QUALITY GUIDELINES

FOR ENERGY SYSTEM STUDIES

Cost Estimation Methodology for

NETL Assessments of Power Plant

Performance

March 2010

DOE/NETL-2010/????

April 2011

DOE/NETL-2011/1455
National Energy Technology Laboratory Office of Program Planning and Analysis

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Power Plant Cost Estimation Methodology

Quality Guidelines for Energy Systems Studies

April 2011

Quality Guidelines for Energy Systems Studies

Cost Estimation Methodology for NETL Assessments 

of Power Plant Performance

Introduction

This paper summarizes the costing methodology employed by NETL in its costing models and baseline 

reports. Further, it defines the specific levels of capital cost as well as outlines the costing metrics by which 

NETL evaluates various power producing plants. These metrics and a clear understanding of the methodology 

used are essential in allowing different power plant technologies to be compared on a similar basis. Though 

these guidelines are tailored for power producing plants, they can also be applied to a variety of different 

revenue generating plants (e.g., coal to liquids, syngas generation, hydrogen).

Capital Costs

Levels of Capital Costs

As illustrated by Figure 1, this methodology defines capital cost at five levels: BEC, EPCC, TPC, TOC and 

TASC. BEC, EPCC, TPC and TOC are “overnight” costs and are expressed in “base-year” dollars. The base 

year is the first year of capital expenditure. TASC is expressed in mixed, current-year dollars over the entire 

capital expenditure period, which is assumed in most NETL studies to last five years for coal plants and three 

years for natural gas plants.

The Bare Erected Cost (BEC) comprises the cost of process equipment, on-site facilities and infrastructure that 

support the plant (e.g., shops, offices, labs, road), and the direct and indirect labor required for its construction 

and/or installation. The cost of EPC services and contingencies are not included in BEC. BEC is an overnight 

cost expressed in base-year dollars.

The Engineering, Procurement and Construction Cost (EPCC) comprises the BEC plus the cost of services 

provided by the engineering, procurement and construction (EPC) contractor. EPC services include: detailed 

design, contractor permitting (i.e., those permits that individual contractors must obtain to perform their scopes 

of work, as opposed to project permitting, which is not included here), and project/construction management 

costs. EPCC is an overnight cost expressed in base-year dollars.

The Total Plant Cost (TPC) comprises the EPCC plus project and process contingencies. TPC is an overnight 

cost expressed in base-year dollars.

The Total Overnight Capital (TOC) comprises the TPC plus all other overnight costs, including owner’s costs. 

TOC is an “overnight” cost, expressed in base-year dollars and as such does not include escalation during 

construction or interest during construction. TOC is an overnight cost expressed in base-year dollars.

The Total As-Spent Capital (TASC) is the sum of all capital expenditures as they are incurred during the capital 

expenditure period including their escalation. TASC also includes interest during construction. Accordingly, 

TASC is expressed in mixed, current-year dollars over the capital expenditure period. 
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Figure 1: Capital Cost Levels and their Elements

Cost Estimate Classification

Recommended Practice 18R-97 of the Association for the Advancement of Cost Engineering International 

(AACE) describes a Cost Estimate Classification System as applied in Engineering, Procurement and 

Construction for the process industries.

Most techno-economic studies completed by NETL feature cost estimates intended for the purpose of a 

“Feasibility Study” (AACE Class 4). Table 1 describes the characteristics of an AACE Class 4 Cost Estimate.

Cost estimates in most NETL studies have an expected accuracy range of -15%/+30%.

Table 1: Features of an AACE Class 4 Cost Estimate

Project 

Definition Typical Engineering Completed Expected Accuracy

1 to 15%

• plant capacity, block schematics, 

indicated layout, process flow diagrams 

for main process

• systems, and preliminary engineered 

process and utility

• equipment lists

-15% to -30% on the low side, 

and +20% to +50% on the 

high side

process equipment

supporting facilities

direct and indirect 

labor

BEC

EPCC

TPC

TOC

TASC

EPC contractor services

process contingency

project contingency

pre-production costs

inventory capital

financing costs

other owner’s costs

escalation during capital expenditure period

interest on debt during capital expenditure period

Bare Erected Cost

Engineering, Procurement 

and Construction Cost

Total Plant Cost

Total Overnight Cost

Total As-Spent Cost

BEC, EPCC, TPC and TOC are 

all “overnight” costs 

expressed in base-year dollars.

TASC is expressed in mixedyear current dollars, spread 

over the capital expenditure 

period.
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Contracting Strategy and EPC Contractor Services 

The cost estimates are based on an engineering, procurement and construction management (EPCM)

contracting strategy utilizing multiple subcontracts. This approach provides the Owner with greater control of

the project, while minimizing, if not eliminating most of the risk premiums typically included in an EPC contract 

price. In a traditional lump sum EPC contract, the Contractor assumes all risk for performance, schedule, and 

cost. However, as a result of current market conditions, EPC contractors appear more reluctant to assume 

that overall level of risk. Rather, the current trend appears to be a modified EPC approach where much of the 

risk remains with the Owner. Where Contractors are willing to accept the risk in EPC type lump-sum 

arrangements, it is reflected in the project cost. In today’s market, Contractor premiums for accepting these 

risks, particularly performance risk, can be substantial and increase the overall project costs dramatically. 

The EPCM approach used as the basis for the estimates is anticipated to be the most cost effective approach 

for the Owner. While the Owner retains the risks, the risks become reduced with time, as there is better scope 

definition at the time of contract award(s).

EPCM contractor services are estimated at 8 to 10 percent of BEC. These costs consist of all home office 

engineering and procurement services as well as field construction management costs. Site staffing generally 

includes a construction manager, resident engineer, scheduler, and personnel for project controls, document 

control, materials management, site safety, and field inspection.

Estimation of Capital Cost Contingencies

Process and project contingencies are included in estimates to account for unknown costs that are omitted or 

unforeseen due to a lack of complete project definition and engineering. Contingencies are added because 

experience has shown that such costs are likely, and expected, to be incurred even though they cannot be 

explicitly determined at the time the estimate is prepared. 

Capital cost contingencies do not cover uncertainties or risks associated with

- scope changes

- changes in labor availability or productivity

- delays in equipment deliveries

- changes in regulatory requirements

- unexpected cost escalation

- the performance of the plant after startup (e.g., availability, efficiency). 

Process Contingency

Process contingency is intended to compensate for uncertainty in cost estimates caused by performance 

uncertainties associated with the development status of a technology. Process contingencies are applied to 

each plant section based on its current technology status.

As shown in Table 2, AACE International Recommended Practice 16R-90 provides guidelines for estimating 

process contingency.

Table 2: AACE Guidelines for Process Contingency

Technology Status Process Contingency

(% of Associated Process Capital)

New concept with limited data 40+

Concept with bench-scale data 30-70

Small pilot plant data 20-35

Full-sized modules have been operated 5-20

Process is used commercially 0-10
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Process contingency is typically not applied to costs that are set equal to a research goal or programmatic 

target since these values presume to reflect the total cost.

Project Contingency

AACE 16R-90 states that project contingency for a “budget-type” estimate (AACE Class 4 or 5) should be 15% 

to 30% of the sum of BEC, EPC fees and process contingency.

Estimation of Owner’s Costs

Table 3 explains the estimation method for owner’s costs. With some exceptions, the estimation method 

follows guidelines in Sections 12.4.7 to 12.4.12 of “Conducting Technical and Economic Evaluations – As 

Applied for the Process and Utility Industries”, AACE International Recommended Practice No. 16R-90. The 

Electric Power Research Institute’s (EPRI) “Technical Assessment Guide (TAG®) – Power Generation and 

Storage Technology Options” also has guidelines for estimating owner’s costs. The EPRI and AACE 

guidelines are very similar. 

Table 3: Estimation Method for Owner’s Costs

Owner’s Cost Estimate Basis

Prepaid 

Royalties

Any technology royalties are assumed to be included in the associated equipment 

cost, and thus are not included as an owner’s cost.

Preproduction 

(Start-Up) 

Costs

• 6 months operating labor

• 1 month maintenance materials at full capacity

• 1 month non-fuel consumables at full capacity

• 1 month waste disposal 

• 25% of one month’s fuel cost at full capacity

• 2% of TPC

Compared to AACE 16R-90, this includes additional costs for operating labor (6 

months versus 1 month) to cover the cost of training the plant operators, including 

their participation in startup, and involving them occasionally during the design and 

construction. AACE 16R-90 and EPRI TAG® differ on the amount of fuel cost to 

include; this estimate follows EPRI.

Working 

Capital

Although inventory capital (see below) is accounted for, no additional costs are 

included for working capital.

Inventory 

Capital

• 0.5% of TPC for spare parts

• 60 day supply (at full capacity) of fuel. Not applicable for natural gas.

• 60 day supply (at full capacity) of non-fuel consumables (e.g., chemicals and 

catalysts) that are stored on site. Does not include catalysts and adsorbents that

are batch replacements such as WGS, COS, and SCR catalysts and activated 

carbon.

AACE 16R-90 does not include an inventory cost for fuel, but EPRI TAG® does.

Land • $3,000/acre (300 acres for IGCC and PC, 100 acres for NGCC)
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Owner’s Cost Estimate Basis

Financing 

Cost

• 2.7% of TPC

This financing cost (not included by AACE 16R-90) covers the cost of securing 

financing, including fees and closing costs but not including interest during 

construction (or AFUDC). The “rule of thumb” estimate (2.7% of TPC) is based on a 

2008 private communication with a capital services firm.

Other 

Owner’s 

Costs

• 15% of TPC

This additional lumped cost is not included by AACE 16R-90 or EPRI TAG®. The 

“rule of thumb” estimate (15% of TPC) is based on a 2009 private communication 

with Worley-Parsons. The lumped cost includes:

- Preliminary feasibility studies, including a Front-End Engineering Design (FEED) 

study

- Economic development (costs for incentivizing local collaboration and support)

- Construction and/or improvement of roads and/or railroad spurs outside of site 

boundary

- Legal fees

- Permitting costs

- Owner’s engineering (staff paid by owner to give third-party advice and to help 

the owner oversee/evaluate the work of the EPC contractor and other contractors)

- Owner’s contingency (Sometimes called “management reserve”, these are funds 

to cover costs relating to delayed startup, fluctuations in equipment costs, 

unplanned labor incentives in excess of a five-day/ten-hour-per-day work week. 

Owner’s contingency is NOT a part of project contingency.)

This lumped cost does NOT include:

- EPC Risk Premiums (Costs estimates are based on an Engineering Procurement 

Construction Management approach utilizing multiple subcontracts, in which the 

owner assumes project risks for performance, schedule and cost)

- Transmission interconnection: the cost of interconnecting with power 

transmission infrastructure beyond the plant busbar.

- Taxes on capital costs: all capital costs are assumed to be exempt from state and 

local taxes.

- Unusual site improvements: normal costs associated with improvements to the 

plant site are included in the bare erected cost, assuming that the site is level and 

requires no environmental remediation. Unusual costs associated with the 

following design parameters are excluded: flood plain considerations, existing 

soil/site conditions, water discharges and reuse, rainfall/snowfall criteria, seismic 

design, buildings/enclosures, fire protection, local code height requirements, noise 

regulations.
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Cost Estimate Scope

All estimates represent a complete power plant facility on a generic site. The plant boundary limit is defined as 

the total plant facility within the “fence line” including coal receiving and water supply system, but terminating at 

the high voltage side of the main power transformers. The only cost outside of this “fence line” that is 

accounted for is the cost of CO2 transport, storage, and monitoring (TS&M). TS&M costs are embedded in the 

reported COE but are not represented in the plant capital or O&M costs.

Some typical examples of items outside the fence line include:

- New access roads and railroad tracks

- Upgrades to existing roads to accommodate increased traffic

- Makeup water pipe outside the “fence line”

- Landfill for on-site waste (slag) disposal

- Natural gas line for backup fuel provisions

- Plant switchyard

- Electrical transmission lines & substation

Other items that are not addressed in the cost estimates are:

- Piles or caissons

- Rock removal

- Excessive dewatering

- Expansive soil considerations

- Excessive seismic considerations

- Extreme temperature considerations

- Hazardous or contaminated soils

- Demolition or relocation of existing structures

- Leasing of offsite land for parking or laydown

- Busing of craft to site

- Costs of offsite storage

All estimates are based on a reasonably “standard” plant. No unusual or extraordinary process equipment is 

included such as:

- Excessive water treatment equipment

- Air-cooled condenser

- Automated coal reclaim

- Zero Liquid Discharge equipment

- SCR catalyst (IGCC cases only)
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Economic Analysis

Global Economic Assumptions

Global economic assumptions are listed in Table 4.

Table 4: Global Economic Assumptions

Parameter Value

TAXES

Income Tax Rate 38% Effective (34% Federal, 6% State)

Capital Depreciation 20 years, 150% declining balance

Investment Tax Credit 0%

Tax Holiday 0 years

CONTRACTING AND FINANCING TERMS

Contracting Strategy Engineering Procurement Construction Management (owner 

assumes project risks for performance, schedule and cost)

Type of Debt Financing Non-Recourse (collateral that secures debt is limited to the 

real assets of the project)

Repayment Term of Debt 15 years

Grace Period on Debt Repayment 0 years

Debt Reserve Fund None

ANALYSIS TIME PERIODS

Capital Expenditure Period Natural Gas Plants: 3 Years

Coal Plants: 5 Years

Operational Period 30 years

Economic Analysis Period (used for 

IRROE)

33 or 35 Years (capital expenditure period plus operational 

period)

TREATMENT OF CAPITAL COSTS

Capital Cost Escalation During Capital 

Expenditure Period (nominal annual rate) 3.6%1

Distribution of Total Overnight Capital 

over the Capital Expenditure Period 

(before escalation)

3-Year Period: 10%, 60%, 30%

5-Year Period: 10%, 30%, 25%, 20%, 15%

Working Capital zero for all parameters

% of Total Overnight Capital that is 

Depreciated

100% (this assumption introduces a very small error even if 

a substantial amount of TOC is actually non-depreciable)

ESCALATION OF OPERATING REVENUES AND COSTS

Escalation of COE (revenue), O&M 

Costs, Fuel Costs (nominal annual rate) 3.0%2

 1 A nominal average annual rate of 3.6% is assumed for escalation of capital costs during construction. This rate is equivalent to the 

nominal average annual escalation rate for process plant construction costs between 1947 and 2008 according to the Chemical 

Engineering Plant Cost Index. 2 An average annual inflation rate of 3.0% is assumed. This rate is equivalent to the average annual escalation rate between 1947 and 

2008 for the U.S. Department of Labor's Producer Price Index for Finished Goods, the so-called "headline" index of the various 

Producer Price Indices. (The Producer Price Index for the Electric Power Generation Industry may be more applicable, but that data 

does not provide a long-term historical perspective since it only dates back to December 2003.)
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Finance Structures

Finance structures were chosen based on the assumed type of developer/owner (investor-owned utility or 

independent power producer) and the assumed risk profile of the plant being assessed (low-risk or high-risk). 

For the following example, the owner/developer was assumed to be an investor-owned utility (IOU). All IGCC 

cases as well as PC and NGCC cases with CO2 capture would be considered high risk. Non-capture PC and 

NGCC cases would be considered low risk. Table 5 describes the low-risk IOU and high-risk IOU finance 

structures that were assumed for the example. Table 6 describes the finance structure that would be used if an 

independent power producer developer/owner were assumed. These finance structures were recommended in 

a 2008 NETL report, "Recommended Project Finance Structures for the Economic Analysis of Fossil-Based 

Energy Projects”, based on interviews with project developers/owners, financial organizations and law firms.

Table 5: Financial Structure for Investor Owned Utility High and Low Risk Projects

Type of 

Security % of Total

Current 

(Nominal) 

Dollar Cost

Weighted 

Current 

(Nominal) Cost

After Tax 

Weighted Cost 

of Capital

LOW RISK

Debt 50 4.5% 2.25%

Equity 50 12% 6%

Total 8.25% 7.39%

HIGH RISK

Debt 45 5.5% 2.475%

Equity 55 12% 6.6%

Total 9.075% 8.13%

Table 6: Financial Structure for Independent Power Producer High and Low Risk Projects

Type of 

Security % of Total

Current 

(Nominal) 

Dollar Cost

Weighted 

Current 

(Nominal) Cost

After Tax 

Weighted Cost 

of Capital

LOW RISK

Debt 70 6.5% 4.55%

Equity 30 20% 6%

Total 10.55% 8.82%

HIGH RISK

Debt 60 8.5% 5.1%

Equity 40 20% 8.0%

Total 13.1% 11.16%
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DCF Analysis and Cost of Electricity

The NETL Power Systems Financial Model (PSFM) is a nominal-dollar3 (current dollar) discounted cash flow 

(DCF) analysis tool. As explained below, the PSFM was used to calculate cost of electricity4 (COE) in two 

ways: a COE and a levelized COE (LCOE). To illustrate how the two are related, COE solutions are shown in 

Figure 2 for a generic pulverized coal (PC) power plant and a generic natural gas combined cycle (NGCC) 

power plant, each with carbon capture and sequestration (CCS).

• The COE is the revenue received by the generator per net megawatt-hour during the power plant’s first 

year of operation, assuming that the COE escalates thereafter at a nominal annual rate equal to the 

general inflation rate, i.e., that it remains constant in real terms over the operational period of the power 

plant. To calculate the COE, the PSFM was used to determine a COE in the first year of operation that, 

when escalated at the assumed nominal annual general inflation rate of 3%5

, provided the stipulated 

internal rate of return on equity over the entire economic analysis period (capital expenditure period plus 

thirty years of operation). The COE solutions are shown as curves in the upper portion of Figure 2 for a 

PC power plant and a NGCC power plant. 

• The LEVELIZED COE is the revenue received by the generator per net megawatt-hour during the power 

plant’s first year of operation, assuming that the COE escalates thereafter at a nominal annual rate of 0%, 

i.e., that it remains constant in nominal terms over the operational period of the power plant. These 

guidelines report LCOE on a current-dollar basis over thirty years. “Current dollar” refers to the fact that 

levelization is done on a nominal, rather than a real, basis6

. “Thirty-years” refers to the length of the 

operational period assumed for the economic analysis. The LCOE is calculated by multiplying the COE by 

a levelization factor (LF) that is a function of the IRROE and the general inflation rate that was applied to 

the COE. (An equation to calculate the levelization factor is provided on Page 14.) For the example PC 

and NGCC power plant cases, the LCOE solutions are shown as horizontal lines in the upper portion of 

Figure 2.

Figure 2 also illustrates the relationship between COE and the assumed developmental and operational 

timelines for the power plants. As shown in the lower portion of Figure 2, the capital expenditure period is 

assumed to start in 2007 for all cases in this example. All capital costs included in this analysis, including 

project development and construction costs, are assumed to be incurred during the capital expenditure period. 

Coal-fueled plants are assumed to have a capital expenditure period of five years and natural gas-fueled 

plants are assumed to have a capital expenditure period of three years. Since both types of plants begin 

expending capital in the base year (2007), this means that the analysis assumes that they begin operating in 

different years: 2012 for coal plants and 2010 for natural gas plants for this example.

In addition to the capital expenditure period, the economic analysis considers thirty years of operation for both 

coal and natural gas plants.

Since 2007 is the first year of the capital expenditure period, it is also the base year for the economic analysis. 

Accordingly, it is convenient to report the results of the economic analysis in base-year (2007) dollars, except 

for TASC, which is expressed in mixed-year, current dollars over the capital expenditure period. 

 3 Since the analysis takes into account taxes and depreciation, a nominal dollar basis is preferred to properly reflect the interplay 

between depreciation and inflation. A nominal dollar basis is also useful for comparing estimated costs with reported costs for actual 

projects, which are frequently expressed in total, as-spent, mixed, current-year dollars. For government-sponsored projects, expressing 

cost estimates on a nominal-dollar basis matches the appropriations process, which is done in current-year dollars. 4 For this calculation, “cost of electricity” is somewhat of a misnomer because from the power plant’s perspective it is actually the 

“price” received for the electricity generated for which the required IRROE is attained. However, since the price paid for generation is 

ultimately charged to the end user, from the customer’s perspective it is part of the cost of electricity.

5 This nominal escalation rate is equal to the average annual inflation rate between 1947 and 2008 for the U.S. Department of Labor’s 

Producer Price Index for Finished Goods. This index was used instead of the Producer Price Index for the Electric Power Generation 

Industry because the Electric Power Index only dates back to December 2003 and the Producer Price Index is considered the “headline” 

index for all of the various Producer Price Indices.

6 For this current-dollar analysis, the LCOE is uniform in current dollars over the analysis period. In contrast, a constant-dollar 

analysis would yield an LCOE that is uniform in constant dollars over the analysis period.
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Consistent with our nominal-dollar discounted cash flow methodology, the COEs shown on Figure 2 are 

expressed in current dollars. However, they can also be expressed in constant, base year dollars (2007) as 

shown in Figure 3 by adjusting them with the assumed nominal annual general inflation rate (3%).

Figure 2: Illustration of COE and LCOE Solutions using Current-Dollar DCF Analysis
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Figure 3 illustrates the same information as in Figure 2 for a PC plant with CCS only on a constant 2007 dollar 

basis. With an assumed nominal COE escalation rate equal to the rate of inflation, the COE line now becomes 

horizontal and the LCOE decreases at a rate of 3% per year.

Figure 3: Depiction of Current-Dollar COE and LCOE Solutions in Constant Dollars
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Estimating COE and LCOE with Capital Charge Factors

For scenarios that adhere to the global economic assumptions listed in Table 4 and utilize one of the finance 

structures listed in Table 5, the following simplified equation can be used to estimate COE as a function of 

TOC7

, fixed O&M, variable O&M (including fuel), capacity factor and net output. The equation requires the 

application of one of the capital charge factors (CCF) listed in Table 7 for an IOU finance structure and Table 8 

for an IPP. These CCFs, which were calculated using the NETL Power Systems Financial Model, are valid 

only for the global economic assumptions listed in Table 4, the stated finance structure, and the stated capital 

expenditure period. 

All factors in the COE equation are expressed in base-year dollars. The base year is the first year of capital 

expenditure, which for this study is assumed to be 2007. As shown in Table 4, all factors (COE, O&M and 

fuel) are assumed to escalate at a nominal annual general inflation rate of 3.0%. Accordingly, all first-year 

costs (COE and O&M) are equivalent to base-year costs when expressed in base-year (2007) dollars.

CCCCCC =

ffffffffff yyyyyy

cc cc cc cch aa

+

ffffffffff yyyyyy

ffffff ff oo oo

cc

+

ffffffffff yyyyyy

vv vv oo oo

cc

aa mm mm hoo

oo

CCCCCC = (CCCCCC)(TT ) + FFFF + (CCCC)( VVVVVV)

(CCCC)(MMMMMM)

where:

COE = revenue received by the generator ($/MWh, equivalent to mills/kWh) during the 

power plant’s first year of operation (but expressed in base-year dollars),

assuming that the COE escalates at a nominal annual rate equal to the general 

inflation rate, i.e., that it remains constant in real terms over the operational period 

of the power plant

CCF = capital charge factor taken from Table 7 that matches the applicable finance 

structure and capital expenditure period

TOC = total overnight capital (see note below), expressed in base-year dollars

OCFIX = the sum of all first-year-of-operation fixed annual operating costs, expressed in 

base-year dollars

OCVAR = the sum of all first-year-of-operation variable annual operating costs at 100% 

capacity factor, including fuel and other feedstock costs and (offset by) any 

byproduct revenues, expressed in base-year dollars

CF = plant capacity factor, assumed to be constant (or levelized) over the operational 

period; expressed as a fraction of the total electricity that would be generated if 

the plant operated at full load without interruption

MWH = annual net megawatt-hours of electricity generated at 100% capacity factor

Total Overnight Capital The TOC may include any “overnight” capital expense incurred during the capital 

expenditure period, except for escalation during construction and interest during construction. (When using 

the simplified COE equation, both escalation during construction and interest during construction are 

 7 Although TOC is used in the simplified COE equation, the CCF that multiplies it accounts for escalation during construction and 

interest during construction (along with other factors related to the recovery of capital costs). 
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“embedded” in the capital charge factor.) Both depreciable and non-depreciable capital should be included in 

the TOC, even though the CCF was computed assuming that all capital is depreciable. For typical tax rates 

and depreciation schedules this simplification introduces a negligible amount of error into the capital portion of 

the COE. If this simplification is not acceptable, a full discounted cash flow analysis tool (such as the NETL 

Power Systems Financial Model) should be used to calculate the COE instead of the simplified COE equation.

Table 7: Capital Charge Factors for COE Equation IOU

Finance Structure High Risk IOU Low Risk IOU

Capital Expenditure Period Three Years Five Years Three Years Five Years

Capital Charge Factor (CCF) 0.111 0.124 0.105 0.116

Table 8: Capital Charge Factors for COE Equation IPP

Finance Structure High Risk IPP Low Risk IPP

Capital Expenditure Period Three Years Five Years Three Years Five Years

Capital Charge Factor (CCF) 0.177 0.214 0.149 0.176

To calculate a Levelized COE, a levelization factor is applied to the COE that is expressed in base year 

dollars. Figure 2 shows LCOE’s in operational year dollars. To get the LCOE that is presented in Figure 2, the 

LCOE must be escalated from base year dollars to the first year of operation using an annual 3% general 

inflation rate over the capital expenditure period. After the first year of operation the LCOE escalates at 0% 

over the operational period.

CCCCCC ∗ LL = LL

Levelization Equation

Levelization factors were computed using the following end of the year cost formula: 

( )

*(1 )

D N

A K LF

LP

−

− =

D

N K

+

+ = 11

(1 ) 1

*(1 )

+ −

+ = LP

LP

D

D D A

where:

LF = levelization factor

LP = levelization period, years 

D = discount rate - used the Internal Rate of Return on Equity (IRROE) 

N = nominal escalation rate 
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Note that nominal escalation was computed as:

N = R + I

where:

R = real escalation rate

I = inflation rate

Table 9 shows the levelization factors calculated for IOU and IPP finance structures using the above equation.

Table 9: Levelization Factors

Finance Structure IOU @ 12% IRROE IPP @ 20% IRROE

Levelization Factor (LF) 1.268 1.169

Estimating TASC from TOC

For scenarios that adhere to the global economic assumptions listed in Table 4 and utilize one of the finance 

structures listed in Table 5, the multipliers shown in Table 10 can be used to translate TOC to TASC to 

account for the impact of both escalation and interest during construction. TOC is expressed in base-year 

dollars and the resulting TASC is expressed in mixed-year, current-year dollars over the entire capital 

expenditure period.

Table 10: TASC/TOC Factors

Finance Structure High Risk IOU Low Risk IOU

Capital Expenditure Period Three Years Five Years Three Years Five Years

TASC/TOC 1.078 1.140 1.075 1.134

Finance Structure High Risk IPP Low Risk IPP

Capital Expenditure Period Three Years Five Years Three Years Five Years

TASC/TOC 1.114 1.211 1.107 1.196