Planning for the future3 August 2003
Xcel Energy had expressed concern over the future of its Prairie Island and Monticello plants because, unless permission to store more spent fuel at its sites were granted, the reactors would have had to have been shut down and other generating options found.
Xcel Energy operates two nuclear power plants in Minnesota, the two 566MWe PWRs at Prairie Island (Prairie Island 1 and 2) and the 576MWe BWR at Monticello. This output represents about 30% of that needed to supply Xcel Energy's Minnesota customers.
Nuclear power plants in the USA currently have to store spent fuel in pools or steel dry casks at the plants. Xcel Energy has a federal licence that allows use of up to 48 of these casks at Prairie Island. However, in 1994, the Minnesota Legislature limited spent fuel storage to 17 casks in the entire state. This limitation meant that the remaining space in the Prairie Island spent fuel storage pool would be full by 2007. Monticello's current operating licence is due to expire in 2010.
In addition to the potential loss of 1708MWe of nuclear generation in Minnesota, there were other decisions by other regulatory agencies on several other electricity supply options that had to be made in the same timeframe. These included:
• An additional 1000MWe in service 2005-2009 to meet projected growth.
• An additional 450MWe in service 2011-2013 to meet projected growth.
For several years, Xcel Energy has pursued temporary interim storage with the Private Fuel Storage (PFS) project in Utah. PFS is a consortium of eight nuclear utilities working with the Skull Valley Band of Goshute Indians to build a spent fuel storage facility in west central Utah.
Xcel Energy believed that the necessary regulatory approvals would be obtained for the project early next year.
PFS proposes to license, build and operate an above-ground interim facility to store spent nuclear fuel from its member plants, as well as from other nuclear plants if space is available.
Seventeen dry storage containers have been filled and stored at Prairie Island. By 2007, all the remaining storage space in the pool would have been filled without legislative action. However, if PFS is operational by 2006, there would be no need for the additional storage of casks at Prairie Island. Even under such circumstances, there would still have been a need for legislative changes to overcome logistical
limitations that require some spent fuel from the pool to be moved while spent fuel in dry storage is shipped.
Monticello is due to run out of spent fuel storage space in 2010, at the same time as its operating licence expires. In the mid-1980s, 1058 spent fuel assemblies were transported in 33 rail shipments to a wet pool storage facility operated by General Electric in Morris, Illinois. As a result of this, Monticello has sufficient storage space in its pool to accommodate spent fuel discharges to 2010.
In May 2003, Governor Tim Pawlenty signed legislation allowing the storage of additional casks at Prairie Island. The bill allows Prairie Island to continue operating until the end of its federal licence for its two reactors in 2013 and 2014. Regarding renewable energy in Minnesota the legislation:
• Nearly doubles the Renewable Development Fund required by Xcel Energy from $8.5 million to $16 million each year for as long as Prairie Island is in operation.
• Requires Xcel Energy to deploy at least an additional 300MWe of wind energy, as well as install renewable energy sources whenever they are the most cost-effective resource.
• Requires all utilities to develop formal plans on how they plan to meet their 10% renewable energy objective by 2015 and require the Public Utilities Commission to establish criteria to review the plans.
The Renewable Development Fund provides $4.5 million for an additional 100MWe of small windmills and $1.5 million to subsidise on-farm bio-gas projects.
The legislation also makes a lump sum grant of $10 million and annual funding of $2 million to the University of Minnesota for research and development into hydrogen and other forms of renewable energy from existing mandated expenditures.
If no ruling had been made on storage of spent fuel, Prairie Island would have had to shut down in 2007, and Monticello in 2010.
As a result, Xcel Energy considered nine different scenarios, and attempted to predict the overall cost of power supply over a 30-year period for each
scenario. The analysis included scenarios in which Prairie Island and Monticello are relicensed for extended operation, both operate to the end of their current licences, and Prairie Island shuts down in 2007 for lack of a spent fuel storage solution.
The results of the analysis are presented in the Table. Values represent differences from the least expensive alternative, which was found to be the extended life case.
Xcel Energy examined four different nuclear options. In the first scenario, Prairie Island was assumed to shut down in 2007, and Monticello was assumed to be relicensed and operate until 2030.
The second scenario assumed that Prairie Island would operate to the end of its current licence, 2013/2014, and Monticello was assumed to receive a new licence and operate to 2030.
The third scenario assumed that both plants are relicensed and continue to operate, Prairie Island to 2033/2034, and Monticello to 2030. In this scenario, no replacement resources are necessary during the period of the analysis.
The fourth scenario assumed that Prairie Island shut down in 2007 and Monticello shut down in 2010.
The capital and operating costs and operating characteristics associated with each of the alternatives were estimated and incorporated into the Strategist power production-modelling program. Strategist then simulates the operation of the power supply system over the entire planning period. It adds new power plants as necessary. The program then estimates the total cost of power supply during the planning period, and converts it to a single present worth value.
Steam generator investments
The steam generator investments needed to keep Prairie Island operating economically will be substantial over the next two years if nuclear generation is to remain part of the fleet. Xcel Energy said that it needed a clearer view of the future of the plant's operations and the regulatory treatment of this new investment to decide whether or not to proceed with steam generator replacement in unit 1.
Through an aggressive programme of inspection and maintenance, the Prairie Island plant has been able to operate its steam generators longer than other plants of similar vintage. However, projections of steam generator tube degradation indicate that, while plant safety can be maintained without compromise, the plant could face shut down as early as 2009 due to the declining performance of the steam generators. Increased operating and replacement power expenses were projected to begin occurring as early as 2003 due to the potential for increased inspections
during refuelling outages, mid-cycle shutdowns to perform inspections to deal with NRC regulatory interventions, as well as eventually experiencing permanent capacity reductions because of reduced flow through the steam generators due to the number of tubes sleeved or plugged. Inspection results of the unit 1 steam generators during the 2001 refuelling outage were within the expected ranges and did not cause a change to the projections.
Xcel Energy intends to preserve the option of replacing steam generators in Prairie Island 1 during the 2004 refuelling outage. The estimated cost of the steam generator replacement is $132 million at Prairie Island 1. Adjustments to operating cycles at Prairie Island 1 have been made so that an extended plant outage, 40 days longer than a normal refuelling outage, can take place in autumn 2004. The fabrication contract for steam generators has been awarded and detailed planning of the installation process is well underway.
In the 2013/14 scenario, it was assumed that steam generators in Prairie Island 1 are replaced in 2004, and that Prairie Island 2's steam generators are not replaced. In the life extension scenario, steam generators in both units are replaced, unit 1 in 2004, and unit 2 in 2008.
Other capital costs
As part of the ongoing operating
and maintenance programmes at Monticello and Prairie Island, routine capital investments are made annually. Routine capital investments include replacements of mechanical items such as pumps, valves, air compressors and heat exchangers, replacement of electrical components such as batteries, switches, cabling and motors, and miscellaneous items such as information technology or security upgrades. Capital investments have averaged roughly $20 million per year at Prairie Island and $10 million per year at Monticello in recent years. Both Prairie Island's and Monticello's annual capital investment levels were assumed to be ongoing for the nuclear power scenarios and were incorporated into the modelling.
Personnel retention costs
Regulatory requirements for operating a nuclear power plant dictate that the licensee meet minimum staffing requirements. These requirements include: minimum numbers of reactor plant operators to staff each shift, qualified instructors to support all accredited training programmes, qualified operators to perform fuel handling activities, staffing to perform routine maintenance, staffing to perform engineering, design and licensing functions, experienced senior management, sufficient plant staffing to staff the emergency response organisation, and adequate security forces to meet NRC requirements. The qualifications necessary for many of these technical positions require staff to study for long periods of time and requires a significant experience base.
Currently, the nuclear industry is experiencing some difficulty in attracting replacement personnel, while demands in specific areas are growing due to increasing qualification requirements. This increased demand translates into available opportunities for qualified employees at other plants if they become concerned that there is not a long-term future where they
If it is decided not to pursue licence renewal at Monticello and Prairie Island, it is likely that employees will look for employment at plants with longer operating horizons. It would probably become necessary to establish retention incentives to keep an adequate complement of qualified plant personnel employed at the plant during its remaining operation and into the commencement of the decommissioning process.
It is estimated that the present value of the retention costs in a 2007/2010 shutdown could range from $49 million to $92 million for Prairie Island, and ranging from $39-75 million for Monticello. To estimate these costs, Xcel Energy reviewed retention packages offered by other licensees who have shutdown prematurely. These retention packages typically offered salary
bonuses from the time shutdown was announced until an employee's position was no longer required, and a severance package (including salary, medical and life insurance) for some period upon termination. The condition of receiving the retention package is typically a requirement for the employee to stay until the company determines that their position is no longer required. Any employee leaving prior to that time would forfeit their retention package.
These costs were not included in the modelling, but they were included in the analysis of alternatives (see Table, p21). However, there is a real cost associated with retention costs for alternatives that shut down nuclear generation early in the planning period compared to those that allow nuclear generation to operate through the planning period due to the time value of money.
A decision on filing an application to renew the Monticello operating licence is approaching. Monticello's current operating licence expires in September 2010. The NRC regulations require that a licensee submit a licence renewal application and receive a determination that the application is sufficient to begin detailed review no later than five years before the expiration of the current licence. Because of the number of licence renewal applications that the NRC may have under review in 2005, the application will have to be submitted at least six months prior to the September 2005 date to allow NRC staff time to perform their sufficiency review of the application.
In order to support filing the Monticello licence renewal application during the second quarter of 2005, Xcel Energy needs to spend $4 million in each of 2003 and 2004. The total estimated cost to renew the licence for an additional
20 years until 2030 is $18-20 million.
When Prairie Island and Monticello are shut down, decommissioning of the plants would begin. There are three basic approaches to decommissioning depending on how spent fuel is handled at the time. Spent fuel can be removed from the pool and shipped directly to an out-of-state facility and casks are paid for by the DoE. Once all fuel in the reactor and pool and dry storage are shipped, the pool and reactors can be dismantled.
If out-of-state storage is not available at the time decommissioning begins, spent fuel can continue to be stored in the pool and reactors until shipping can begin. This approach would lengthen the decommissioning programme and increase costs due to continued operation of the pool and other plant support facilities.
The third alternative would be to move spent fuel from the pool and reactors to on-site dry storage so that the pool and reactors could be dismantled as soon as possible. Spent fuel would then be shipped from dry storage as soon as a destination was available. This method was recently studied by Xcel Energy, which found that it resulted in a need for somewhat higher accrual rates than wet storage due to the early outlay of cash flows for casks.
Selection of the preferred decommissioning method will involve ongoing analysis, and any decision would consider the cost at the time, as well as any advantages in fully decommissioning the reactor and pool using dry cask storage. Xcel Energy does not currently believe that decommissioning will be achieved without incurring spent fuel storage costs. The total amount of time necessary to decommission the plant could range from 20-40 years.
Decommissioning costs have been included in the cost of electricity generated at Prairie Island and Monticello. Xcel Energy annually sets aside money for decommissioning into a fund that is managed by fiduciaries. In the past, funds were accrued in internal accounts at Xcel Energy. However, these funds were transferred to the external dedicated funds. The programme is designed so that adequate resources are available at the time of plant shutdown to allow the decommissioning programme to be fully funded.
The NRC reviews decommissioning accruals annually, and a new estimate of decommissioning costs is prepared every third year.
Decommissioning costs associated with the various scenarios have not been included in the Strategist modelling since currently expenses are being recovered. However, the timing and method of decommissioning can cause significant cost differences among the alternatives that should be considered. The time left to accumulate decommissioning funds is short if Monticello shuts down in 2010. Thus annual decommissioning outlays in the form of levelised payments to the external fund could increase from $23 million in 2002 to as much as $74 million annually.
Decommissioning may already be fully funded if the plants operate for another 30 years. The present worth of cash outlays into the external decommissioning fund was added to the results of each scenario for purposes of reflecting the differences in funding costs associated with decommissioning at different points in time. Any excess funds placed in the external decommissioning fund cannot be returned until after decommissioning is
completed and all decommissioning expenses are paid. Thus excess funds cannot be returned to those that made the payments, only to ratepayers some 30 or more years in the future.