WHITE PAPER - Cost of New Generating Capacity in Perspective

7/29/2019 WHITE PAPER - Cost of New Generating Capacity in Perspective

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January 2012

The Cost of New Generating

Capacity in Perspective

Executive Summary

Like all new generating capacity, there is uncertaintyabout the capital cost of new nuclear power plants. Esti-mates range from $4 billion in todays dollars for the en-gineering, procurement, and construction (EPC) cost of a

single plant to $22.5 billion in 2022 for an entire two-unitproject, including transmission lines and other services.This wide variation in costs can be attributed to severalfactors:

uncertainty about commodity prices and wages, use of different financial assumptions, including the

year in which the costs are projected, and estimates frequently include different scope, which

can make a dramatic difference in cost estimates(see Understanding the Cost Components of NewGenerating Capacity, page 4).

Although new nuclear power plants are capital-intensive,it is important to recognize that capital costs are only thestarting point for any analysis of new generating capaci-ty. The only accurate measure of economic competitive-ness, and the one that is most important to regulatorsand consumers, is the cost of electricity produced by aparticular project compared to alternative sources ofelectricity and to the market price of electricity when thepower plant starts commercial operation. This genera-tion cost takes into account not only capital and financing

costs, but also the operating costs and performance of aproject.

Analysis by generating companies, the academic commu-nity, government agencies, and others shows that evenat capital costs in the $4,000/kWe to $6,000/kWe range,the electricity generated from nuclear power can be com-petitive with other new sources of baseload power. Theseresults do not include the cost impact of restrictions oncarbon dioxide emissions. With regional or national pro-grams that put a significant price on carbon emissions,nuclear power becomes even more competitive.1776 I Street NW Suite 400 Washington DC 20006-3708

www.nei.org


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The Cost of New Generating Capacity in Perspective January 2012

2

Recent Cost Estimates for New Nuclear Power Plants

Although there is uncertainty about the capital cost of new nuclear generatingcapacity, filings with state public utility commissions, and negotiations on engi-neering, procurement and construction (EPC) contracts are beginning to narrowthe range. A more accurate picture of these costs is developing as construction

proceeds on the first projects.

South Carolina Electric & Gas (SCE&G).In February 2009, the SouthCarolina Public Service Commission (PSC) approved a Certificate of Environ-mental Compatibility and Public Convenience and Necessity and for a Base LoadReview Order to construct two additional units at the V.C. Summer Nuclear Sta-tion. SCE&G and Santee Cooper, a state-owned electric and water utility inSouth Carolina, are joint owners of the existing V.C. Summer plant, and willshare costs and generating output of the two new units. In addition, SCE&Gand Santee Cooper have signed an EPC contract with Westinghouse ElectricCompany and Stone & Webster for the design and construction of the twounits.

SCE&G is well into site preparation activities and has purchased long-leadequipment in advance of receiving its combined construction/operating licensefrom the Nuclear Regulatory Commission, anticipated in January 2012. Theproject is running substantially below budget with an approved cost1 of $5.8billion and a cost projection of $5.6 billion. This is down from an original pro-jected cost of $6.9 billion for SCE&Gs 55 percent share of the project.

In addition to providing competitive power generation for customers, the newnuclear capacity will help reduce SCE&Gs greenhouse gas emissions to 50 per-cent of 2005 levels by 2019.

EPC scope is divided into one of three categories: fixed, firm and actual costs.Under SCE&Gs contract, cost elements subject to fixed pricing have no associ-ated escalation rates, while firm elements are subject to definite establishedescalation rates. For example, one class of costs, called Firm with IndexedEscalation, will be priced subject to the Handy-Whitman All Steam GenerationPlant Index, South Atlantic Region.2 This type of pricing offers some certaintyas to what the actual cost for those elements will be. As a result, SCE&G ap-plies a relatively low risk contingency of 5 percent to these cost elements.3

Cost elements such as craft wages, non-labor costs, time and materials, own-ers costs and transmission costs will be paid at actual costs meaningSCE&G will be exposed to real escalation associated with those costs. For plan-ning purposes, SCE&G uses the Handy-Whitman index to estimate these costs,but there is significantly less certainty that estimates will reflect actual costs.Thus for craft wages, SCE&G assumes a high risk and assigns a 20 percentcost contingency. Non-labor costs, time and materials, owners costs andtransmission are all moderate-high risk and are assigned a 15 percent contin-

gency.

1 Base capital cost adjustments reflect South Carolina Public Service Commission Order

2011-345, which removed contingency costs from the approved project amount.2A common escalation index for power plant materials and labor.3

Project contingency accounts for unexpected cost increases and is usually expressed as a

percentage of the cost. Elements such as project complexity, design status, and market

conditions all factor into the contingency.


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3

During the companys June 16, 2011, analysts meeting, the company explainedthat over two-thirds of the construction costs are either spent, fixed or fixedwith fixed escalation costs.

As part of the PSC approval process, SCE&G analyzed a number of strategiesfor meeting South Carolinas electricity needs. The analysis compared a nucle-

ar, natural gas, and coal strategy,4

and examined various environmental com-pliance scenarios and fuel prices. In all cases, SCE&G found nuclear to be themost competitive option over the long run:

It can be seen that the gas strategy would cost SCE&Gscustomers $15.1 million per year more than the nuclear strategyif CO2 costs $15 per ton in 2012 and escalates at 7% per year.With CO2 at $30 per ton, the cost advantage of nuclear would be$125.2 million per year. A higher natural gas price with CO2 at$15 per ton shows a nuclear cost advantage of $68.5 million peryear.

Even in scenarios with assumptions that are unfavorable to nuclear energy,nuclear is considered the optimal strategy:

if uranium fuel prices follow a high track, the nuclear strategystill has a positive advantage over the gas strategy by $13.2 mil-lion per year but if natural gas prices follow a low track, then thegas strategy has the advantage over nuclear by $44.9 million peryear. Additionally, if there is no legislation imposing additionalcosts on CO2 emissions, the gas strategy has an $86.5 millionadvantage over nuclear. However while higher uranium prices arepossible, they are not expected. In addition, it does not seemreasonable at this point to expect low gas prices or no CO2 legisla-tion.

Florida Power and Light Company (FP&L). In October 2007, FP&L filed aPetition for Determination of Need with the Florida PSC for two new nuclearunits at its Turkey Point site. The petition was approved in April 2008. Alt-

hough economic conditions in Florida have pushed back the proposed in-servicedates for the plants to 2022 and 2023 respectively, new nuclear generatingcapacity remains a solid choice for Floridas ratepayers as demand grows.

FP&L provided a non-binding estimate for overnight capital costs of between$3,483/kWe and $5,063/kWe (2011 dollars) in a May 2011 regulatory filing.Final costs will vary depending on the cost of materials escalation, ownersscope and cost, and transmission integration required. FP&L continues to mon-itor current construction costs of other projects and will provide annual updatesto the PSC.

The original estimates for overnight capital cost result in a range of total projectcosts for two units between $12.1 billion and $18 billion in year spent dollars5for two 1,100 MWe reactors. The total project cost includes escalation of 2.5percent and AFUDC calculated at a rate of 11.04 percent.

4 Both the nuclear and the coal strategies include gas capacity in the form of combustionturbine peaking units.5

Year spent dollars are escalated to the year in which spending occurs. FP&L publishedthis estimate in its initial filing for a determination of need. Updated total cost estimatesare not publicly available.

(Continued on page 5)


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4

Understanding the Cost Componentsof New Generating Capacity

An accurate analysis of the cost of new generating capacity requires an understand-ing of precisely what is included in any given set of numbers, particularly when mak-

ing comparisons between generating technologies. The cost of a new power plant ismade up of three major elements:

capital costs (the cost of the equipment, materials and labor required to build

the plant)

financing costs, and

operating costs.

The capital and financing costs make up the total project cost. The cost of electrici-ty from a new power plant includes these costs, as well as the cost of operating thefacility.

New power plant costs are often referred to as overnight costs. Overnight cost

literally represents the cost to complete a construction project overnight. It usuallyincludes engineering-procurement-construction (EPC) costs1 and ownerscosts,2 but is net of financing costs and does not account for inflation or escalation.

Capital cost estimates can be misleading unless it is clear what assumptions standbehind them. They may or may not include contingencies to account for factorssuch as project complexity, design status, market conditions or first-of-a-kind tech-nologies. They can also represent the cost for more than one unit. These assump-tions can account for differences of hundreds of millions of dollars.

The total cost of a power project should include all capital costs, contingencies andfinancing costs. Financing costs will depend on the rate obtained on the debt, pro-ject leverage, and whether the plant is built as part of a regulated entitys rate base

or as a merchant plant. Some projects may obtain more favorable financing termsthrough federal loan guarantees or state policies to recover carrying costs throughrates during construction. Total project cost may also include escalation to inflatecosts to the value of the year in which the dollars will be spent.3

The total cost of a power project is also reflected in the cost of electricity producedby the plant or the busbar cost. It includes the capital and financing costs for theproject as well as the cost of operation, maintenance and fuel once the plant is pro-ducing power. It also includes the return on equity investment in the project.

1EPC costs include the cost of engineering, materials and labor for the construction of the

power plant.2 Owners costs include other infrastructure transmission upgrades, cooling towers, water

intake and treatment systems, administrative buildings, warehouses, roads, switchyards, as

well as project management and development costs, permitting, taxes, legal, staffing and training.3 Costs expressed in 2015 dollars will be greater than the same costs expressed in 2007 dollars

because of the time value of money.


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5

In its May 2011 regulatory filing, FP&L evaluated the comparative economics ofa new natural gas combined cycle generating unit. FP&L looked at seven eco-nomic scenarios incorporating a range of potential natural gas prices and envi-ronmental compliance costs. The conclusion:

Turkey Point 6 & 7 are projected to be cost-effective in 6of these 7 scenar-ios and are breakeven in the remaining scenario which assumes a combina-

tion of low fuel costs and low environmental costs for the entire analysisperiod.

FPL expects that the Turkey Point 6 & 7 project will:

Provide estimated fuel cost savings for FPLs customers of approxi-mately $1.1 billion (nominal) in the first full year of operation;

Provide estimated fuel cost savings for FPLs customers over the life ofthe project of approximately $75 billion (nominal);

Diversify FPLs fuel sources by decreasing reliance on natural gas byapproximately 13% beginning in the first full year of operation;

Reduce annual fossil fuel usage by the equivalent of 177 million barrelsof oil or 28 million BTU of natural gas; and

Reduce C02 emissions by an estimated 287 million tons over the life ofthe project, which is the equivalent of operating FPLs entire generat-ing system with zero C02 emissions for 7 years.

Turkey Point 6 & 7 are projected to be solidly cost-effective and to providevaluable firm capacity, energy, and fuel diversity for FPLs customers.

Progress Energy Florida filed a Petition for Determination of Need with theFlorida PSC in March 2008 for its proposed Levy Nuclear Power Plant (LNP).The petition was approved in July 2008. Progress has since revised the in-service dates for the two units to 2021 and 2022 in response to the economicconditions in Florida. Progress non-binding overnight cost estimate for its two-unit greenfield site was $4,260/kWe (2007 dollars) in the original filing.7 Pro-

gress current estimate is $17.2 to $22.5 billion including land, transmissionlines, fuel and financing costs. The overnight cost estimate has not been up-dated in public documents at this time.

Nuclear Cost Estimates from Recent Public Service Commission Filings

CompanyPlant

Capacity(MWe)

Overnight CapitalCost ($/kWe)

TotalProject Cost(Billion $)

SCE&G/SanteeCooper

2,200 3,719 9.8

FP&L 2,200 3,483 5063 12.1 18

Progress 2,200 4,2606 17.2 22.5

6 Progress Energy published this estimate in its initial filing for a determination of need.

Updated overnight capital cost estimates are not publicly available. Total project cost esti-

mates reflect an April 2010 update.7 Average for two units, based on a summer capacity rating of 2,184 MWe for two

Westinghouse AP1000 units. This estimate is from an initial regulatory filing. Updated cost

projections are not publicly available.

Turkey Point 6 &

7 are projected to

be solidly cost-

effective and to

provide valuable

firm capacity,

energy, and fuel

diversity for FPLs

customers.


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6

In a May 2011 filing with the Florida Public Service Commission, Progress pro-vided the results of an updated cumulative present value revenue requirements(CPVRR) analysis. The recent analysis has updated fuel, environmental andcarbon compliance cost estimates, but utilizes the same capital cost estimatesand in-service dates that were provided in the 2010 update:

As a result, the updated CPVRR produces results that are slightly morefavorable to the LNP than the CPVRR results in the LNP need case eventhough the updated CPVRR analysis assumes later in-service dates for theLevy units and a corresponding higher total project cost than the needcase CPVRR analysis.

In the initial filing, Progress compared the proposed nuclear units with otherviable generation alternatives. Nuclear, pulverized coal and atmospheric fluid-ized bed combustion (AFBC) and coal IGCC were evaluated against an all natu-ral gas generation reference case:8

Nuclear generation technology fared better than AFBC, pulver-ized coal and coal gasification against the all natural gas referencecase in preliminary evaluations. Further, nuclear generationappeared to be the most viable generation alternative to naturalgas generation because (1) significant, potential environmentalcosts were associated with AFBC, pulverized coal and coal gasifi-cation resulting from GHG and possible carbon capture or carbonabatement costs, and (2) there were recent regulatory and utilitydecisions to forego AFBC, pulverized coal and coal gasificationgeneration options in Florida.

Progress also found that, when evaluated over their expected 60-year operatinglives, Levy 1 & 2 were more economic than an all-natural gas scenario:

When one analyzes the nuclear project over sixty years, andtakes into account the air emission compliance cost, fuel diversity,

and fossil fuel dependence concerns that the Florida Legislaturerequires the utility to consider, nuclear is generally more cost-effective than an all natural gas resource plan

8Natural gas generation, based on relative capital costs, experience with the technology

and environmental factors, was considered the default supply-side generation alternative to

the other viable generation resources.

When one

analyzes the

nuclear project

over sixty years,

and takes into

account air

emission

compliance cost,

fuel diversity, and

fossil fuel

dependence

concerns ...

nuclear is

generally more

cost-effective.


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Independent Analyses of Cost of New Generating Capacity

Several academic institutions, research organizations and government agencieshave conducted analyses of the cost of electricity from various generating op-tions. Although the findings, expressed in dollars per megawatt-hour, may dif-fer from analysis to analysis (a product of differing assumptions), all these anal-

yses point in the same direction: new nuclear plants can be competitive withother options when they are placed in service and are likely to be comfortablycompetitive in a carbon-constrained world.

Electric Power Research Institute (EPRI). The Electric Power ResearchInstitute is a non-profit research organization funded by companies that pro-duce and deliver over 90 percent of the electricity in the U.S. and internationalmembers from 40 countries. EPRIs Program on Technology Innovation con-ducts research to estimate the costs of electricity generating technologies overtime.

EPRIs most recent update included estimated costs for a range of generatingtechnologies in 2015 and 2025. For each technology, the analysis provides the

levelized cost of electricity (LCOE). The updated report assumes significantimprovements in renewable technology cost and output. The report also pro-vides costs for carbon capture and storage for coal and gas technologies in2025.

Since nuclear technology for large reactors is based on existing technology, theLCOE range does not change in the 2015 to 2025 time frame. However, the

Representative Cost for Power Generation Technologies in 2015All Costs in Constant

Dec. 2010$Nominal Plant

Capacity, MWCapacity

FactorTotal Plant Cost

$/kWTotal Capital

Required$/kW

LevelizedElectricity Cost

$/MWhCoal: PC 750 80% 2,000 - 2,300 2,400 - 2,760 54 - 60Coal: IGCC 600 80% 2,600 - 2,850 3,150 - 3,450 68 - 73Natural Gas: NGCC 550 80% 1,060 - 1,150 1,275 - 1,375 49 - 79Nuclear 1,400 90% 3,900 - 4,400 5,250 - 5,900 76 - 87Biomass, Bubbling Fluid-ized Bed 100 85% 3,500 - 4,400 4,000 - 5,000 84 - 147Wind: Onshore 100 28 - 40% 2,025 - 2,700 2,120 - 2,825 75 - 138Wind: Offshore 200 40% 3,100 - 4,000 3,250 - 4,200 130 - 159Solar: ConcentratingSolar Thermal (CST) 100 - 250 25 - 49% 3,300 - 5,300 4,050 - 6,500 151 - 195Solar: Photovoltaic (PV) 10 15 - 28% 3,400 - 4,600 3,725 - 5,050 242 - 455Source: Electric Power Research Institute Program on Technology Innovation: Integrated Generation TechnologyOptions, June 2011.


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analysis shows that nuclear is among the most competitive sources of non-carbon electricity even after other technology advances are taken into consider-ation.

Massachusetts Institute of Technology (MIT). The MIT Center for Energyand Environmental Policy Research issued a report in 2003 (The Future of Nu-clear Power), which explored the challenges to nuclear energy expansion andoptions to overcome them. The study was based on the premise that nuclearenergy is an important technology for the U.S. and the world to meet futureenergy needs while addressing environmental concerns associated with carbondioxide emissions.

In 2009, MIT updated that report and the economic analysis in the originalstudy, including new information from utility cost estimates for actual projectsthat was not available in 2003. The update compares the levelized cost of elec-

tricity from new nuclear plants to the coal-fired and gas-fired plants used inbaseload generation of electricity. The study (see table below) shows that nu-clear energy is cost-competitive at 6.6/kWh (vs. 6.2/kWh for coal and 6.5/kWh for gas) if the technology risk premium is removed from the financing as-sumptions (i.e., when the first few plants have been built and investors areconfident that they can be built to cost and schedule). The study also showsthat nuclear plants become increasingly competitive as the price of carbon in-creases. The example provided in the report showed that a $25/ton carbon taxwould increase the price of coal-fired generation to 8.3/kWh and gas-firedgeneration to 7.5/kWh (nuclear remains at 6.6/kWh).

Representative Cost for Power Generation Technologies in 2025All Costs in Constant

Dec. 2010$ Nominal PlantCapacity, MW CapacityFactor Total Plant Cost$/kWTotal Capital

Required$/kW

LevelizedElectricity Cost

$/MWhCoal: PC with CarbonCapture 600 80% 3,200 - 4,100 3,850 - 4,920 87 - 105Coal: IGCC with CarbonCapture 500 80% 3,100 - 3,800 3,750 - 4,600 85 - 101Natural Gas: NGCC 550 80% 1,060 - 1,150 1,275 - 1,375 47 - 74Natural Gas: NGCC withCarbon Capture 450 80% 1,600 - 1,900 1,900 - 2,250 68 - 109Nuclear 1,400 90% 3,800 - 4,250 5,100 - 5,700 76 - 87Biomass, Bubbling Fluid-ized Bed 100 85% 3,400 - 4,250 3,900 - 4,850 80 - 136Wind: Onshore 100 28 - 40% 1,960 - 2,600 2,050 - 2,720 73 - 134Wind: Offshore 200 40% 2,850 - 3,650 3,000 - 3,825 122 - 147Solar: ConcentratingSolar Thermal (CST) 100-250 26 - 58% 3,000 - 4,800 3,700 - 5,900 116 - 173Solar: Photovoltaic (PV) 10 15 - 28% 2,900 - 3,950 3,175 - 4,325 210 - 396Source: Electric Power Research Institute Program on Technology Innovation: Integrated Generation Technology Op-tions, June 2011.


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Energy Information Administration (EIA). The Energy Information Ad-ministration (the independent statistical arm of the U.S. Department of Energy)publishes an annual forecast called the Annual Energy Outlook (AEO), whichincludes estimates of the capital cost of all generating technologies and theirlikely market penetration out to 2035. AEO 2011 provides the expected aver-age national levelized cost of electricity from various generating technologies in2016 (see table below). This data comes from the reference case of AEO 2011,prepared using the National Energy Modeling System (NEMS).

Technology Nuclearwith riskpremium

Nuclearw/o riskpremium Coal Gas

Capital Cost($2007/kW) 4,000 4,000 2,300 850Fuel($2007/mmBtu) 0.67 0.67 2.60 7.00Weighted average cost ofcapital (WACC) 10% 7.8% 7.8% 7.8%Levelized Cost(/kWh) 8.4 6.6 6.2 6.5Levelized Cost(/kWh) with $25/tCO2 8.3 7.5

Levelized Cost of Baseload Electricity

Source: Massachusetts Institute of Technology, Update on the Cost of Nuclear Power,May 2009

U.S. Average Levelized Costs (2009 $/MWh)for Plants Entering Service in 2016

CapacityFactor (%)

Range

Minimum Average Maximum

Natural Gas - ConventionalCombined Cycle

87 60.0 66.1 74.1

Hydro 52 58.5 86.4 121.4

Natural Gas - Advanced CCwith CCS

87 80.8 89.3 104.0

Wind - Onshore 34 81.9 97.0 115.0

Geothermal 92 91.8 101.7 115.7

Advanced Coal 85 100.7 109.4 122.1

Biomass 83 99.5 112.5 133.4

Advanced Nuclear 90 109.7 113.9 121.4

Advanced Coal with CCS 85 126.3 136.2 154.5

Solar PV 25 158.7 210.7 323.9

Wind - Offshore 34 186.7 243.2 349.4

Solar Thermal 18 191.7 311.8 641.6

Plant Type

Source: Energy Information Administration, Annual Energy Outlook 2011, April 2011,DOE/EIA-0383 (2011)


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The values shown in the EIA analysis do not include financial incentives such asstate or federal tax credits. A 3-percentage point increase in the cost of capitalis included for technologies that are greenhouse gas intensive (coal-fired andcoal-to-liquids plants without CCS). This adjustment is similar to a $15 per toncarbon tax. Additional system investments such as transmission are included,but the cost of back-up power for intermittent resources such as wind and solar

is not included in this analysis. The EIA results indicate that nuclear energy isone of the least-cost technologies that does not emit greenhouse gases.

National Research Council Americas Energy Future Project. The Na-tional Research Council (NRC), an arm of the National Academy of Sciences andthe National Academy of Engineering, has a Committee on Americas EnergyFuture, which published a report in 2009 titled, Americas Energy Future: Tech-nology and Transformation. The project started in 2007 in anticipation of leg-islative interest in energy policy in the U.S. Congress given the pressing de-mands of energy security, global climate change, recent volatility in energyprices, and necessary future investment in the U.S. energy infrastructure. TheNational Research Council study evaluates contributions and estimated costs ofexisting and new energy technologies.

The report concludes that it is imperative to demonstrate the commercial viabil-ity of new nuclear power plants through the construction of a suite of aboutfive plants by 2020, in addition to the demonstration of CCS technologies forcoal and natural gas through construction of 15-20 retrofitted and new demon-stration plants. According to the report, evaluating the viability of these tech-nologies as soon as possible will help preserve the portfolio approach necessaryto address greenhouse gas reductions:

A failure to demonstrate the viability of these technologies during the nextdecade would greatly restrict options to reduce the electricity sectors CO2emissions over succeeding decades. The urgency of getting started onthese demonstrations cannot be overstated.

Levelized Cost of Electricity for New Baseload Sources

0 5 10 15 20 25 30

Solar CSP

Solar PV

Wind (onshore)

Wind (offshore)

Coal-CCS

Coal

NGCC-CCS (Low)

NGCC (Low)

NGCC-CCS (High)

NGCC (High)

Nuclear

Geothermal

Biopower

Source: National Research Council of the National Academies,Americas Energy Future: Technology and Transformation

Levelized Cost of Electricity for New Intermittent Sources

8-10

10

6-13

10-16

14-21

4-7

7-10

5-9

9-15

5-18

4-10

14-30

8-20

2007 Cents per kilowatt-hour

A failure to

demonstrate the

viability of these

technologies

during the next

decade would

greatly restrict

options to reduce

. . . emissions.


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11

The report modeled levelized costs of electricity for several different technolo-gies. The cost ranges shown in the graph (below) can be attributed to manyfactors, including different assumptions about financing, capital costs, capacityfactor, fuel costs, and others. For nuclear energy the range is from 6/kWh to13/kWh. The low end of the range corresponds to plants that secure low-costfinancing through the DOEs loan guarantee program. As indicated in the re-

port, natural gas could be the lowest- or the highest-cost option, depending onthe price of the fuel, with a cost range from 4/kWh to 16/kWh (and up to21/kWh if gas prices are high and CCS technology is added). When comparedwith other non-emitting technologies, the analysis shows that nuclear plantscan be competitive:

These levelized costs are higher than the current average cost of whole-sale electricity, but they are likely to be comparable to future costs of elec-tricity from other sources, particularly if fossil fuel plants are required tostore CO2 or pay a carbon fee.

Putting Nuclear Cost Estimates in Perspective

Although nuclear project costs are undeniably large, total project cost does notmeasure a projects economic viability. The relevant metric is the cost of theelectricity produced by the nuclear project relative to alternative sources ofelectricity and relative to the market price of electricity at the time the nuclearplant comes into service. As illustrated by the detailed financial modeling citedabove, new nuclear power plants can be competitive, even with total projectcosts exceeding $6,000/kWe, including EPC and owners costs and financingcosts.

These findings are confirmed by results from the Nuclear Energy Institute (NEI)financial model9 (see Table 1, page 12). NEIs modeling shows that a merchantnuclear plant with an 80 percent debt/20 percent equity capital structure, sup-ported by a federal loan guarantee, will produce electricity in the range of $84/MWh to $91/MWh. (The range reflects EPC costs from $4,500/kWe to $5,000/

kWe.) Nuclear energy is competitive with coal generation and offers fuel diver-sity and protection against future carbon costs or fossil fuel price spikes.

The results above assume no restrictions on carbon dioxide emissions. If a car-bon price of $30/ton is incorporated, nuclear power becomes even more com-petitive. Generation from natural gas increases by around $18/MWh, while thecost of electricity from IGCC and SCPC increases by roughly $25/MWh.

NEIs modeling shows that, in the absence of a significant price for carbon,loan guarantees are an important tool to reduce the cost of electricity producedby merchant nuclear plants; construction work in progress (CWIP)10 has a simi-lar benefit for regulated companies. With this support as a transition to a car-bon-constrained world, the next nuclear plants can be competitive and econom-

ically viable.

Although nuclear

project costs are

undeniably large,

total project costdoes not measure

a projects

economic viability.

The relevant

metric is the cost of

the electricity

produced by the

nuclear project

relative to

alternative sources

of electricity and

relative to the

market price of

electricity at the

time the nuclear

plant comes

into service.

9 The NEI Financial Model is a detailed financial pro-forma model used to estimate totalproject, first year and levelized busbar costs for new generating capacity built in eitherutility-regulated rate base or private sector project finance environments. The modelwas constructed and tested by NEI staff in consultation with financial, utility, and otherindustry experts.10

CWIP is a ratemaking technique under which a company can recover financing costsduring construction.


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Table1.CostofElectricityfro

mVariousGeneratingTechnolog

ies(in2011Dollars)1

Technology

Nuclear

Coal

(SCPC)

Coa

l

(IGC

C)

Gas

(CombinedCycle)

ProjectStructure

ProjectFinance

with

LoanGuarantee

80%D

ebt

20%E

quity

RateBase

withCWIP2

50%D

ebt

50%E

quity

RateBase

withCWIP

50%D

ebt

50%E

quity

ProjectFinance

with

LoanGuarantee

80%D

ebt

20%E

quity

RateBase

withCWIP

50%D

ebt

50%E

quity

ProjectFinance

50%D

ebt

50%E

quity

EPCCost

($/kWe)

$4,5

00-5,0

00

$3,2

00

$3,600

$1,000

TotalCost3

($/kWe)

$6,0

00-$6,6

00

$5,3

00-$5,8

00

$3,5

00

$4,5

00

$4,0

00

$1,2

00

$1,2

00

FuelCost

(nuclear-$/MWh)

(coal/gas-$/mmBtu)

$7.5

0

$2.0

0

$2.0

0

$4.0

0

$6.0

0

Capacity

(MWe)

1,4

00

800

600

400

FirstYearBusbar

($/MWh)

$84-91

$115-$126

$99

$81

$113

$56

$70

LevelizedBusbar

($/MWh)

NA

$86-$93

$75

NA

$85

NA

NA

ImpactofC02

Priceat$30/Ton

($/MWh)

NA

NA

Add$25.00

Add$2

5.00

Add$1

8.00

Notes:Thenuclearcasesassume48-monthconstruction,6-monthstart-up;ownerscostof$300/kWeand10%contingency;6.5%interestrateoncommercialdebtforunreg-

ulatedentities,6.0%interest

rateoncommerciald

ebtforregulatedentities,4.5

%interestrateongovernment-gua

ranteeddebt,1

5%returnonequityforpro

jectfinanceand

12%allowedrateofreturnforratebase;2%loanguaranteecost;90%

capacityfactor;O&Mcostof$9.5

0/MWhandfuelc

ostof$7.5

0/MWh.Thecapitalcos

testimatesfor

supercriticalp

ulverizedcoal(SCPC)andintegratedgasificationcombined

cycle(IGCC)arefromtheEnergyInformationAdministration.

12

TheCostofNewGeneratingCa

pacityinPerspective

January2012

1

Estimatescalculatedusin

gtheNEIFinancialModel,Version8.1

0,A

ugust2010.

2

CWIP=ConstructionWo

rkInProgress

3

EstimatedTotalCostvaluesfromtheNEIFinancialModelinclude

EPCcost,ownerscosts,decommissioningfunding(nuclearunitsonly),andfinan

cing.

Valuesare

roundedtonearesthundre

d.

Documents

WHITE PAPER - Cost of New Generating Capacity in Perspective