DOE/NETL-2010/???? 2011/1455
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Disclaimer

This report was prepared as an account of work sponsored by an agency of the United States 

Government. Neither the United States Government nor any agency thereof, nor any of their 

employees, makes any warranty, express or implied, or assumes any legal liability or 

responsibility for the accuracy, completeness, or usefulness of any information, apparatus, 

product, or process disclosed, or represents that its use would not infringe privately owned rights. 

Reference therein to any specific commercial product, process, or service by trade name, 

trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, 

recommendation, or favoring by the United States Government or any agency thereof. The 

views and opinions of authors expressed therein do not necessarily state or reflect those of the 

United States Government or any agency thereof.
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Power Plant Cost Estimation Methodology

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Cost Estimation Methodology for NETL Assessments of 

Power Plant Performance

DOE/NETL-2011/1455

Final Report

August 2011

NETL Contact:

William Morgan Summers

General Engineer

Office of Program Performance & Benefits, Performance Division

National Energy Technology Laboratory

www.netl.doe.gov
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Prepared by:

Energy Sector Planning and Analysis (ESPA)

Kristin Gerdes

National Energy Technology Laboratory

William Morgan Summers

National Energy Technology Laboratory

John Wimer 

National Energy Technology Laboratory

DOE Contract Number DE-FE0004001
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Power Plant Cost Estimation Methodology

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Acknowledgments

This report was prepared by the United States Department of Energy (DOE), National Energy 

Technology Laboratory (NETL). 

The authors wish to acknowledge the excellent contributions and cooperation by members of the 

Energy Sector Planning and Analysis staff, particularly:

Lora Pinkerton, WorleyParsons Group, Inc.

Mark Woods, Booz Allen Hamilton, Inc. 

Paul Worhach, Nexant Inc. 
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Table of Contents

1 Introduction.................................................................................................................................11

2 Capital Costs...............................................................................................................................11

2.1 Levels of Capital Costs............................................................................................................11

2.2 Cost Estimate Classification ....................................................................................................12

2.3 Contracting Strategy and EPC Contractor Services.................................................................13

2.4 Estimation of Capital Cost Contingencies...............................................................................13

2.5 Estimation of Owner’s Costs...................................................................................................14

3 Cost Estimate Scope ...................................................................................................................16

4 Economic Analysis .....................................................................................................................17

4.1 Global Economic Assumptions................................................................................................17

4.2 Finance Structures....................................................................................................................18

4.3 DCF Analysis and Cost of Electricity......................................................................................19

4.4 Estimating COE and LCOE with Capital Charge Factors.......................................................21

4.5 Levelization Equation ..............................................................................................................23

4.6 Estimating TASC from TOC ...................................................................................................24

5 Revision Control.........................................................................................................................25

6 References...................................................................................................................................26
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List of Exhibits

Exhibit 2-1 Capital cost levels and their elements........................................................................ 12

Exhibit 2-2 Features of an AACE Class 4 cost estimate .............................................................. 12

Exhibit 2-3 AACE guidelines for process contingency................................................................ 14

Exhibit 2-4 Estimation method for owner’s costs......................................................................... 14

Exhibit 4-1 Global economic assumptions................................................................................... 17

Exhibit 4-2 Financial structure for investor owned utility high and low risk projects ................. 18

Exhibit 4-3 Financial structure for independent power producer high and low risk projects....... 18

Exhibit 4-4 Illustration of COE and LCOE solutions using current-dollar DCF analysis ........... 20

Exhibit 4-5 Depiction of current-dollar COE and LCOE solutions in constant dollars ............... 21

Exhibit 4-6 Capital charge factors for COE equation IOU........................................................... 22

Exhibit 4-7 Capital charge factors for COE equation IPP ............................................................ 23

Exhibit 4-8 Levelization factors.................................................................................................... 23

Exhibit 4-9 TASC/TOC factors.................................................................................................... 24

Exhibit 5-1 Revision table ............................................................................................................ 25
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Acronyms and Abbreviations

AACE Association for the Advancement 

of Cost Engineering

BEC Bare erected cost

CCF Capital charge factors

CCS Carbon capture and sequestration

COE Cost of electricity

CO2 Carbon dioxide

DCF Discounted cash flow

DOE Department of Energy

EPC Engineering, procurement, and 

construction

EPCC Engineering, procurement, and 

construction cost

EPCM Engineering, procurement, and 

construction management

EPRI Electric Power Research Institute

IOU Investor-owned utility

IGCC Integrated gasification combined 

cycle

IPP Independent power producer

LCOE Levelized cost of electricity

LF Levelization factor

NETL National Energy Technology 

Laboratory

NGCC Natural gas combined cycle

O&M Operation and maintenance

PC Pulverized coal

PSFM Power systems financial model

TASC Total as-spent capital

TCM Total cost management

TOC Total overnight cost

TPC Total plant cost

$/kW Dollars per kilowatt

$/MWh Dollars per megawatt
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1 Introduction

This paper summarizes the costing methodology employed by the National Energy Technology 

Laboratory (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).

2 Capital Costs

2.1 Levels of Capital Costs

As illustrated by Exhibit 2-1, 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, currentyear 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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Exhibit 2-1 Capital cost levels and their elements

Source: NETL

2.2 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. [1]

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

a “Feasibility Study” (AACE Class 4). Exhibit 2-2 describes the characteristics of an AACE Class 4 

cost estimate.

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

Exhibit 2-2 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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2.3 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.

2.4 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 Exhibit 2-3, AACE International Recommended Practice 16R-90 provides guidelines for 

estimating process contingency. [2]
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Exhibit 2-3 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

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 percent to 30 percent of the sum of BEC, EPC fees and process contingency. [2] 

2.5 Estimation of Owner’s Costs

Exhibit 2-4 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. [2] 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. [3] The EPRI and AACE guidelines are very similar. 

Exhibit 2-4 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 

[2] and EPRI TAG® [3] 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 [2] does not include an inventory cost for fuel, but EPRI TAG® [3] does.
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Owner’s Cost Estimate Basis

Land  $3,000/acre (300 acres for IGCC and PC, 100 acres for NGCC)

Financing Cost

 2.7% of TPC

This financing cost (not included by AACE 16R-90 [2]) 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 [2] or EPRI TAG®. [3] The “rule 

of thumb” estimate (15% of TPC) is based on a 2009 private communication with WorleyParsons. 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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3 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 

(T&S). T&S 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

• Selective catalytic reduction (SCR) catalyst (Integrated gasification combined cycle [IGCC]

cases only)
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4 Economic Analysis

4.1 Global Economic Assumptions

Global economic assumptions are listed in Exhibit 4-1.

Exhibit 4-1 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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4.2 Finance Structures

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

utility [IOU or independent power producer [IPP]) 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. All IGCC cases as well as pulverized coal (PC) and natural gas combined 

cycle (NGCC) cases with CO2 capture would be considered high risk. Non-capture PC and NGCC

cases would be considered low risk. Exhibit 4-2 describes the low-risk IOU and high-risk IOU 

finance structures that were assumed for the example. Exhibit 4-3 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.

Exhibit 4-2 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%

Exhibit 4-3 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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4.3 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. [4] As explained below, the PSFM was used to calculate COE4in two 

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

shown in Exhibit 4-4 for a generic PC power plant and a generic 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 percent5, 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 Exhibit 4-4 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 percent, 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 Exhibit 4-4.

Exhibit 4-4 also illustrates the relationship between COE and the assumed developmental and 

operational timelines for the power plants. As shown in the lower portion of Exhibit 4-4, 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 

 

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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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. 

Consistent with our nominal-dollar discounted cash flow methodology, the COE values shown on 

Exhibit 4-4 are expressed in current dollars. However, they can also be expressed in constant, base 

year dollars (2007) as shown in Exhibit 4-5 by adjusting them with the assumed nominal annual 

general inflation rate (3 percent).

Exhibit 4-4 Illustration of COE and LCOE solutions using current-dollar DCF analysis

Source: NETL
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Exhibit 4-5 illustrates the same information as in Exhibit 4-4 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 percent per 

year.

Exhibit 4-5 Depiction of current-dollar COE and LCOE solutions in constant dollars

Source: NETL

4.4 Estimating COE and LCOE with Capital Charge Factors

For scenarios that adhere to the global economic assumptions listed in Exhibit 4-1 and utilize one of 

the finance structures listed in Exhibit 4-2, 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 

Exhibit 4-6 for an IOU finance structure and Exhibit 4-7 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 Exhibit 4-1, 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 Exhibit 4-1, all factors 

 

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). 
National Energy Technology Laboratory Office of Program Performance and Benefits

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(COE, O&M, and fuel) are assumed to escalate at a nominal annual general inflation rate of 3.0

percent. Accordingly, all first-year costs (COE and O&M) are equivalent to base-year costs when 

expressed in base-year (2007) dollars.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

( ( ( ( 

( ( 

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 Exhibit 4-6 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 baseyear dollars

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

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 percent 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 “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.

Exhibit 4-6 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
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Power Plant Cost Estimation Methodology

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Exhibit 4-7 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. Exhibit 4-4 shows LCOE’s in operational year dollars. To get the LCOE that is 

presented in Exhibit 4-4, the LCOE must be escalated from base year dollars to the first year of 

operation using an annual 3 percent general inflation rate over the capital expenditure period. After 

the first year of operation the LCOE escalates at 0 percent over the operational period.

 

4.5 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







1

1

(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 

Note that nominal escalation was computed as:

N = R + I

where:

R = real escalation rate

I = inflation rate

Exhibit 4-8 shows the levelization factors calculated for IOU and IPP finance structures using the 

above equation.

Exhibit 4-8 Levelization factors

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

Levelization Factor (LF) 1.268 1.169
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Power Plant Cost Estimation Methodology

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4.6 Estimating TASC from TOC

For scenarios that adhere to the global economic assumptions listed in Exhibit 4-1 and utilize one of 

the finance structures listed in Exhibit 4-2, the multipliers shown in Exhibit 4-9 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, currentyear dollars over the entire capital expenditure period.

Exhibit 4-9 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
National Energy Technology Laboratory Office of Program Performance and Benefits

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5 Revision Control

Exhibit 5-1 Revision table

Revision 

Number Revision Date Description of Change Comments

1 February 11, 2014 Document formatted
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Power Plant Cost Estimation Methodology

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6 References

1 Advancement of Cost Engineering (AACE) International. (2005) Cost Estimate Classification 

System – As Applied in Engineering, Procurement, and Construction for the Process 

Industries; TCM Framework 7.3 – Cost Estimating and Budgeting, AACE International 

Recommended Practice No. 18R-97, 2005, Rev. November 29, 2011

Retrieved on April 8, 2013 from http://www.aacei.org/non/rps/18R-97.pdf

2 Advancement of Cost Engineering (AACE) International. (2003) Conducting Technical and 

Economic Evaluations – as Applied for the Process and Utility Industries TCM Framework: 

3.2 – Asset Planning, 3.3 – Investment Decision Making, AACE International Recommended 

Practice No. 16R-90, 2003.

Retrieved on April 8, 2013 from http://www.aacei.org/non/rps/16R-90.pdf

3 Electric Power Research Institute (EPRI). (2009). Technical Assessment Guide (TAG®) –

Power Generation and Storage Technology Options, Electric Power Research Institute 

(EPRI), EPRI Product ID No. 1017465, December 12, 2009.

Retrieved on April 8, 2011 from http://tag.epri.com/tag/

4 National Energy Technology Laboratory (NETL). (2011) Power Systems Financial Model 

Version 6.6. Pittsburgh, Pennsylvania. Details Retrieved on March 8, 2012, 

http://www.netl.doe.gov/energyanalyses/refshelf/PubDetails.aspx?Action=View&Source=Products&PubId=382