DOE/NETL

- 2010/???? 2011/1455National Energy Technology Laboratory Office of Program Performance and Benefits

2 Power Plant Cost Estimation Methodology Quality Guidelines for Energy System Studies April 2011



## 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 comme rcial 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.National Energy Technology Laboratory Office of Program Performance and Benefits

3 Power Plant Cost Estimation Methodology Quality Guidelines for Energy System Studies April 2011



## 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.govNational Energy Technology Laboratory Office of Program Performance and Benefits

4 Power Plant Cost Estimation Methodology Quality Guidelines for Energy System Studies April 2011



### Prepared by:

Energy Sector Planning and Analysis (ESPA)

Kristin Gerdes
National Energy Technology Laboratory

William Morgan Summers
National Energy Technology Lab oratory

John Wimer
National Energy Technology Laboratory

DOE Contract Number DE

- FE0004001National Energy Technology Laboratory Office of Program Performance and Benefits

5 Power Plant Cost Estimation Methodology Quality Guidelines for Energy System Studies April 2011



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

6 Power Plant Cost Estimation Methodology Quality Guidelines for Energy System Studies April 2011

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7 Power Plant Cost Estimation Methodology Quality Guidelines for Energy System Studies April 2011



## 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 Glob al Economic Assumptions

................................ ................................ ................................ 17

4.2 Finance Structures

................................ ................................ ................................ .................... 18

4.3 DCF Analysis and Cost of Electricity

................................ ................................ ...................... 19

4.4 Estimating COE and LCOE with Cap ital Charge Factors

................................ ....................... 21

4.5 Levelization Equation

................................ ................................ ................................ .............. 23

4.6 Estimating TASC from TOC

................................ ................................ ................................ ... 24

5 Revision Control

................................ ................................ ................................ ......................... 25

6 References

................................ ................................ ................................ ................................ ... 26National Energy Technology Laboratory Office of Program Performance and Benefits

8 Power Plant Cost Estimation Methodology Quality Guidelines for Energy System Studies April 2011



## 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 Depictio n 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

................................ ................................ ................................ ............ 25National Energy Technology Laboratory Office of Program Performance and Benefits

9 Power Plant Cost Estimation Methodology Quality Guidelines for Energy System Studies April 2011



## 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

CO 2 Carbon dioxide

DCF Discounted cash flow

DOE Department of Energy

EPC Engineering, procurement

, and

construction

EPCC Engineering, procurement

, and

construction cost

EPC M 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 s ystems f inancial m odel

TASC Total as

- spent capital

TCM Total cost management

TOC Total overnight cost

TPC Total plant co st
$/kW Dollars per kilowatt

$/MWh Dollars per megawattNational Energy Technology Laboratory Office of Program Performance and Benefits

10 Power Plant Cost Estimation Methodology Quality Guidelines for Energy System Studies April 2011

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11 Power Plant Cost Estimation Methodology Quality Guidelines for Energy System Studies April 2011



## 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 metho dology 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 le vels: 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 con tingencies 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/constr uction 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 c ost 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. According ly, TASC is expressed in mixed, current

- year dollars over the capital expenditure period.National Energy Technology Laboratory Office of Program Performance and Benefits

12 Power Plant Cost Estimation Methodology Quality Guidelines for Energy System Studies April 2011

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

sideNational Energy Technology Laboratory Office of Program Performance and Benefits

13 Power Plant Cost Estimation Methodology Quality Guidelines for Energy System Studies April 2011



### 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

Contracto rs 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 un certainties 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 ]National Energy Technology Laboratory Office of Program Performance and Benefits

14 Power Plant Cost Estimation Methodology Quality Guidelines for Energy System Studies April 2011

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

Evaluatio ns

– As Applied for the Process and Utility Industries

, ” AACE International Recommended

Practice No. 16R

- 90. [ 2 ] The Electric Power Research Institute’s (EPRI) “T echnical 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 Estimat ion 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 operat ing 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.National Energy Technology Laboratory Office of Program Performance and Benefits

15 Power Plant Cost Estimation Methodology Quality Guidelines for Energy System Studies April 2011

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 communic ation 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 r oads 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 pa rt 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 perfor mance, 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 sit e 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 ar e 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.National Energy Technology Laboratory Office of Program Performance and Benefits

16 Power Plant Cost Estimation Methodology Quality Guidelines for Energy System Studies April 2011



## 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 s ide of the main power transformers. The only cost

outside of this “ fence line ” that is accounted for is the cost of CO 2 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 a ccess roads and railroad tracks

• Upgrades to existing roads t o accommodate increased traffic

• Makeup water pipe outside the “fence line”

• Landfill fo r on

- site waste (slag) disposal

• N atural gas line for backup fuel provisions

• Plant switchyard

• Electrical transmission lines & substation

Other items that are not address ed in the cost estimates are:

• Piles or caissons

• Rock remov al

• Excessive dewatering

• Expansive soil considerations

• E xcessive seismic considerations

• Ext reme temperature considerations

• Hazardous or contaminated soils

• Demolition or re location of existing structures

• Leasing of offsite land for parki ng or laydown

• Busing of craft to site

• Costs of offsite storage

All estimates are bas ed on a reasonably “standard” plant. No unusual or extraordinary process equipment is included such as:

• Exce ssive water treatment equipment

• Air

- cooled condens er

• Automated coal reclaim

• Zero Liquid Discharge equipment

• Selective catalytic reduction ( SCR ) catalyst ( Integrated gasification combined cycle [ IGCC ] cases only)National Energy Technology Laboratory Office of Program Performance and Benefits

17 Power Plant Cost Estimation Methodology Quality Guidelines for Energy System Studies April 2011



## 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 Chemic al 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 Decem ber 2003.)National Energy Technology Laboratory Office of Program Performance and Benefits

18 Power Plant Cost Estimation Methodology Quality Guidelines for Energy System Studies April 2011



### 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 CO 2 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%National Energy Technology Laboratory Office of Program Performance and Benefits

19 Power Plant Cost Estimation Methodology Quality Guidelines for Energy System Studies April 2011



### 4.3 DCF Analysis and Cost of Electricity

The NETL Power Systems Financial Model (PSFM) is a nominal

- dollar 3 (current dollar) discounted cash flow (DCF) analysis tool. [ 4 ] As explained below, the PSFM was used to calculate COE 4 in 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 gener al inflation rate of 3 percent 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 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

ope rational 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, basis 6 . “Thirty

- years” refers to the length of the operational period assumed for the economic analysis. T he 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 th e 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, i ncluding 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 ca pital 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 int erplay between depreciation and inflation. A nominal dollar basis is also useful for comparing estimated costs with r eported 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 actual ly the “price” received for the electricity generated for which the required IRROE is attained. However, s ince 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 Gener ation Industry because the Electric Power Index only dates back to December 2003 and the Producer Price Inde x 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 u niform in constant dollars over the analysis period.National Energy Technology Laboratory Office of Program Performance and Benefits

20 Power Plant Cost Estimation Methodology Quality Guidelines for Energy System Studies April 2011

that the analysis assumes that they begin operating in different years: 2012 for coal plants and 2010 for natural gas plants fo r 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 nomi nal

- 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 a nalysis

Sou rce: NETLNational Energy Technology Laboratory Office of Program Performance and Benefits

21 Power Plant Cost Estimation Methodology Quality Guidelines for Energy System Studies April 2011

Exhibit 4

- 5 illustrates the same information as in Exhibit 4

- 4 for a PC plant with CCS only on a

constant 2007 dol lar 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 cu rrent

- 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 ca n be used to estimate

COE as a function of TOC 7 , 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 exp enditure, 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 a nd interest during construction (along with other factors related to the rec overy of capital costs).National Energy Technology Laboratory Office of Program Performance and Benefits

22 Power Plant Cost Estimation Methodology Quality Guidelines for Energy System Studies April 2011

(COE, O&M, and fuel) are assumed to escalate at a nominal annual general i nflation 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 f inance structure and capital expenditure period

TOC = total overnight capital (see note below)

, expressed in base

- year dollars

OC FIX = the sum of all first

- year

- of

- operation fixed annual operating costs, expressed in base

year dollars

OC VAR = 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 b e 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 a nd 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 e quation 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 0.116National Energy Technology Laboratory Office of Program Performance and Benefits

23 Power Plant Cost Estimation Methodology Quality Guidelines for Energy System Studies April 2011

Exhibit 4

- 7 Capital charge factors for COE e quation 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 perce nt over the operational period.

4.5 

### Levelization Equation

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

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 f actors

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

Levelization Factor (LF) 1.268 1.169National Energy Technology Laboratory Office of Program Performance and Benefits

24 Power Plant Cost Estimation Methodology Quality Guidelines for Energy System Studies April 2011



### 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, current

year dollars over the entire capital expenditure period.

Exhibit 4

- 9 TASC/TOC f actors

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 1.196National Energy Technology Laboratory Office of Program Performance and Benefits

25 Power Plant Cost Estimation Methodology Quality Guidelines for Energy System Studies April 2011



## 5 Revision Control

Exhibit 5

- 1 Revision table

Revision

Number Revision Date Description of Change Comments

1 February 11, 2014 Document formattedNational Energy Technology Laboratory Office of Program Performance and Benefits

26 Power Plant Cost Estimation Methodology Quality Guidelines for Energy System Studies April 2011



## 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 Ind u stries 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/n on/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). ( 20 11) Power Systems Financial Model

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

, http://www.netl.doe.gov/energy

analyses/refshelf/PubDetails.aspx?Action=View&Source=Products&PubId=382