Chapter 77: The Cost of a Nuclear Power Plant

Toshiba, the Japanese industrial giant, and the French utility GDF Suez have announced plans recently (2014) for moving ahead with a new British nuclear power station, adding momentum to the country’s atomic energy program.  The facility, called Moorside, would be located in northwest England on the Irish Sea and would eventually have three Westinghouse reactors, supplying close to 7 percent of Britain’s power, the companies said Monday.

At the earliest, construction of the facility, with a price tag of at least 10 billion pounds, or about $17 billion, would begin in 2020, with the goal of having the first reactor online in 2024.


Nuclear power plants indeed are capital-intensive and according to the Nuclear Energy Agency (NEA), a typical cost for construction of a Generation III reactor with the capacity between 1400 – 1800 MW in the Organization for Economic Co-operation and Development (OECD) countries might be in the region of USD 5 – 6 billion.  In non-OECD countries such as China, the cost of reactors is lower.  Generally reactors which are first-of-a-kind are more expensive to build than those which are built in a series with previous experience of construction.

At the same time, the Nuclear Energy Institute (NEI) estimates construction cost for building a large reactor from USD 6 to 8 billion.  The fact is that once a nuclear power plant is built, operating costs for generating electricity are considerably low.

It needs to be kept in mind that new nuclear power plants are projects of immense scope and magnitude in the world of infrastructure development.  Reports of periodic cost or schedule variances can be highly misleading if treated in a vacuum and if they fail to take into account the vast scope of the project.  For instance:

  • A nuclear power plant construction project is a multi-year effort.  Any variance over a few days, weeks or even months is not indicative of overall project progress.  Simply reporting on the variance does not take into account longer-term projections over the life of the construction project; and
  • Nor does it reflect the ultimate value of the facility when it goes into service—its contribution to the stability of the electrical system, its role in reducing greenhouse emissions and its ability to provide affordable power over the long term.

1.1         Capital Cost (Overnight Cost):

Like all new generating capacity, there is uncertainty about the capital cost of new nuclear power plants.  Estimates range from $4 billion in today’s dollars for the Engineering, Procurement, and Construction (EPC) cost of a single plant to $22.5 billion in 2022 for an entire two-unit project, including transmission lines and other services.  This wide variation in costs can be attributed to several factors including:

  1. Uncertainty about commodity prices and wages;
  2. Use of different financial assumptions, including the year in which the costs are projected, and
  3. Estimates frequently include different scope, which can make a dramatic difference in cost estimates.

The capital investment to construct a nuclear power plant represents some 60 percent of the total generation cost.  The capital cost discussed in this section represents the overnight cost which doesn’t include financing charges.

Overnight construction cost equals owner’s costs, EPC costs, and contingency provision.  The overnight construction cost is so-called because it is calculated using the cost as if the full amount was spent ‘overnight’, or at one specific moment in time. This excludes interest on the capital during the period of construction.

Here are some definitions:

  • Owner’s Costs:

Owner’s costs are difficult to determine exactly, but they include elements such as general administration, spare parts, site selection and land acquisition, taxes, and preliminary feasibility studies. The total is different for each project and can vary from country to country, but it typically accounts for 15 to 20 percent of the engineering and procurement costs or 15 to 20 percent of the total plant cost or 15 to 20 percent of the overnight construction cost;

  • Engineering, Procurement, and Construction (EPC) Costs:

Engineering, procurement and construction costs are related to site preparation, materials, equipment, manpower aspects, as well as the construction, engineering and supervision services and licensing fees. Typically, this cost makes up about 70% of the total overnight cost of the plant.  Of that share, between 70 and 80 percent is accounted for by materials and factory equipment and the other 20 to 30 percent are related to labour costs; and

  • Contingency Provision:

A contingency provision is added to the estimate in order to account for unknown costs that could arise, for example because of a request by the regulatory body for changes during construction.  The usual contingency cost is 15 percent.  On top of that, an accuracy of cost estimate contingency is calculated.  This is related to factors such as the country where the plant is being built, its experience with nuclear power and the specific design chosen, and whether the selected site is new or already hosts nuclear installations.

A recent study by the University of Leuven, Belgium, obtained 137 estimates for the overnight construction cost of a nuclear plant from 28 different sources.  The results show that the cost could range between EUR 1,316 per kW and EUR 6,934 per kW.

Accounting for contingencies, the study estimates that a twin-unit nuclear power station which is the first of its kind in the country, but using a design that is already in use elsewhere and being built on an existing site can cost about EUR 3,910 per kW with uncertainty of -20 to +30 percent.  This estimate equals EUR 7.8 billion for the construction of a plant composed of two 1,000-megawatt nuclear units.  For a single unit, the estimate increases to EUR 4,250 per kW or EUR 4.25 billion for a 1,000 MW unit.

A twin-unit power station which is not the first of its kind in the country and is being built on an existing site can cost about EUR 3,400 per kW with uncertainty of -10 to +15 percent.  This estimate equals about EUR 6.8 billion for a plant composed of two 1,000 MW nuclear units.  For a single unit, the estimate increases to EUR 3,570 per kW or EUR 3.6 billion for a single 1,000 MW unit.

  • Example 1:

Flamanville-3 is a first-of-its-kind reactor design being built in France, but not the first reactor of its kind in the world.  It is a single unit being built at a site which already has two operational nuclear reactors.  Its capacity is 1,650 MW. Taking the estimated cost above, the unit should cost approximately EUR 7 billion with an accuracy adjustment of -20 to +30 percent.

As of December 2012, EDF’s projected cost for the unit has been EUR 8.5 billion.  Note that the Flamanville-3 project is financed by EDF, which is a state-owned enterprise and therefore benefits from low interest on its financing.

  • Example 2:

Mochovce-3 and -4 are two reactors being added on the site of two operational units at the Mochovce Slovakian nuclear power plant.  They are not the first of their kind and have a capacity of 440 MW each.  Taking the estimated cost, this twin-unit project should have a total cost of approximately EUR 2.8 billion with an accuracy adjustment of -10 to +15 percent.

In August 2013, the Slovak government’s projected cost was EUR 3.8 billion, which also takes account of a prolonged construction time.

Note that the project is financed by the utility Slovenské Elektrárne AS, a company which is 66 percent private and 34 percent government owned, meaning that a combination of debt and equity is being used for its financing, making the estimation of costs more difficult.

Contingency is an integral part of the cost estimate in some countries and the following table illustrates how countries in general handle the provision of contingency and management of risk:


1.2       Financing Cost:

Interest during construction is the so-called financing cost and refers to the interest paid on debt during the period of construction as well as the rate of return to equity investors (for private investments). Typically, this cost is about 20 percent of the overnight construction cost.

As a background, nearly all nuclear power plants operating today were financed and built in regulated utility markets. Thus, they were guaranteed both future customers and high enough electricity prices to ensure a profitable rate of return.  Under these conditions, cost overruns and project delays were covered by higher electricity prices and were ultimately paid for by customers.  In addition, much of the financing for these plants was provided by governments or with government backing or government guarantees of some kind.

In the last three decades both the utility and financial markets have changed in important ways.  On the utility side, the rules have changed substantially.  The new conventional wisdom is that progress means deregulating quasi-monopolistic markets and unbundling transmission, distribution and generation so that there is full competition among electricity generators and full choice for customers.  While full deregulation, unbundling and competition are not yet established in most countries, this model affects financing considerations for new power plants. Thus, the market risk for utilities has changed and will continue to change, even as demand for their product – electricity – continues to grow.

On the financial side, international capital markets have become increasingly global and competitive.  A variety of new financial instruments and packaging schemes have evolved to better ensure returns on investments and attract investors to specific projects.  Meanwhile, the availability of capital is not an issue: in 2006, some $4.2 trillion were raised in the global capital markets, of which 5 percent, or $230 billion, was invested in the power industry.

Due to the high initial investment costs of nuclear power plants (overnight costs), the financing costs during construction are very high.  Together they can constitute up to 75 percent of the total lifetime costs of a nuclear power plant that will run for 40 to 60 years.  On the other hand, operating costs are low and stable.  Nevertheless, due to the high initial outlay required, those financing nuclear power plants may demand interest rates sufficient to compensate for risk.

The cost of financing is often significantly lower in emerging economies, as plants are usually built by publicly owned utilities with access to cheaper government-backed finance.  Such projects are usually part of central energy planning, which further reduces construction risks as prices are regulated.  This is the case in China.  In the United States, the federal government recently offered loan guarantees for two new reactors at Georgia’s Vogtle plant.

In a few countries there are very large, well-capitalized electricity utilities that are able to finance nuclear construction from their “balance sheet”, at least for a limited number of plants.  Some of these are fully or partly state-owned, while others are vertically integrated (giving them direct access to electricity customers) which reduces risk as any cost increases can be passed on.  To some extent, utilities may be able to share risks with nuclear power plant suppliers and contractors, as well as with other investors (including banks and investment funds).  Support through public loan guarantees, export finance and long-term contracts can also lower the cost of capital.

Several models for financing nuclear power plants exist.  Apart from financing through a strong balance sheet, there is also the possibility that major electricity consumers invest in a plant, such as in the case of Olkiluoto-3 in Finland. Construction may also be on a build-own-operate (BOO) basis.  This is the scheme under which Atomstroyexport of Russia is building a nuclear power plant at Akkuyu in Turkey, and is the first nuclear power plant project to be constructed under these terms.

Short-term cost and schedule variances are simply snapshots in time.  As such, they do not reflect factors such as long-term contracts for materials, labor at set prices, lower-than-forecast interest rates and other related financing costs.

  • Simply focusing on a short-term variance does not take into account the benefits of “construction-work-progress,” which allows a company to recover financing costs during construction by including them in the rate base.  Doing so eliminates additional financing costs, or “interest on interest.”
  • Any endeavor as large and complex as a nuclear plant construction project will inevitably pose challenges. Regulatory delays, design changes or protracted approvals may affect project schedule, resulting in adjustments in costs at that particular moment.  On the other hand, savings later in project timelines can counter earlier increases. Such variations are expected in large capital projects.

The real gauge of a project’s success or failure is not the variance itself, rather how the company handles these challenges and prepares for contingencies.  In view of all these factors, nuclear energy projects in Georgia and South Carolina have experienced no setbacks that would jeopardize their ability to finish on time and within budget and meet customer expectations.

In February 2010, President Obama and Energy Secretary Steven Chu announced the award of $8.3 billion in conditional loan guarantees for Vogtle Units 3 and 4, two 1,100-megawatt nuclear reactors in Georgia.  Consequently:

  • Four years later, in February 2014, after extensive negotiations, the Department of Energy (DOE) finalized the loan guarantees with two of the co-owners of Vogtle 3 and 4.1 DOE guaranteed a loan of $3.46 billion to Georgia Power Co., and $3.06 billion to Oglethorpe Power Corp.  Final negotiations on the loan guarantee for Municipal Electric Authority of Georgia are ongoing and expected to conclude shortly;
  • Georgia Power’s share of the project is currently projected at approximately $6.8 billion, including approximately $2 billion of financing costs to be collected during construction.  Use of the DOE loan guarantee will reduce financing costs and save Georgia Power customers as much as $250 million; and
  • The credit subsidy cost of the loan guarantees provided to Georgia Power and Oglethorpe Power was zero;
  • Both the Georgia Power and Oglethorpe loans are full-recourse corporate loans under which DOE has a claim against all the assets of the companies respectively in the event of default.

Perhaps the question is – How are utilities managing cost recovery for the construction of new reactors? 

By paying the cost of building a new reactor as it is incurred, electric companies can benefit their customers by reduced financing costs.  This is called Construction Work in Progress (CWIP).  While there may be a small charge added to the monthly utility bill, it facilitates paying off finance charges immediately rather than over the entire life of the plant. This avoids “interest-on-interest” charges and prevents a much larger one-time increase in electric rates when the reactor becomes operational.

Improved cash flow to the electric company leads to a stronger financial rating, which in turn results in lower interest costs for the nuclear energy project and all other investments the utility makes over the long term.

The other question is:  How much is added to the monthly electricity bill?  The amount differs depending on the nature of the project and what is allowed by the state government and regulator.  For example, Florida Power & Light said that the cost recovery charge for its projects was about $1.65 per month to a typical customer.  The fee financed $130 million for upgrades to the St. Lucie and Turkey Point nuclear power plants.

1.3        Some Examples:

There have been a large number of recent estimates from the United States of the costs of new nuclear power plants. For example, Florida Power & Light in February 2008 released projected figures for two new AP1000 reactors at its proposed Turkey Point site.  These took into account increases of some 50 percent in material, equipment and labour since 2004.  The new figures for overnight capital cost ranged from $2,444 to $3,582 /kW, or when grossed up to include cooling towers, site works, land costs, transmission costs and risk management, the total cost came to $3,108 to $4,540 per kilowatt.  Adding in finance charges almost doubled the overall figures at $5,780 to $8,071 /kW.  FPL said that alternatives to nuclear for the plant were not economically attractive.

In May 2008 South Carolina Electric and Gas Co. and Santee Cooper locked in the price and schedule of new reactors for their Summer Plant in South Carolina at $9.8 billion.  The budgeted cost earlier in the process was $10.8 billion, but some construction and material costs ended up less than projected.  The EPC contract for completing two 1,117-MW AP1000s is with Westinghouse and the Shaw Group.  Beyond the cost of the actual plants, the figure includes forecast inflation and owners’ costs for site preparation, contingencies and project financing.  The units are expected to be in commercial operation in 2016 and 2019.

In November 2008 Duke Energy Carolinas raised the cost estimate for its Lee plant (2 x 1117 Mwe AP1000) to $11 billion, excluding finance and inflation, but apparently including other owners costs.

In November 2008 TVA updated its estimates for Bellefonte units 3 & 4 for which it had submitted a COL application for twin AP1000 reactors, total 2234 Mwe.  It said that overnight capital cost estimates ranged from $2,516 to $4,649/kW for a combined construction cost of $5.6 to 10.4 billion.  Total cost to the owners would be $9.9 to $17.5 billion.

Regarding bare plant costs, some recent figures apparently for overnight capital cost (or Engineering, Procurement and Construction – EPC – cost) quoted from reputable sources but not necessarily comparable are:

  • Bruce Power Alberta 2×1100 Mwe ACR, $6.2 billion, so $2800/kW;
  • CGNPC Hongyanhe 4×1080 CPR-1000 $6.6 billion, so $1530/kW;
  • AEO Novovronezh 6&7 2136 Mwe net for $5 billion, so $2340/kW;
  • AEP Volgodonsk 3 & 4, 2 x 1200 Mwe VVER $4.8 billion, so $2000/kW;
  • KHNP Shin Kori 3&4 1350 Mwe APR-1400 for $5 billion, so $1850/kW;
  • FPL Turkey Point 2 x 1100 Mwe AP1000 $2444 to $3582/kW;
  • Progress Energy Levy county 2 x 1105 Mwe AP1000 $3462/kW;
  • NRG South Texas 2 x 1350 Mwe ABWR $8 billion, so $2900/kW; and
  • ENEC for UAE from Kepco, 4 x 1400 Mwe APR-1400 $20.4 billion, so $3643/kW.


The maintenance cost of a nuclear power plant includes:  the operating cost; the cost of waste; and the cost of decommissioning.

Effective maintenance of a nuclear power plant is essential for the safe operation of a nuclear power plant.  The facility must be monitored, inspected, tested, assessed and maintained to ensure that the structures, systems, or components (SSCs) function as per design. Various maintenance concepts can be used to form a maintenance strategy.

The majority of maintenance activities are traditionally allocated to the concept of preventive maintenance.  These maintenance activities can be derived, for example, from the safety analysis assumptions; design or reliability requirements, codes and standards, and operating experience and are performed on the basis of service time, actual condition or predicted condition. Where the performance or condition of an SSC does not allow it to function as per design, corrective action must be taken.

The results of all maintenance activities are fed back through an optimization process which enables the continuous improvement of the program.

2.1       Operating Costs:

Fuel costs have from the outset given nuclear energy an advantage compared with coal, oil and gas-fired plants. Uranium, however, has to be processed, enriched and fabricated into fuel elements, and about half of the cost is due to enrichment and fabrication.  In the assessment of the economics of nuclear power allowances must also be made for the management of radioactive used fuel and the ultimate disposal of this used fuel or the wastes separated from it.  But even with these included, the total fuel costs of a nuclear power plant in the OECD are typically about a third of those for a coal-fired plant and between a quarter and a fifth of those for a gas combined-cycle plant.  The US Nuclear Energy Institute suggests that for a coal-fired plant 78 percent of the cost is the fuel, for a gas-fired plant the figure is 89 percent, and for nuclear the uranium is about 14 percent, or double that to include all front end costs.


Fuel costs are one area of steadily increasing efficiency and cost reduction.  For instance, in Spain the nuclear electricity cost was reduced by 29 percent over 1995-2001.  This involved boosting enrichment levels and burn-up to achieve 40 percent fuel cost reduction.  Prospectively, a further 8 percent increase in burn-up will give another 5 percent reduction in fuel cost.

Uranium has the advantage of being a highly concentrated source of energy which is easily and cheaply transportable. The quantities needed are very much less than for coal or oil. One kilogram of natural uranium will yield about 20,000 times as much energy as the same amount of coal. It is therefore intrinsically a very portable and tradable commodity.

The contribution of fuel to the overall cost of the electricity produced is relatively small, so even a large fuel price escalation will have relatively little effect (see below). Uranium is abundant and widely available.

There are other possible savings.  For example, if used fuel is reprocessed and the recovered plutonium and uranium is used in mixed oxide (MOX) fuel, more energy can be extracted.  The costs of achieving this are large, but are offset by MOX fuel not needing enrichment and particularly by the smaller amount of high-level wastes produced at the end. Seven UO2 fuel assemblies give rise to one MOX assembly plus some vitrified high-level waste, resulting in only about 35 percent of the volume, mass and cost of disposal.

Operating costs include operating and maintenance (O&M) plus fuel.  Fuel cost figures include used fuel management and final waste disposal.  These costs, while usually external for other technologies, are internal for nuclear power (i.e. they have to be paid or set aside securely by the utility generating the power, and the cost passed on to the customer in the actual tariff).

The University of Leuven study shows fuel costs to be approximately EUR 6 per MWh, a figure produced with an uncertainty of ± EUR 0.75 per MWh.

Fuel costs are divided into two:  Front-end and Back-end.  The front-end cost is related to actions from the mining of uranium to the loading of the fuel assemblies.  The back-end is related to the unloading of the assemblies, intermediate storage, transport, treatment and long-term storage of the residuals.

It is estimated that between 7 percent and 15 percent of the electricity generation cost of nuclear energy is related to fuel costs. Approximately 75 percent of that is for the front-end and 25 percent for the back-end.

Research shows that the costs of a fuel cycle where used fuel assemblies are not recycled and one where they are reprocessed and reused are roughly the same. This is because the extra reprocessing cost is regained from a lower price for the front-end supply, since about half of the front-end cost is related to the mining and supply of uranium.

2.2       Cost of Waste:

In addition to the routine wastes from current nuclear power generation there are other radioactive wastes referred to as ‘legacy wastes’. These wastes exist in several countries which pioneered nuclear power and especially where power programmes were developed out of military programmes. These are sometimes voluminous and difficult, and arose in the course of those countries getting to a position where nuclear technology is a commercial proposition for power generation. They represent a liability which is not covered by current funding arrangements. In the UK, some £73 billion (undiscounted) is estimated to be involved in addressing these – principally from Magnox and some early AGR developments – and about 30 percent of the total is attributable to military programmes. In the USA, Russia and France the liabilities are also considerable.

Financial provisions are made for managing all kinds of civilian radioactive waste.  The cost of managing and disposing of nuclear power plant wastes represents about 5 percent of the total cost of the electricity generated.

Most nuclear utilities are required by governments to put aside a levy (e.g. 0.1 cents per kilowatt hour in the USA, 0.14 ¢/kWh in France) to provide for management and disposal of their wastes.  So far some US$ 28 billion has been committed to the US waste fund by electricity consumers.

The actual arrangements for paying for waste management and decommissioning also vary.  The key objective is however always the same: to ensure that sufficient funds are available when they are needed.  There are three main approaches:

  • Provisions on the Balance Sheet:

Sums to cover the anticipated costs of waste management and decommissioning are included on the generating company’s balance sheet as a liability.  As waste management and decommissioning work proceeds, the company has to ensure that it has sufficient investments and cash flow to meet the required payments;

  • Internal Fund:

Payments are made over the life of the nuclear facility into a special fund that is held and administered within the company. The rules for the management of the fund vary, but many countries allow the fund to be re-invested in the assets of the company, subject to adequate securities and investment returns; and

  • External Fund:

Payments are made into a fund that is held outside the company, often within government or administered by a group of independent trustees.  Again, rules for the management of the fund vary.  Some countries only allow the fund to be used for waste management and decommissioning purposes, others allow companies to borrow a percentage of the fund to reinvest in their business.

2.3       Decommissioning Cost:

It is now common practice that decommissioning plans and associated cost estimates are prepared for all necessary installations.  Specific requirements are generally set out in regulations that have their basis in national legislations.  These estimates are important for ascertaining the facility.  The long time horizon for both assessing and disbursing these funds is a particular concern for national authorities.  It is this important to maintain a realistic estimate of the liabilities involved and to confirm the adequacy of the provisions to discharge them over time.

The scope of decommissioning generally includes:

  • Decontamination;
  • Removal/Dismantling of Disused Plant and Buildings;
  • Spent Fuel Storage or Disposition of Waste Management;
  • Transport; and
  • Fuel Disposal or Long-Term Storage.

Decommissioning costs are about 9-15 percent of the initial capital cost of a nuclear power plant.  But when discounted, they contribute only a few percent to the investment cost and even less to the generation cost.  In the USA they account for 0.1-0.2 cent/kWh, which is no more than 5 percent of the cost of the electricity produced.

3.         OTHER COSTS:

3.1        System Costs:

System costs are the total costs above plant-level costs (capital and operating) to supply electricity at a given load and given level of security of supply. They include grid connection, extension and reinforcement, short-term balancing costs and long-term costs of maintaining adequate back-up.

They are external to the building and operation of any power plant, but must be paid by the electricity consumer, usually as part of the transmission and distribution cost.  From a government policy point of view they are just as significant as the actual generation cost, but are seldom factored in to comparisons among different supply options, especially comparing base-load with dispersed renewables.   In fact, the total system cost should be analyzed when introducing new power generating capacity on the grid.  Any new power plant likely requires changes to the grid, and hence incurs a significant cost for power supply that must be accounted for.  But this cost for large base-load plants is small compared with integrating renewables to the grid.

The integration of intermittent renewable supply on a preferential basis despite higher unit cost creates significant dis-economies for dispatchable supply, as is now becoming evident in Germany, Austria and Spain, compromising security of supply and escalating costs.  Nuclear system cost is $1-3/MWh.

3.2       External Costs:

The external costs are defined as those actually incurred in relation to health and the environment, and which are quantifiable but not built into the cost of the electricity.  External costs are not included in the building and operation of any power plant, and are not paid by the electricity consumer, but by the community generally.

The report of a major European study of the external costs of various fuel cycles, focusing on coal and nuclear, was released in mid-2001.  It shows that in clear cash terms nuclear energy incurs about one tenth of the costs of coal.  If these costs were in fact included, the EU price of electricity from coal would double and that from gas would increase 30 percent.  These are without attempting to include the external costs of global warming.

The European Commission launched the project in 1991 in collaboration with the US Department of Energy, and it was the first research project of its kind “to put plausible financial figures against damage resulting from different forms of electricity production for the entire EU”.  The methodology considers emissions, dispersion and ultimate impact.  With nuclear energy the risk of accidents is factored in along with high estimates of radiological impacts from mine tailings (waste management and decommissioning being already within the cost to the consumer).  Nuclear energy averages 0.4 euro cents/kWh, much the same as hydro, coal is over 4.0 cents (4.1-7.3), gas ranges 1.3-2.3 cents and only wind shows up better than nuclear, at 0.1-0.2 cents/kWh average.


  1. Columbus CEO – Toshiba and GDF Suez push ahead on British Nuclear Plant;
  2. Nuclear Energy Institute – Fact Sheets;
  3. NucNet Special Report – The Cost of a Nuclear Power Plant;
  4. NEI – White Paper – The Cost of New Generating Capacity in Prospective;
  5. OECD – Cost Estimation for Decommissioning;
  6. IAEA – Financing of New Nuclear Power Plants;
  7. Nuclear Energy Agency – Economics of Nuclear Power FAQs;
  8. Nuclear Energy Institute – Loan Guarantee for the Vogtle Nuclear Power Project;
  9. Nuclear Energy Institute – Knowledge Center;
  10. World Nuclear Association – The Economics of Nuclear Power;
  11. Canada’s Nuclear Regulator – Maintenance Programs for Nuclear Power Plants; and
  12. World Nuclear Association – Radioactive Waste Management.



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