' GT-MHR, Areva's similar Antares design, and the Pebble Bed Modular Reactor (PBMR), backed by Westinghouse and  South Africa's PBMR Ltd,

Contents 

Public opinion

Public opinion has generally been fairly positive, and has grown more so as people have had to think about security of energy supplies. Polls show continuing increase in public opinion favourable to nuclear power in the USA.  More than three times as many strongly support nuclear energy than strongly oppose it.  Two thirds of self-described environmentalists favour it.

In mid 2007 a survey of 1150 people living within 16 km of nuclear power plants in the USA, but without any personal involvement with them,  showed very strong support for new nuclear plants.  Over 90% thought nuclear energy was important for future supply, 82% favoured it now, 77% said that new plants should definitely be built and 71% said they would accept a new plant near them.  There was an overwhelmingly favourable view of local nuclear plants, notably their safety.  On nuclear waste, 71% said it was safe being stored at the plant and 78% said the federal government should get on with developing the Yucca Mountain repository.  Regarding reliable sources of information about nuclear energy, various nuclear plant sources were rated 68-74% compared with environmental groups 45% and anti-nuclear groups 22%.  The researcher concluded that "Nimby (not in my back yard) does not apply at existing plant sites because close neighbours have a positive view of nuclear energy, are familiar with the plant, and believe that the plant benefits the community."  

An April 2008 survey (N=1000) found that overall 82% said nuclear power will be important in meeting the nation's electricity needs in the years ahead.  In a change since October 2007, most put economic growth ahead of climate change and energy security as a prime concern, with air pollution trailing in a list of four. Public support for building new nuclear power plants strengthened three points to 78% since October.

The survey also showed clear public support for government incentives to reduce CO2 emissions - 79% approved of providing tax credits "as an incentive to companies to build solar, wind and advanced-design nuclear power plants," and 37% strongly approved.  Only 20% did not approve. When asked about providing federal loan guarantees to companies that build solar, wind, advanced-design nuclear power plants "or other energy technology that reduces greenhouse gases, to jump-start investment in these critical energy facilities" 77% approved.

A May 2008 survey (N=2925) by Zogby showed 67% of Americans favoured building new nuclear power plants, with 46% registering strong support; 23% were opposed.  Asked which kind of power plant they would prefer if it were sited in their community, 43% said nuclear, 26% gas, 8% coal.  Men (60%) were more than twice as likely as women (28%) to be supportive of a nuclear power plant.

A March 2009 Bisconti-GfK Roper survey showed that strong public support for nuclear energy was being sustained.  In particular, 84% think nuclear will be important in meeting electricity needs in the years ahead, 84% support licence renewal for nuclear plants, 76% believe utilities should prepare to build more nuclear plants, 87% and 81% respectively approve of tax credits and federal loan guarantees to encourage new build, 70% would support adding a new reactor at the nearest nuclear plant, and 62% say that USA should definitely build more plants in the future. Only 12% of people said they strongly opposed the use of nuclear energy.  A new question focused on recycling used nuclear fuel, and 83% supported this (contra past US policy) while 13% opposed.

Contents 

Non-proliferation

The USA is a nuclear weapons state, party to the Nuclear Non-Proliferation Treaty (NPT) which it ratified in 1970 and under which a safeguards agreement has been in force since 1980.  The Additional Protocol in relation to this was signed in 1998 and ratified in 2004, though arrangements to bring it into force were not completed until the end of 2008.  While in weapons states the Additional Protocol is largely symbolic, the State Department noted that US ratification "gives us a stronger foundation from which to encourage other states to adopt the Protocol."  IAEA safeguards are applied on all civil nuclear activities.  (The USA undertook nuclear weapons tests from 1945 to 1992.) 

Contents 

Appendix 1. Power Plant Purchases 

First, in mid 1999, the 670 MWe Pilgrim plant was sold to Entergy, by Boston Edison, for $14 million plus $67 million for fuel.

Then AmerGen, the joint venture of British Energy and PECO Energy (now Exelon), completed its purchase of the 930 MWe Clinton nuclear plant and the 790 MWe Three Mile Island plant in 1999. However, its plan to acquire control of the two-unit Nine Mile Point nuclear power station (614 & 1140 MWe) was derailed by a minor shareholder exercising its veto. Constellation later bid successfully for the units.

In 1999 AmerGen won the "Boldest Successful Investment Decision" award from the Financial Times in New York. AmerGen was cited as "a huge success ... with expected strong financial returns" and "a bold investment which has created new confidence in the US nuclear industry".

In March 2000, Entergy Corporation reached agreement to buy the New York Power Authority's Indian Point-3 (965 MWe) and Fitzpatrick (778 MWe) nuclear power plants for US$ 967 million, topping a bid by Dominion Resources. The complexity of the transaction is indicated by the sum including $636 million for the two mid 1970s units, nearly $171 million for the fuel, $92 million to reduce NYPA's decommissioning obligation, and other amounts related to power purchase. There are also provisions for further payments if licences for the 25 year old plants are extended. NYPA will retain the $630 million decommissioning funds and pay them when required, while Entergy will accept the $250 million risk of any adverse tax ruling on these. Up to 500 MWe of the combined output will be available to NYPA at 2.9 cents/kWh, the remainder at 3.2 or 3.6 cents/kWh. The sale closed in November 2000.

In November 2000 Entergy became the successful bidder for ConEd's 939 MWe Indian Point-2 unit (including the shut down unit 1 and 76 MWe of gas turbine capacity). The price was $502 million plus about $100 million for fuel. ConEd will purchase the output at an average of 3.9 cents/kWh.

The price per kilowatt is very much higher than earlier nuclear plant transactions. Entergy already operated six nuclear plants, total 5654 MWe, whose three-year capacity factor exceeds 90%, underlining NYPA's assessment of Entergy as "one of the nation's premier nuclear operators". Entergy had earlier announced plans to spend US$ 1.7 billion over the next five years to buy five to eight more nuclear plants, mostly in the Northeast and Midwest, as nuclear energy becomes central to its growth strategy, expressing its "commitment to environmental leadership".

In June 2000 AmerGen received approval to purchase the elderly 650 MWe Oyster Creek plant for US$ 10 million, and the 522 MWe Vermont Yankee plant for $61 million. However, the latter deal was vetoed by state regulators and the plant was auctioned.

In August 2000 Dominion Resources agreed to pay US$ 1.3 billion in cash for the Millstone nuclear plant, about $600 for each kilowatt of generating capacity. The Northeast Utilities plant comprises the 1150 MWe unit 3 and the 858 MWe unit 2, respectively 14 and 25 years old. Unit 1, which is being decommissioned, is also included. The price includes $105 million for fuel, but only 93.5% of unit 3, since minority shareholders wish to remain.

In November 2000, Public Service Co. of New Mexico agred to purchase two Kansas utilites owning 94% of the 1170 MWe Wolf Creek nuclear plant.

In December 2000 Constellation Energy, owner of Calvert Cliffs nuclear power plant, agreed to buy Nine Mile Point for US$ 815 million, including fuel. The deal takes in unit 1 (609 MWe, started in 1969) and 82% of unit 2 ( 1148 MWe, started 1988) for $737 million, plus $78 million for fuel. This is about 3.5 times the price which had been agreed with AmerGen for the plant in 1999. Constellation has agreed to sell 90% of its output to the vendors for 10 years at about 3.5 cents/kWh. Some $450 million in decommissioning funds will be transferred to Constellation.

In 2001 PECO (now Exelon) and PSEG concluded the purchase of minor shares in five large reactors from Connectiv.

In August 2001 Entergy Corporation became the successful bidder for the 29-year old Vermont Yankee power station. Entergy paid $180 million for the 522 MWe plant, $35 million of this for fuel. It will take over both the decommissioning liability and the existing fund for this. Power will be sold to local utilities (former owners) for 3.9 to 4.5 cents/kWh to 2012. Entergy paid almost three times the price which had been agreed in 2000 with AmerGen.

In April 2002 FPL Energy became the successful bidder for 88.2% of the 12 year old Seabrook plant. The utility will pay six utility vendors US$ 836.6 million for the 1161 MWe PWR reactor, being $749.1 million for the plant (including decommissioning trust fund), $61.9 million for fuel and the balance for components of an uncompleted second unit. FPL Energy is the US leader in wind energy generation and a sister company to Florida Power & Light, which operates four PWR nuclear reactors.

In September 2003 British Energy (BE) agreed to sell its most profitable asset - the half share of US utility AmerGen, to FPL Energy for US$ 276.5 million. The proposed deal was the result of its plan to realise the value of its AmerGen equity independently of Exelon - its joint venture partner. Exelon then exercised its right of first refusal and bought the share, subject to regulatory and other approvals. The sale was required by the UK government's restructuring provisions for BE.  In 2008 Amergen was absorbed into Exelon.

In November 2003 Dominion agreed to pay $220 million cash for Kewaunee, a 540 MWe Wisconsin reactor, the figure including $36.5 million for fuel. The sale was finalised in July 2005. Some $392 million in decommissioning funds were transferred.

Also in November 2003, Constellation Energy agreed to buy the R E Ginna nuclear power plant for $401 million plus $21.6 million for fuel. The 495 MWe PWR started up in 1969 and is among the best-performing in USA. The sale was contingent upon the licence extension taking its life to 2029. A planned uprate enabled by 1996 steam generator replacement will increase capacity to 580 MWe. A sales contract commits 90% of ten years output to RG&E at 4.4 cents/kWh average.

In March 2004 Cameco Corp. agreed to buy 25.2% of the South Texas Project - two 1250 MWe PWRs which started up 1988-89 - for $279 million plus fuel, but two of the owners then exercised right of first refusal, leaving Cameco with a $7 million consolation fee.

In July 2005 FPL Energy agreed to pay $380 million for 70% of newly-uprated Duane Arnold BWR from an Alliant Energy subsidiary, which will continue to buy the power. The plant is run by Nuclear Management Co. and a licence extension application is expected late in 2008.

In July 2006 Entergy agreed to buy the 798 MWe Palisades nuclear power plant from CMS subsidiary Consumers Energy for US$ 242 million ($301/kW) plus $83 million for the fuel and $55 million for other assets. It started up in 1971 and a 20-year licence extension to 2031 was granted early in 2007. Entergy will sell all the power back to Consumers Energy for 15 years and will then own 11 nuclear power reactors and manage a 12th. Entergy will assume responsibility for eventual decommissioning of the plant, though the vendor will retain $200 million of the current $566 million decommissioning funds, with the later return of $116 million more pending a favorable federal tax ruling.

In December 2006 FPL Energy agreed to buy the Point Beach nuclear plant. The two units total 1012 MWe and had just had licences extended to 2030 and 2033. The vendor is Wisconsin's We Energies, which will continue to buy the power. The final price was $719 million for the plant, plus $205 million for fuel and inventory. FPL will assume responsibility for decommissioning and $390 million in trust funds transferred to FPL for this. The deal was approved in September 2007.

The private equity buyout of TXU Corporation, with its two 1150 MWe Comanche Peak reactors, announced in February 2007 was completed in October.  TXU is now Energy Future Holdings Corp which will become three operations: TXU Energy for retail, Luminant for power generation and Oncor for transmission and distribution.  Luminant will take over plans to build two new 1700 MWe Mitsubishi US-APWR reactors at Comanche Peak in Texas and possibly others as well.  Plans for eight coal-fired plants were scrapped earlier in the year.  Environment groups have supported the buyout with its changed policies, and a new director who is chairman of one such group "will lead the effort to make climate stewardship central to corporate policies".

In December 2008 Constellation Energy accepted a bid by Electricite de France (EdF) for half of its nuclear business - 3994 MWe net at Calvert Cliffs in Maryland, and Nine Mile Point and Ginna in New York.  All the five reactors have been granted 20-year licence extensions, and the deal values them at about $2250/kWe net.  The NY plants were bought by Constellation for $533/kW earlier in the decade.

Contents  

US Nuclear Power Plant Purchases since mid 1998  

Buyer Reactors Net MWe
sold		 Plant price
$ million		 Sale Completed
(expected)		 Price*
$/kW		 Value**
$/kW.yr
Entergy
Pilgrim
670
14
July 1999
21
1.6
AmerGen
Three Mile Island
786
23
Dec 1999
29
1.9
AmerGen
Clinton
924
20
Dec 1999
22
0.8
AmerGen
Oyster Creek
619
10
Aug 2000
16
1.8
PECO (Exelon) et al
Peach Bottom, Hope Creek, Salem
714
20
Jan & Oct 2001
28
1.5
Entergy
Fitzpatrick & Indian Point 3
1743
636
Nov 2000
280
18.4
Entergy
Indian Point 2
939
502
Sept 2001
49
3.8
Dominion Res
Millstone
1947
1193
March 2001
613
30
Constellation
Nine Mile Point
1536
675
Nov 2001
439
23
Entergy
Vermont Yankee
510
145
July 2002
288
28
FPL Energy
Seabrook
1024
749
Nov 2002
731
26
Exelon
Clinton, TMI, Oyster Creek
1210
276
Oct 2003
228
about 18
Constellation
R E Ginna
495
408
June 2004
810
31
Genco & CPSE
South Texas
630
279
May 2005
443
18
Dominion
Kewaunee
540
192
July 2005
355
39
FPL Energy
Duane Arnold
419
300
Jan 2006
716
80
Entergy
Palisades
798
242
April 2007
303
12
FPL Energy
Point Beach
1012
719
Sept 2007
710
30
Duke, NCEMC
Catawba
229
200
(mid 2008)
874
35
EdF Calvert Cliffs, Nine Mile Point, Ginna 1997 4500 (2009) 2253 ?

* Price excludes fuel.
** Value based on years between announcement and end of operating licence.

Contents

 Appendix 2. Prospective COL Applications, and EPC contracts

The Department of Energy has made provision for companies to apply for combined construction and operation licences for new nuclear power plants, with costs being shared by DOE. See main part of paper.

NuStart Energy Development LLC comprises nine major utilities* brought together by Entergy and representing more than half of the US nuclear plants. It involves Westinghouse, General Electric and EdF International and will pursue the Westinghouse AP1000 and GE's ESBWR technology options before submitting applications about 2008. It has identified Entergy's Grand Gulf site for an ESBWR reactor and Tennessee Valley Authority's (TVA's) Bellefonte site for two AP1000 reactors . TVA submitted a COL application for Bellefonte in October 2007. NuStart is headed by a n Exelon senior executive. In May 2005 it signed an agreement with DOE to split the estimated $520 million cost of completing detailed engineering work on one of the two designs.

* Constellation, Duke, EdF International, Entergy, Exelon, FPL, Progress, Southern & TVA. Late in 2007 Constellation Energy left it to pursue its Unistar plans with EdF, and Detroit Edison replaced it.  

The second consortium is led by Dominion and originally included Atomic Energy of Canada Ltd (AECL), Hitachi and Bechtel. It started to pursue AECL's ACR-700 option, developed from the successful CANDU-6 heavy-water design but with light water cooling. Hitachi and Bechtel were key contributors to the successful completion of recent CANDU plants in China. However, in January 2005 AECL and Hitachi were replaced by General Electric and the ESBWR became the favoured technology. The reason given for this was NRC indication that certification of the ACR design would be very slow, whereas that of the US technology - developed from designs already approved - would be much quicker. In April 2005 it signed an agreement with DOE to split the estimated $440 million cost of its COL work on the ESBWR, and development costs will be shared with NuStart. Then in 2007 GE became GE Hitachi, bringing that Japanese expertise back into play.  In November 2007 a COL for an ESBWR at North Anna was filed.

In addition to these costs, the main design certification and engineering costs will be borne by the vendor partners.

The Westinghouse AP1000 was given full design certification by NRC in 2005.  The ESBWR is under review for NRC certification, with design certification expected about 2010.  The three advanced reactor designs already certified by NRC initially seemed to have been bypassed, though the AP1000 is developed from one of them and the a 1500 MWe version of the ESBWR from another - the ABWR - several of which are operating in Japan and two of which are now proposed in Texas.

UniStar Nuclear Energy (UNE) started in 2005 as a joint project of Areva (France) and Constellation Energy to develop a business framework for building at least four of Areva's advanced US-EPR nuclear units in North America. The US design certification process was commenced with Areva's help and is now under review by NRC. Bechtel Power Corporation supports UniStar with engineering and construction expertise and Electricite de France (EdF) provides technical assistance. On the basis of the business framework developed over two years, in mid 2007 EdF became the 50-50 partner with Constellation and paid $350 million cash upfront and pledged up to $625 million total to the joint venture which aims to build, own and operate a fleet of US-EPR units in USA and Canada.

The UniStar COL timetable is much the same as NuStart's, with application in 2008, construction start in 2010 and operation 2015. Overnight capital cost was put at up to $2000 per kilowatt, depending on site. UniStar Nuclear Operating Services is the proposed operating company and is a subsidiary of Constellation Energy.

Duke Energy has lodged a COL for two Westinghouse AP1000 units in South Carolina, South Carolina Electricity & Gas for two AP1000 units also in South Carolina, Progress Energy for two AP1000 units in North Carolina and Southern Co  for two AP1000 units in Georgia.  Entergy plans a COL for an ESBWR in Louisiana.  Entergy and Duke are part of the NuStart consortium.

Under the same DOE COL program, a consortium led by TVA undertook a $4 million feasibility study half funded by DOE on building two new ABWRs at Bellefonte in Alabama. It consists of the Tennessee Valley Authority (TVA) plus vendors GE and Toshiba as well as Bechtel, GE Global Nuclear Fuels and USEC. The TVA site has two large uncompleted PWR units.  The 1350 MWe ABWR was the first Generation 3 reactor design to enter service, and while a number of units are operating and under construction in Japanand it already has design certification in the USA, TVA apparently decided not to proceed as they would be the only ABWR units in USA. However the figures are noteworthy: twin 1371 MWe ABWRs would be $1611 per kilowatt, or if they were uprated to 1465 MWe each, $1535 /kW, and built in 40 months.

In mid 2006 NRG Energy announced plans to build 8 GWe of base-load capacity across the USA in the next decade, notably two 1358 MWe ABWR nuclear units from Toshiba costing $5.2 billion at its South Texas site, coming on line 2014-15. Japan's Tepco, the most experienced operator of ABWRs, agreed to assist NRG Energy and STP Nuclear Operating Co with these. The company aims to reduce dependence on natural gas and reduce the carbon intensity of its base-load fleet by 20-25%. This is the most conservative equipment choice among potential new nuclear build in USA, reflecting the fact that such ABWR units are well proven, four of them having been operating in Japan for up to ten years, and they are fully certified in USA. The "investments will be underpinned by long-term offtake contracts and hedges" as well as equity partners, which will be innovative in the US context. Most of the rest of the base-load capacity is to be coal-fired. The company was the first to apply for a COL, in September 2007.  In 2008 Toshiba formed a partnership with NRG to market the ABWR in the USA.

In February 2007 DTE Energy announced that it would apply for a COL for a new plant at its Fermi site in Michigan.

In mid 2007 AmerenUE announced that it was planning to build a US-EPR unit at Callaway, Missouri to meet increased base-load demand in 2017-18, and it lodged a COL application for this in July 2008.  In May 2007 AmerenUE had an $85 million contract with Areva Inc for heavy forgings from Japan Steel Works for this, to be delivered in 2010-11.  In April 2009 it suspended these plans due to the state's ban on recovering costs of construction work in progress.

Luminant (formerly TXU) expects to lodge the COL application for its new nuclear units at Comanche Peak by October 2008, to bring the units on line about 2015. It has deferred plans to build new nuclear units at other sites. Design certification application for the Mitsubishi US-APWR reactors is expected in March 2008 with approval possibly in 2011.

Outside the mainstream utilities, Alternate Energy Holdings Inc proposes a 1600 MWe US EPR nuclear unit at Grand View, near Bruneau in southwest Idaho, and has agreed with Unistar Nuclear to build the reactor.  It says it has raised the finance for this from a group of investors through Cobblestone Financial Group.  The proposed reactor will be part of the $4.5 billion Idaho Energy Complex, providing electricity for local farm co-op irrigation, but with the majority of output being sold in the national energy market and the waste heat being used to co-generate ethanol.  Meanwhile, AEHI has gained the support of local Native American tribesmen for the plant.  A second company, MidAmerican Nuclear Energy Co, was also looking at nuclear possibilities in Idaho but decided not to proceed.

In October 2007 a new private equity group - Transition Power Developments - said it proposed to spend $100 million obtaining a licence to build a 1500 MWe nuclear plant in Utah.  It has contracted for 37 GL/yr water rights, comfortably more than necessary for cooling it, from Lake Powell.

EPC contracts and Advance orders for heavy forgings  

The AP1000 consortium of Westinghouse and the Shaw Group in April 2008 signed an EPC contract with Georgia Power for two new 1100 MWe AP1000 nuclear units at the existing Vogtle site in Georgia.  It already has two 1215 MWe reactors on the site. The units are expected to enter commercial operation in 2016 and 2017.

Six weeks later Westinghouse and Shaw signed a second EPC contract with South Carolina Electricity & Gas and Santee Cooper to build two new 1117 MWe AP1000 reactors at their VC Summer, SC site, which already has one 966 MWe unit.  Total cost of $9.8 billion includes forecast inflation and owners' costs for site preparation, contingencies and project financing, all of which would approximately double the bare plant costs.  The units are expected to enter commercial operation in 2016 and 2019.

At the end of December 2008 Westinghouse and Shaw signed a third EPC contract with Progress Energy Florida to build two 1105 MWe AP1000 units on a greenfield site in Levy county, Florida.  The contract is for $7.65 billion ($3462/kW), of an overall project cost of about $14 billion, including land, inflation, site preparation, licensing, financing costs and fuel.  A further $3 billion will be required for transmission infrastructure.  The reactors would go on line over 2016-18.  A final decision to build will be made when NRC issues a COL for the project, about 2012.

In 2007 Toshiba signed a project services agreement with NRG Energy and its 44% owned STP Nuclear Operating Co. (STPNOC – which owns South Texas Project-1 and -2) for two 1358 MWe ABWR units at its South Texas site.  NRG ordered heavy components for the plant including a reactor pressure vessel.  In February 2009 an EPC contract was signed with STPNOC, which operates the two existing reactors at the site.  STPNOC was acting as the agent for CPS Energy (which owns 40% of units-1 and -2) and Nuclear Innovation North America (NINA), the 50-50 joint owners of the planned new units.

Toshiba said that at mid May 2008 it had orders for six Westinghouse AP-1000 reactors and for two ABWR units in the USA.  The former appear to be Georgia Power/ Southern Nuclear: two Vogtle units, South Carolina Electricity & Gas: two Summer units, and Progress Energy: two Levy County units.  The ABWR units would be for NRG's South Texas plant.

Several companies have ordered heavy forgings and other long lead time equipment for building new plants, in advance of specific plans or approvals. In 2006 Areva (for UniStar Nuclear joint venture) ordered heavy forgings from suppliers in Japan and France in anticipation of US orders for new US-EPR reactors - evidently for Constellation at Calvert Cliffs and AmerenUE at Callaway. Areva also arranged with Babcock & Wilcox in Virginia to supply major EPR components such as steam generators and pressure vessels.

In 2006 GE Energy arranged production slots for forgings from Japan Steel Works for ESBWR and ABWR units. In April 2007 Dominion contracted with it - now GE-Hitachi Nuclear Energy - for major ESBWR components such as large forgings and other nuclear and turbine island parts for North Anna, and in July Entergy signed up for ESBWR components for either Grand Gulf or River Bend.  Then In December Exelon Nuclear ordered ultra-large forgings, reactor pressure vessels and steam generators to keep its options open for two ESBWR units in Texas. These moves will put them in front of any supply bottlenecks when orders are confirmed. 

Contents

 Appendix 3:  US Uranium Mining and Exploration

Cameco's US subsidiary Power Resources Inc operates the Smith Ranch-Highland mine in Wyoming's Powder River basin and the Crow Butte mine in Nebraska, both of them ISL operations, and producing 786 and 281 tonnes U respectively in 2006 from total reserves of 12,000 tU (15,000 t U3O8). The US company is now known as Cameco Resources and is aiming to increase production from these mines and adjacent properties to 1770 tU/yr by 2011.

Uranium Resources Inc commenced production from its Vasquez ISL mine in 2004 at about 50 tU/yr and from Kingsville Dome in 2006 at 150 tU/yr, both in south Texas.  Vasquez peaked in 2006 and is now largely depleted (30 tU in 2007).  Rosita started production in 2008 with oxygen injection but was then closed as uneconomic after 3 tU was recovered.  Mestena Uranium's Alta Mesa ISL plant in southern Texas is also operational.  Uranium Energy Corp has been granted preliminary approval to mine its Goliard ISL project in south Texas.  It has 2100 tU measured and indicated resources which are NI 43-101 compliant.

Conventional (non-ISL) uranium mining in is resuming after some years (though Cotter Corp. produced 38 tonnes U through its 400 t/day Canon City mill, Colorado in 2005).

Cotter Corp, a General Atomics subsidiary, is planning a $200 million rebuild of its Canon City mill by 2014, when it expects to treat ore from Mount Taylor mine in New Mexico. 

Denison Mines expects to produce up to 650 tU in 2008 through its 2000 t/day White Mesa mill in southeastern Utah, from its own and purchased ore, as well as doing some toll milling.

Denison is opening the first of its Uravan Mineral Belt mines on the Colorado Plateau containing 2100 tU in placer deposits plus vanadium co-product (Uravan = uranium + vanadium). Its Henry Mountains deposits in Utah including Tony M, Southwest and Bullfrog have 4900 tU as indicated resources at over 0.2% and inferred resources of 3100 tU, both NI 43-101 compliant.  All these are within 160 km of White Mesa mill.  It has begun production from Colorado Plateau and Tony M mines, but late in 2008 temporarily closed the latter.  It is spending $13 million on mill refurbishment, $10 million on old mines and then $35 million on the adjacent new Bullfrog mine preparing for a late 2009 start.  It also plans to start reopening its four mines in the Arizona Strip in 2008, along with some new deposits there, though all these are some 500 km from White Mesa mill.

In 2007, Denison operated four mines in the Colorado Plateau area: Topaz, Pandora, West Sunday and Sunday/St. Jude. The last three are mature operating mines with extensive underground workings, while the Topaz mine is relatively new.  Two further old mines reopened in 2008: Rim Canyon and Beaver Shaft, which required significant refurbishing to produce some 30 tU/yr. A third mine, Van 4, will be in production in early 2009.

Toronto-based Uranium One in 2007 bought US Energy's 1000 t/day Shootaring Canyon mill in southeast Utah and associated properties in four contiguous states for $50 million plus royalties. US Energy had been planning to bring the mill back into production at a cost of $31 million. Uranium One had also secured the right to buy Rio Tinto's 3000 t/day Sweetwater uranium mill and associated uranium properties in south-central Wyoming for $110 million, but in January 2007 Rio Tinto cancelled the deal.

Uranium One, through wholly-owned Energy Metals Corporation, has refurbished the small Hobson plant in southern Texas which has been shut since 1991. It produced about 130 tU/yr for previous owner Energy Metals Corporation but will have 380 t/yr capacity, recovered from loaded resin trucked there from the La Palangana ISL mine from 2009.

In Wyoming the company has plans for 900 tU/yr production from three mines in the Powder River basin from 2010 (Moore Ranch, Peterson Ranch, Nine Mile) and 900 tU/yr from Antelope in the Great Divide basin later. In 2007 it announced a toll "milling" arrangement with Cameco for recovery of up to 540 tU per year at Smith Ranch-Highland mill. This will be from loaded resin trucked to the plant, initially from Moore Ranch, starting 2010. It has some 4000 tU as measured resources (2235 t at Moore Ranch) and 23,000 tU as indicated resources in the state.

Uranerz is in the process of permitting its Nichols Ranch ISL operation in the Powder River Basin of Wyoming.  This will have a number of satellite operations, starting with Hank, with loaded resin being trucked to Nichols Ranch.  Production is envisaged from 2011.  Resources were quoted at 4000 tU, but in June a NI 43-101 compliant indicated resource of 1137 tU for Nichols Ranch itself was announced.

Energy Fuels Resources Corp (subsidiary of Energy Fuels Inc of Toronto) has applied to reopen former uranium-vanadium mines in the Uravan mineral belt in western Colorado.  Whirlwind (including Packrat, Bonanza and La Sal) is a near-term project following Bureau of Land management approval, but late in 2008 was put on standby.  Tenderfoot Mesa is adjacent.  Its Pinon Ridge mill is listed as developing, with commissioning possible in 2011.  EFRC's nearby Energy Queen mine in Utah has been refurbished for 2008 reopening.  In August 2008 EFRC announced NI 43-101 compliant indicated resources of 1480 tU and inferred resources of 1370 tU for its Colorado and Utah properties.

Areva NC's Cogema Mining Inc has applied to reopen the Irigary Christensen Ranch ISL mine in the Pumpkin Buttes district of Wyoming, which will have 250 tU/yr capacity from about 2009.

American Uranium Co in joint venture with Strathmore Minerals based in Canada has announced a NI 43-101 measured and indicated resource of 2865 tU @ 0.065% for Reno Creek and 1360 tU @ 0.068% for Southwest Reno Creek in Wyoming, suitable for ISL.  This is 30 km southeast of Christiansen Ranch and 50 km north of Cameco's Smith Ranch.

Uranium Energy Corp in 2007 bought the New River Uranium Project in Arizona with a historic resource estimate of 5000 tU in shallow low-grade ore.  In 2009 it formed a joint venture with Australia’s Uran Ltd to develop the Grants Ridge project in New Mexico, including nine historic mines which operated from 1970-80s, with average grade 0.20%.

Ur-Energy expects NRC approval in 2009 for ISL mining at its Lost Creek, Wyoming deposit with 4200 tU indicated and inferred resources. 

Uranium Resources Inc (URI) in 2007 sought to buy Rio Algom Mining, with uranium properties and a licensed mill site at Ambrosia Lake in New  Mexico, where it planned to construct a new mill to serve the Grants mineral belt. However, the deal was aborted in mid 2008.  URI subsidiary Hydro Resources Inc was licensed in 1994 to mine the Crownpoint and Church Rock ISL deposits in New Mexico, and after years of opposition the licence was validated by NRC in 2006.  URI was moving all these towards production, but in March 2009 was reported as closing its Texas operations due to low uranium price.

Also in New Mexico, Uranium International Corp has announced 1180 tU measured and indicated resource at Dalton Pass, with ISL potential.  It also announced an 1160 tU measured and indicated resource at Nose Rock, deep in hard rock.  Both are NI 43-101 compliant, in the Grants mineral belt and owned by Strathmore Minerals.  UIC has the option of earning a 65% share of each.

Yellowcake Mining Corp reports 5000 tU reserves at its planned Beck mine in the Uravan area of Colorado and agreed in May 2008 to sell a 50% stake in it to Korea Electric Power Corp (KEPCO).  However, in February 2009 KEPCO withdrew, leaving the project bereft of funds.  The company also has joint ventures with Strathmore Minerals for Juniper Ridge and a Gas Hills prospect in Wyoming.

Strathmore Minerals is working towards bringing its Gas Hills properties in Wyoming into production, though it has only historical resource figures for most of these. 

Strathmore also has projects in the Grants mineral district in New Mexico, including another Church Rock prospect with 4570 tU as NI 43-101 compliant measured and indicated resources.  Two other properties in the Grants mineral belt are Dalton Pass, with ISL potential and 1000 tU measured and indicated resource, and Nose Rock, deep in hard rock but with 1160 tU measured and indicated resource, both NI 43-101 compliant. Uranium International Corp had an agreement to earn a 65% share in both these, but terminated that in November 2008.  Strathmore is preparing to submit a mining permit application for Roca Honda (60% owned, with Sumitomo 40%) in the Grants mineral district which has measured and indicates resources of 6745 tU at 0.195% U and slightly less inferred resources.

Powertech Uranium Corp is proposing to develop two ISL mines: Centennial in northern Colorado, and Dewey Burdock in South Dakota - in each case very close to the Wyoming border.  Centennial has 4430 tU in 0.08% ore and Dewey Burdock 4160 tU in 0.154% ore, both as NI 43-101 compliant inferred resources.

Bluerock Energy Corp. has shipped the first ore from development of the J-Bird mine in Colorado to Denison's White Mesa mill in Utah.

White Canyon Uranium based in Perth has approval for mining its Daneros deposit in southeastern Utah.  Underground mine development will then proceed and it is envisaged that ore will be trucked 100 km to the White Mesa mill from about September 2009.  No resource figures are quoted.

US Uranium Mines and other Production Facilities 


 ISL mine Mill Status  Annual capacity
Cogema Mining Inc (Areva) Christiansen Ranch, Wy
Christiansen Ranch 250 tU
Power Resources Inc (Cameco) Smith Ranch - Highland, Wy
operating 2100 tU
Cameco Corporation
 Crow Butte, Neb
operating 385 tU
Uranium Resources Inc Vasquez, Tx
 
Rosita, Tx
operating in 2008, but closed early 2009
 310 tU

Kingsville Dome, Tx
operating in 2008, but closed early 2009
 385 tU
Mestena Uranium Alta Mesa, Tx
operating 385 tU
Uranium Energy Corp

Goliard, Tx

   preliminary approval ?
Hydro Resources Inc (URI subsidiary)
 Church Rock, NM
under const.* 385 tU
  Crownpoint, NM
   under const
 385 tU
Uranerz Nichols Ranch
   Permitting  
Uranium One
 Moore Ranch, Wy
under const. 900 tU
  Antelope, Wy
   under sonst
 900 tU
South Texas Mining La Palangana, Tx Hobson, Tx under const.* 385 tU
Cotter Corp
Canon City, Co standby, refurbish plan for 2014 start
Denison
White Mesa, Ut operating
 
Sweetwater, Wy  standby  
Uranium One
Shootaring Canyon, Ut  operational in 2008?
Energy Fuels Resource Corp  

Pinon Ridge, Co

developing, maybe operate 2011

  

  * partially permitted and licensed 

See also EIA information

Main Sources:
Based originally on NAC Emerging Issues, May-June & Sept 2000.
NRC 23/3 & 23/5/00; NEI various, utilites various;
NucNet news & business news, various;
Nuclear Eng Int'l Dec 2001;
B.Lacy 2002, WNA Symposium paper.
US Dept of Energy, EIA 2003, New Reactor Designs.
RWE NMR Online July 2004, US Consortia: inching towards new nukes.
S.Bowman paper at World Nuclear Fuel Cycle conference, April 2005.