From: Higgins, Cortney [mailto:Cortney_Higgins@omb.eop.gov] 

Sent: Tuesday, May 20, 2014 12:14 PM 

To: Wayland, Robertj 

Cc: Culligan, Kevin 

Subject: RE: Chapters 3 & 6 - GHG Abatement TSD 

Thanks! 

From: Wayland, Robertj [mailto:Wayland.Robertj@epa.gov] 

Sent: Tuesday, May 20, 2014 10:53 AM 

To: Higgins, Cortney 

Cc: Culligan, Kevin 

Subject: Chapters 3 & 6 - GHG Abatement TSD 

Cortney – 

Here’s Chapters 3 & 6 of the GHG Abatement TSD. I believe that only leaves Chapter 4 

outstanding, and I’ll work with Jeb/Kevin to get that one and get it over to you as quickly as I can. 

thanx! 

bob 

Robert J. Wayland, Ph.D. 

Leader, Energy Strategies Group 

U.S. Environmental Protection Agency 

Office of Air Quality Planning and Standards 

Sector Policies and Programs Division 

Mail Code D243-01 

Research Triangle Park, NC 27709 

Office: (919) 541-1045 

Cell: (919) 306-2290 

Fax: (919) 541-5450 

Email: wayland.robertj@epa.gov 

************************************* 

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GHG Abatement Measures Technical Support Document 

Chapter 3: CO2 Reduction Potential from Re-Dispatch of Existing Units 

Table of Contents 

Overview.......................................................................................................................................................2

Introduction ..................................................................................................................................................2

Power Sector Background............................................................................................................................. 3

Historical Context..........................................................................................................................................7

Natural Gas Supply......................................................................................................................................15

Technical Considerations............................................................................................................................ 17

Analysis of Cost‐Effectiveness..................................................................................................................... 23

Natural Gas Price Impacts........................................................................................................................... 31

 

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Overview 

This chapter explores the dynamics of power sector dispatch and the cost-effectiveness of 

lowering the carbon dioxide (CO2) emissions intensity of the power sector by substituting 

generationreducing utilization of from the most carbon-intensive existing EGUs and increasing 

utilization, to the extent possible, of less carbon-intensive existing fossil fuel-fired EGUs. More 

specifically, the examination focuses on opportunities to improve emissions intensity by 

increasing the utilization of existing natural gas combined cycle units. The TSD provides 

background on existing power plants, power system operation, and the economics of electricity 

production and delivery in the context of cost-effective CO2 emission reduction opportunities. 

Introduction

Electric system dispatch is typically defined as “the operation of generation facilities to 

produce energy at the lowest cost to reliably serve consumers, recognizing any operational limits 

of generation and transmission facilities.”1

 Electricity demand varies across geography and time 

in response to numerous conditions, such that electricity generators are constantly responding to 

changes in demand and “re-dispatching” to meet demand in the most reliable and cost-effective 

manner possible. 

The nation’s EGUs are connected by transmission grids that extend over large regions. 

Through these interconnections, EGU balancing authorities treat the product (i.e., electricity) of 

EGUs as fungible, calling for electricity generation supply to meet demand usually by deploying 

the least expensive power source first.2

 

EGU operators and balancing authorities must take into account several constraints in 

dispatch, including transmission constraints as well as emission control programs and other 

environmental requirements. Such programs and requirements can change the relative cost of 

generating electricity among plants and/or limit the number of hours that a plant can run. For 

many years, EGU operators throughout the country have considered the emissions implications 

for pollutants such as SO2 and NOx when scheduling unit dispatch, in response to costs and 

                                                            

1

 Energy Policy Act of 2005 

2

 A balancing authority is the responsible entity that integrates resource plans ahead of time, maintains the balance 

between supply, demand, and generation within a balancing authority area, and supports interconnection frequency 

in real-time. http://www.nerc.com/files/glossary_of_terms.pdf 

Comment [A1]: General Comments:

1)The section on electric markets contains a

number of over‐simplifications. It’s not clear why

the section is necessary.

2)It should be made clear in introductory

sections (and throughout TSD) that the analysis

of building block 2/re‐dispatch is based on

dispatch to existing NGCC.   

Comment [A2]: EPA Response:

We feel that some context is useful for this chapter,

but we are open to specific suggestions for

improvements.

Clarifications also added for existing NGCC.

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regulatory requirements. For example, EGU operators in 10 states participating in the Regional 

Greenhouse Gas Initiative have several years of experience with factoring CO2 emissions limits 

directly into bids for economic dispatch. The electric system’s carbon intensity can be lowered 

through re-dispatch among existing EGUs, particularly by shifting generation from coal-fired 

units to natural gas combined cycle (NGCC) units. 

Power Sector Background

 Electric Dispatch 

Electricity generation conforms to the principle of least-cost economic dispatch, which is 

“the operation of generation facilities to produce energy at the lowest cost to reliably serve 

consumers, recognizing any operational limits of generation and transmission facilities.”3

 The 

cost of operating electric generators varies based on a number of factors, such as fuel used and 

generator efficiency. Regional Transmission Organizations (RTOs) and Independent System 

Operators (ISOs) help coordinate economic dispatch over larger areas to help keep the cost of 

meeting electricity demand as low as possible, subject to operational constraints. 

The decision by balancing authorities to call upon, or dispatch, any particular generating 

unit is driven by the relative operating cost, or marginal cost, of generating electricity to meet the 

last increment of electric demand. These costs change over time depending upon a variety of 

factors like fuel prices, weather conditions, and overall demand levels. Since the fixed cost of 

power plants is a sunk cost, plant operators bid into electricity markets such that their variable 

costs are covered. For fossil fuel-fired electric generating units, variable costs are dominated by 

the cost of the fuel, although coal-fired units often also have considerable variable costs 

associated with running pollution controls.4

 Other generating technologies, like renewables, 

hydroelectric, and nuclear, have little or no variable costs and are generally dispatched to the 

extent possible. In order to maintain least-cost dispatch, the units with the lowest variable costs 

will be called upon first, then other units (with higher variable costs) will be called upon 

sequentially, such that total system demand is met. The economic order in which units are 

                                                            

3

 Federal Energy Regulatory Commission, 2005. Economic Dispatch: Concepts, Practices, and Issues 

4

 In addition to fuel costs, variable costs also include costs associated operating and maintenance, and costs of 

operating a pollution control and/or emission allowance charges. 

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dispatched to meet demand, at any particular point in time, is commonly called a dispatch 

“curve.”5

 

                                                            

5

 http://www.eia.gov/todayinenergy/detail.cfm?id=7590 

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Balancing Authorities 

In states with cost-of-service regulation of vertically-integrated utilities who own 

generation, transmission, and distribution infrastructure, the utilities themselves often form the 

balancing authorities who determine unit dispatch. Such utilities are presumed to dispatch their 

units in a cost-minimizing fashion (seeking the lowest marginal cost), and they can arrange to 

buy and sell power with other balancing authorities. 

In states that have restructured regulation to allow for competition between generators, 

RTOs and ISOs are generally responsible for moving electricity across larger areas in the most 

efficient and least-cost manner possible.6

 They coordinate, control, and monitor electricity 

transmission systems to ensure cost-effective and reliable delivery of power, and they are 

independent from market participants. ISOs grew out of the Federal Energy Regulatory 

Commission (FERC) requirements for existing power pools to satisfy the requirement of 

providing non-discriminatory access to transmission. Subsequently, FERC encouraged the 

voluntary formation of RTOs to administer the transmission grid on a regional basis throughout 

North America (including Canada). 

RTOs and ISOs administer wholesale power markets, which match the generation of 

electricity with the purchase of electricity (and ancillary services) prior to delivery to end-users. 

Companies that provide retail electricity (e.g., utilities and energy service companies) procure 

power through these wholesale electricity markets. 

State Public Utility Commissions (PUCs)7

Each state has a governing body that is tasked with regulating retail electricity rates and 

electric services to protect the public interest, ensure efficient and reliable delivery of electricity, 

and plan appropriately for the short and long term energy needs of the state and consumers. 

Depending on market structure, PUCs also allocate costs among customers, design price 

structures and set price levels, set service quality standards, approve capital expenditure by 

utilities, and arbitrate disputes among relevant parties and stakeholders. In restructured markets, 

the PUC’s authority is generally applicable to the transmission and distribution system, since the 

                                                            

6

 http://www.ferc.gov/industries/electric/indus-act/rto.asp 

7

 These entities are sometimes called Utilities Commissions, Utility Regulatory Commissions, or Public Service 

Commissions.

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Comment [A3]: It’s probably more appropriate

to say that vertically‐integrated utilities seek the

lowest total cost, not the lowest marginal cost.

Comment [A4]: EPA Response:

It is EPA’s understanding that least‐cost dispatch

(system operation) is generally decided on a

marginal cost basis regardless of the type of utility.  

EPA recognizes that vertically‐integrated utilities

consider total costs in the context of longer‐term

capacity planning, but this document is focused on

operational dispatch patterns across existing units,

for which marginal cost is the relevant metric.
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generation and dispatch component is governed by RTOs and ISOs. In cost-of-service states, the 

PUC also has oversight of the generation and capacity planning components. 

Spot and Day-Ahead Markets 

RTOs and ISOs operate spot markets for wholesale power supply and demand for their 

designated area, including both day ahead and real-time (hourly, or shorter time periods). These 

markets are based on bids for supply and demand and operate according to rules established by 

FERC. The RTOs and ISOs use these markets for balancing power supply and load in their area 

and typically serve as the balancing authority for the same area. 

For areas not administered by RTOs and ISOs, dispatch is scheduled both day ahead and 

hourly, but is typically driven by the power supply costs and schedules of traditional utilities. 

This dispatch will depend, to a certain degree, on spot markets for power, since utilities will 

dispatch purchased power from other suppliers when that power can be obtained at a cost 

savings. There is an active wholesale market for this power in the spot market, from individual 

sales and from exchanges. These markets typically sell power day-ahead but not hourly, and also 

sell power for longer periods, such as weekly or monthly. However, the actual dispatch and 

balancing of power is conducted by the utility based on its own scheduling and purchasing 

protocols and varies considerably from one utility to the next. 

As a balancing authority, the RTO or utility will balance demand, generation, and 

imports/exports in real time while maintaining system frequency and ensuring that the next 

hour’s demand, or load, is met. In addition, the transmission system is constantly monitored to 

ensure reliability limits are met, voltage levels are appropriate, and appropriate corrective action 

is taken when needed. 

Reliability 

As reliability coordinators, balancing authorities are responsible for the reliable operation of the 

bulk electric system. The bulk electric system refers to a large interconnected electrical system 

made up of generation and transmission facilities and their control systems. To ensure reliability, 

system operators continuously analyze real-time and forecasted load and transmission conditions 

to ensure that scheduled generation dispatch can meet load without adverse impacts. If the 

scheduled dispatch is not feasible within the limits of the transmission system, it must be 

adjusted by the system operator. The North American Electric Reliability Corporation (NERC) 
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develops and enforces the procedures to ensure reliability, in accordance with Federal laws and 

regulations, and with FERC oversight.8

 

Historical Context

In 2012, average CO2 emission rates9 across all the following technology categories on a net 

generation basis were: 

 Coal Steam - 2,220354 lbs/MWh 

 Oil/Gas (O/G) Steam - 1,463624 lbs/MWh 

 NGCC – 90726 lbs/MWh 

Coal- and oil/gas-fired boilers are considerably higher-emitting sources than NGCCs, on 

average. Therefore, the replacement, or re-dispatch, of each megawatt-hour (MWh) from the 

average fossil fuel-fired boiler with each MWh from an average NGCC will result in notable 

CO2 emission reductions. 

The lower emission rate of NGCC conveys the potential of re-dispatch to reduce GHG 

emissions. However, the actual potential to realize emission reductions through this technology 

depends on the availability and capacity factors of the existing NGCC fleet. In order to redispatch from existing fossil fuel-fired boilers to existing NGCC, there needs to be some existing 

unused generation potential in the current NGCC fleet that could displace generation from more 

CO2 intensive generating resources. The term “availability” is a common engineering term used 

in the power sector, which reflects the percentage of period hours that a plant is available to 

produce electricity (a period being 1 year, or 8,784 hours in 2012 since that year included a leap 

day). The unavailable period is generally attributed to scheduled maintenance, unplanned 

maintenance, and unplanned outages. The EPA assumes that NGCC has an availability of 87%.10 

Other reports suggest that NGCC availability factors may reach as high as 92%.11 

                                                            

8

 http://www.nerc.com/ 

9

 Emission rates in this document are shown on a net generation basis and reflect Hawaii and Alaska sources. See 

“2012 eGrid Data” file provided in the docket 

10 See Chapter 3, Table 3-18 at http://www.epa.gov/powersectormodeling/BaseCasev513.html 

11 http://www.power-eng.com/articles/print/volume-115/issue-2/features/higher-availability-of-gas-turbinecombined-cycle.html 

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If the existing NGCC fleet was already operating at a level of 87% to 92%, there would 

not be any additional generation potential in the existing generating system for re-dispatch to 

those units. To evaluate re-dispatch opportunities to unused NGCC generation potential in the 

system, the EPA reviewed recent NGCC fleet operating data to determine capacity factors. 

Redispatch for GHG abatement purposes would require one net MWh of a lower emitting 

technology displacing one net MWh of generation from higher emitting technology. Therefore, 

when the EPA was assessing capacity factor it used the net generation of a given NGCC unit as 

the numerator. The EPA was interested in the relationship of a unit’s total net generation relative 

to its net generating capacity (i.e., capacity factor). Net generating capacity is a function of 

weather/temperature conditions at the site, which varies throughout the year. While some units 

may model actual weather adjusted capacity by the hour/minute, theisethis data iaresis not 

reported for the fleet. Therefore, the EPA used the reported nameplate capacity reported for 

units. The net generation was divided into the nameplate generation capacity of a unit multiplied 

by the number of hours in a year. This calculation of capacity factor provides an indication of 

how much net generation a unit is providing as a percent of its total generating capacity. 

Whereas availability refers to the maximum amount of generation that could be expected from a 

given source, the capacity factor refers to the actual utilization of that source on an annual basis. 

The EPA surveyed 2012 data for over 1800 NGCC units and observed that the NGCC fleet had 

an average capacity factor in the 44% to 46% range for 2012.12 Since the fleet-wide capacity 

factor in 2012 was less than the availability assumed for the technology, the historical data 

suggests that there is a significant potential for re-dispatch from higher CO2 emitting resources to 

lower emitting NGCC generation. 

Availability for NGCC fleet................................87% to 92% (84% to 89%)13

2012 Capacity Factor for NGCC fleet.....................44% -46% 

To quantify the GHG reduction potential from re-dispatch, the EPA considered 

alternative capacity factor levels at which the NGCC fleet could be dispatched. Although the 

availability for NGCC units is assumed to be in the mid to high 80s, the EPA did not assume that 

                                                            

12 See “2012 eGrid Data” file provided in the docket for 44% figure. See EIA 860 and 923 for 46% value. 13 Because the 2012 capacity factor used in this exercise focuses on net generation as a percent of name plate 

capacity, the availability is converted from a gross generation/name plate value to a net generation/name plate value 

using a .97net/gross conversion resulting in a range is 84% to 89%. 

Comment [A5]: This is incorrect. Other forms of

generation are dispatchable. Please clarify.

Comment [A6]: EPA Response:

Clarification added.
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each state’s NGCC fleet could collectively operate at this level on an annual basis. To determine 

reasonable average capacity factor ceilings for a state’s NGCC fleet as part of BSER, the EPA 

considered historical data and modeling projections describing NGCC characteristics and 

operating behavior. 

As seen in Table 3-1, the existing NGCC fleet is relatively young. More than 80% of the 

capacity has come online in the last 15 years.14 Of this capacity, almost all are a highly efficient 

class of NGCCs that are able to achieve high availability factors. 

Table 3-1: Existing NGCC Capacity, by Age15

Online Year Capacity 

(Name Plate Capacity – MW) 

Percentage of 

Total Existing NGCC 

Fleet 

Pre 1950 103 0% 

1950-1959 1,769 0.7% 

1960-1969 3,087 1.3% 

1970-1979 6,909 2.8% 

1980-1989 7,658 3.1% 

1990-1999 28,467 11.7% 

2000-2009 174,947 71.7% 

2010+ 21,068 8.6% 

Total 244,008 100% 

Of 4641,812 NGCC plantsNGCC units operating generating in 2012 and greater than 25 

MW, the EPA observed that 50179 plants units (more than 1010% of NGCC plantsunits) had a 

                                                            

14 See the National Electricity Energy Data Systems (NEEDS) file at 

http://www.epa.gov/powersectormodeling/BaseCasev513.html 

15 See “Operable” worksheet in “GeneratorY2012” Workbook in 2012 Zip file at 

http://www.eia.gov/electricity/data/eia860/ 
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net generation value that was greater than or equal to its nameplate capacity x 8784 hours * 70%. 

That is, a capacity factor that was 70% or greater (see Figures 3-1 and 3-2).16 

Figure 3-1: Cumulative NGCC Capacity Factor vs. Percentage of Units

Figure 3-2: NGCC Plant Distribution by Frequency of NGCC Capacity Factors (2012) 

                                                            

16 See “2012 eGrid Data” file provided in the docket 

0%

20%

40%

60%

80%

100%

0%4%8%

12%16%20%24%28%32%36%40%44%48%52%56%60%65%69%73%77%81%85%89%93%97%

Capacity Factor

% of Units

Cumulative Capacity Factor

0%

20%

40%

60%

80%

100%

0%4%8%

12%16%20%24%28%32%36%40%44%48%52%56%60%65%69%73%77%81%85%89%93%97%

Capacity Factor

% of Units

Cumulative Capacity Factor

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17

                                                            

17 EIA Forms 860 and 923. CA and CT Prime Mover categories

0

20

40

60

80

100

120

140

160

180

200

# of Units

Unit Distribution by Capacity Factor

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Unit Distribution by Capacity Factor

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Table 3-X: Plant Distribution of Existing NGCCs (2012) 

Capacity Factor # of NGCC 

plants 

% of NGCC 

Plants 

Less than 5% 40 8.62% 

5%-9% 26 5.60% 

10%-14% 23 4.96% 

15%-19% 25 5.39% 

20%-24% 16 3.45% 

25%-29% 18 3.88% 

30%-34% 27 5.82% 

35%-39% 38 8.19% 

40%-44% 30 6.47% 

45%-49% 36 7.76% 

50%-54% 33 7.11% 

55%-59% 39 8.41% 

60%-64% 36 7.76% 

65%-69% 27 5.82% 

70%-74% 20 4.31% 

75%-79% 13 2.80% 

80-84% 10 2.16% 

85-89% 4 0.86% 

Greater than 90% 3 0.65% 

In 2012, roughly more than 10% of NGCC plantsunits operated at an annual capacity 

factor of 70% or higher. This subset of NGCCs was largely dispatched to provide base load 

power. While only 10% of units plants operated at 70% or higher capacity factor on an annual 

basis, the fleet of NGCC units was relied upon heavily during certain periods of time, in response 

to higher demand. On a seasonal basis, a significant number of units achieved capacity factors 

greater than 50%, and even up to 80%. Using data reported to the EPA,18 and looking more 

closely at data during the summer and winter peak electricity demand timeframes nationwide, 

more than 10% of NGCCs were operated at a capacity factor greater than 70%.19 In fact, 19% of 

NGCCs achieved 70% capacity factor during the winter of 2011/2012 and 20% hit that level or 

                                                            

18 Air Markets Program Data (at http://ampd.epa.gov/ampd/). 

19 Summer defined as June, July and August. Winter defined as December, January, and February. Estimates are 

for units for which data was provided to EPA. 

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higher during the summer.20 During periods where demand levels are typically lower, some 

NGCCs were idled or operated at lower capacity factors. Nonetheless, a notable number of 

existing NGCCs have demonstrated the ability to achieve a 70% capacity factor for extended 

periods of time. These units achieved high capacity factors without adverse effects on the electric 

system. While many units demonstrated an ability to deliver net generation that was more than 

70% of their nameplate capacity, the EPA assumed that 70% was a reasonable fleet-wide ceiling 

for each state. It should also be noted, roughly 6% of units (107 units) operated at a 75% 

capacity factor, or higher, in 2012. In addition, 16% of units (291 units) operated at 65%, or 

higher.

Over the last several years, advances in the production of natural gas have helped reduce 

natural gas prices and improved the competitive position of gas-fired units relative to coal-fired 

units. As a result, operators have shifted significant quantities of generation from coal units to 

NGCCs, absent any federal CO2 requirements. 2012 net generation from NGCC units grew to 

981 TWh, up from 796 TWh in 2011 (22% growth in one year). The extent of this capability 

varies by region, based on factors such as the mix of EGU types and the amount of available 

NGCC capacity. 

An analysis of historical dispatch across the generating fleet of coal and NGCC units for 

2011 and 2012 provides some implicit measures of the cost dynamics between the two 

technologies. For example, one is able to look at the change in the prices of coal and gas to 

gauge the relative costs of generating, or dispatch, for each technology. While there are wideranging costs at the unit level, an aggregated assessment of the relative economics is informative 

and can provide a metric for assessing the implications of dispatch as it relates to emissions of 

CO2. 

The potential for redispatch from CO2 intensive sources to less CO2 intensive sources is 

evidenced in historical data. EIA form 860 and 923 data demonstrate an increase in NGCC 

generation and fuel use between 2011 and 2012 of more than 20% (even though the NGCC fleet 

capacity rose by just 3%). As NGCC generation rose by approximately 185 TWh, coal 

generation fell by approximately 216 TWh. The significant redispatch from coal to gas over just 

                                                            

20 Air Markets Program Data (http://ampd.epa.gov/ampd/). Winter includes December of 2011, January and 

February of 2012. Summer includes June, July, and August. 

Comment [A7]: The use of historical data has

little bearing on the capability of the entire fleet to

reach a given level of dispatch. It only shows the

ability of individual units to reach high levels, but it

is already well‐established (and noted elsewhere)

that these plants are designed to operate at yearly

capacity factors in excess of 85%. The main

constraints on reaching high capacity factors for

existing NGCC generation are system constraints

including the need for dispatchable generation to

meet intermediate load. These are addressed later

in the TSD.

Comment [A8]: EPA Response:

We agree with the comment, but it is important to

show all evidence where it exists, supporting the

conclusion that higher capacity factors can be met.  

By using historical data, we show that this is not

merely a theoretical or engineering argument, but

actually happens, in practice, fairly routinely at

individual units. The other arguments mentioned in

the comment are addressed throughout this TSD.

Comment [A9]: EPA Response:

We agree with the comment, but it is important to

show all evidence where it exists, supporting the

conclusion that higher capacity factors can be met.  

By using historical data, we show that this is not

merely a theoretical or engineering argument, but

actually happens, in practice, fairly routinely at

individual units. The other arguments mentioned in

the comment are addressed throughout this TSD.
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a one year period demonstrates the ability for the quick re-dispatch in response to market or 

economic drivers. 

The increase in the NGCC utilization was in large part driven by the decrease in natural 

gas prices to historic lows (see Table 3-2). Henry Hub natural gas prices averaged $4.00/mmBtu 

in 2011 and $2.76/mmBtu in 2012. This $1.24/mmBtu creates an additional incentive for 

redispatch from coal generation to NGCC relative to 2011 dispatch economics. The fuel 

advantage is similar to the incentive that a $15/metric ton of CO2 price signal would create.21 

This historical data also shows a sharp increase in the NGCC fleet’s capacity factor from the 

high 30s to the mid 40s. During that same period, net coal generation dropped by an amount 

similar to the increase observed in NGCC net generation. Furthermore, natural gas supply is 

expected to grow more than 20% by 2020 relative to its 2012 levels, creating more fuel resources 

to foster the potential continued and increasing redispatch to NGCC generating technology.22

Table 3-2: 2011 and 2012 Gas and Coal Generation23

Year 

NGCC 

Name Plate 

Capacity 

(GW) 

NGCC Heat 

Input for 

Electricity 

(TBtu) 

NGCC Net 

Generation 

(TWh) 

NGCC 

Capacity 

Factor 

Henry Hub

Natural Gas 

Price 

($/mmBtu 

Coal Net 

Generation 

(TWh) 

2011 2395 5,912 796 389% $4.00 1,719 

2012 2442 7,224 981 46% $2.76 1,503 

The demonstrated ability of the NGCC units plants to consistently operate at levels 

greater than 70% of their nameplate capacity (e.g., this was the utilization level of the ~ 90th

percentile plantunit), the historic evidence supporting quick and significant redispatch to NGCC, 

and the cost-effectiveness of high NGCC utilization demonstrated later in this TSD all supported 

the notion of a NGCC fleet capacity factor of 70% as a reasonable ceiling in the EPA’s BSER 

approach. 

For purposes of establishing state goals, historical electric generation data (2012) was 

used to apply each building block and develop each state’s goal (expressed as an emissions rate, 

                                                            

21 Assumes 11,000 Btu/KWh heat rate and 2354 lb/MWh emision rate for coal, 8000 Btu/KWh and 926 lbs/MWh 

for NGCC (based of “2012 eGrid file”) 

22 http://www.eia.gov/oiaf/aeo/tablebrowser/#release=AEO2014ER&subject=0-AEO2014ER&table=13-

AEO2014ER®ion=0-0&cases=ref2014er-d102413a 

23 EIA form 860 and EIA form 923 

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lbs/MWh). In 2012, electric generation from existing NGCC units likely subject to the 111(d) 

applicability criteria was 95932 TWh.24 After the application of NGCC re-dispatch to the 70% 

level,25 these same existing sources were calculated to collectively generate 1,39076 TWh. 

Adding in the existing sources that were not yet online in 2012 (under construction) increases 

total NGCC generation calculated in the goal setting to 1,44427 TWh. 

Although, states may choose to comply with state goals through other abatement 

measures, the EPA believes that upwards oft roughly 1,400 TWh from existing and under 

construction NGCCs is achievable. As a reference point, NGCC generation increased by 

approximately 430 TWh (an 8180% increase) between 2005 and 2012. EPA is calculating that 

NGCC generation in 2020 could increase by approximately 5-45% form today’s levels. This 

reflects a smaller ramp rate in NGCC generation than has been observed from 2005 to 2012. 

Table 3-3: Historic and Assumed Generation Patterns for State Goal Setting 

 

NGCC 

Name Plate 

Capacity 

(GW) 

NGCC Net 

Generation 

(TWh) 

Growth in 

NGCC 

Generation 

from 2005 to 

2012 

Growth in 

NGCC 

Generation 

from 2012 to 

2020 

Nationwide 

NGCC 

Capacity 

Factor 

2005 199 551 NA NA 32% 

2012 2442 981 8178% NA 46% 

2020 State Goal Calculation 256 1,44427 45% 47% 643% 

Natural Gas Supply 

The EPA expects the growth in NGCC generation assumed in goal setting to be feasible 

and consistent with domestic natural supplies. Increases in the natural gas resource base have led 

to fundamental changes in the outlook for natural gas. There is general agreement that 

                                                            

24 For covered sources. 25 This dispatch level is a ceiling dependent upon available existing steam generation that can be decreased.  As a

result, not all states achieve the assumed 70% re‐dispatch for purposes of goal setting (see Goal Setting chapter).

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recoverable natural gas resources will be substantially higher for the foreseeable future than 

previously anticipated, exerting downward pressure on natural gas prices.26

According to EIA, natural gas proved reserves have doubled between 2000 and 2012.27 

Domestic production has increased by 32% over that same timeframe (from 19.2 TCF to 25.3 

TCF). EIA’s Annual Energy Outlook for 2014 projects that production will further increase to 

29.1 TCF, due to increased supplies and favorable market conditions. For comparison, NGCC 

generation growth of 450 TWh (calculated in goal setting) would result in increased gas 

consumption of roughly 3.54.4 TCF for the electricity sector.28 

The National Petroleum Council (NPC), a privately funded advisory committee 

established by the Secretary of Energy, recently updated a major resource study and concluded 

that “the potential supply of North American natural gas is far bigger than was thought even a 

few years ago,” after large increases in shale resource estimates.29 

Figure 3-3: U.S. Natural Gas Technically Recoverable Resources (from NPC, 2011)30

                                                            

26 National Petroleum Council. 2011. Prudent Development: Realizing the Potential of North America's Abundant  

Natural Gas and Oil Resources. http://www.npc.org/reports/rd.html (see Figure 1.2 on p. 47). 27 http://www.eia.gov/cfapps/ipdbproject/IEDIndex3.cfm?tid=3&pid=3&aid=6 28 Assuming 1,024 Btu/cubic foot and 10,000 mmBtu/MWh 29 National Petroleum Council, 2012 (http://www.npc.org/PD_update‐80112.pdf) 30 http://www.npc.org/reports/rd.html

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Technical Considerations 

Emission reductions through re-dispatch are largely determined by the ability to change 

the utilization of existing generating units, relative to current utilization levels. Other influences 

include physical limitations of the electric transmission system and considerations for reliability, 

timing, and cost. 

NGCC Availability 

For purposes of economic dispatch, most NGCCs have historically been operated to serve 

base load or intermediate demand due to their high efficiency and flexibility of operation, with 

national average annual capacity factors in the range of 40-50%.31,32 However, NGCCs are 

designed for, and are demonstrably capable of, reliable and efficient operation at much higher 

annual capacity factors, as shown in observed historical data for particular units and their design 

and engineering specifications. 

                                                            

31 EIA, Today In Energy, January 15, 2014, http://www.eia.gov/todayinenergy/detail.cfm?id=14611 (for recent data) 32 EIA, Electric Power Annual 2009, http://www.eia.gov/electricity/annual/archive/03482009.pdf (Table 5-2 for 

2009 and earlier data) 

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The capability of NGCCs to operate at capacity factors of 70% and greater is indicated, in 

part, by statistics on the average availability factor of NGCCs. 33 Annual availability is the ratio 

of annual hours that an EGU is operating or considered able to operate (not in a forced or 

maintenance outage) to the hours in a year. The average availability factor for NGCCs in the 

U.S. generally exceeds 85%, and can exceed 90% for selected groups, as reported to NERC.34,35 

Advanced NGCCs being built today have availability factors of over 95%. According to one 

NGCC manufacturer, these highly efficient units already represent over 15 percent of total 

installed capacity nationwide, including all electric generating sources (as of 2010).36

These high-efficiency and high-availability NGCC units were first introduced around 

1995 and have consistently reported availability factors of 90 to 92 percent to NERC (compared 

to 95 percent or greater availabilities reported by current vintage F class and H class turbines 

from General Electric Power Systems).37 Data reported to NERC from NGCC units greater than 

50 MW in 1994 through 1998 shows similar availability factors (generally exceeding 89 

percent). 

Natural Gas Pipeline and Electricity Transmission 

The EPA believes that the natural gas pipeline and electricity transmission networks can 

support aggregate operation of the NGCC fleet at up to a 70% capacity factor on average, either 

as they currently exist or with modifications that can be reasonably expected in the time frame 

for compliance with this rule. Existing NGCCs are already connected to both the power and 

natural gas networks and, while constraints to specific unit operations can occur in either or both 

networks during peak pipeline flow or electricity use, the rule allows for emission rate averaging 

across multiple units and across time for compliance. As a consequence of this averaging 

flexibility, constraints that occur at peak times are unlikely to be a barrier to achieving 

compliance with the rule, because these peak times are only a small percentage of the year and 

                                                            

33 NERC, 2008-2012 Generating Unit Statistical Brochure – All Units Reporting, 

http://www.nerc.com/pa/RAPA/gads/Pages/Reports.aspx

34 Power Engineering, Negotiating Availability Guarantees for Gas Turbine Plants, 03/01/2001, http://www.powereng.com/articles/print/volume-105/issue-3/features/negotiating-availability-guarantees-for-gas-turbine-plants.html 35 Power Engineering, Higher Availability of Gas Turbine Combined Cycle 02/01/2011, http://www.powereng.com/articles/print/volume-115/issue-2/features/higher-availability-of-gas-turbine-combined-cycle.html 36 http://site.ge-energy.com/corporate/network/downloads/7FA_Evolution.pdf 

37 GE Power Systems submitted to U.S. Department of Energy, 2000. Utility Advanced Turbine Systems 

Technology Readiness Testing Phase 3 Restructured. DOE Cooperative Agreement No. DE-FC21-95MC31176—

30. 
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will constrain only a limited percentage of the state-wide NGCC fleet. The ability for the current 

fleet to ramp up significantly to meet changes in demand can be seen from the increased use of 

natural gas that occurred in 2012 in response to historically low natural gas prices. Power plant 

use of natural gas use in 2012 increased by 20% over 201138 and resulted in a national average 

capacity factor for NGCC of 45.89% on average, and higher in some states.39

During the peak hours of the day (which vary by region and season), NGCC capacity 

factors are typically well above average capacity factors.40 The pattern of capacity utilization by 

hour for 2005 to 2010 is shown in Figure 3-43. In this figure, capacity factors in 2010 are 

approximately 50% from the Hour 11 to Hour 21.41 The persistence of this hourly pattern across 

years shows the pattern to be stable. Since the average capacity factor for combined cycle units 

in 2010 from the same information source was 39%42, this indicates that the current system can 

support levels of approximately 11% above the average capacity factor. These peak hours are the 

period when there are most likely to be constraints on the pipeline or electricity transmission 

networks; during other hours of the day, continued NGCC operation at equal, or higher levels, 

are technically feasible but may be limited by economic considerations (e.g., whether NGCCs 

can offer least-cost electricity compared to other sources at those times). As a result, the current 

system is already able to support national average capacity factors in the mid to high 50’s for 

NGCC for peak. It is reasonable to expect that average capacity factors could be extended to 

higher levels at all hours without experiencing technical feasibility barriers from either pipeline 

supplies or electricity transmission. 

Figure 3-43. Average Utilization of Natural Gas Combined Cycle Power Plant Fleet 

                                                            

38 Energy Information Administration, U.S. Natural Gas Consumption by End Use, 

http://www.eia.gov/dnav/ng/ng_cons_sum_dcu_nus_a.htm. 

39 Source: Air Markets Program Data (AMPD), ampd.epa.gov, EPA, 2014 

40 Energy Information Administration, Today in Energy, July 9, 2011. Average utilization of the nation’s natural gas 

combined-cycle power plant fleet is rising. http://www.eia.gov/todayinenergy/detail.cfm?id=1730# 41 In this figure, hour 11 is the hour ending at 11 AM, and similarly for other hours. 

42 Air Markets Program Data (AMPD), ampd.epa.gov, EPA, 2014
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Although there can be site-specific constraints on utilization at some NGCC facilities, 

several factors support the ability of the power and natural gas pipeline systems to respond 

effectively with increases in infrastructure when needed to alleviate these barriers. For example, 

in recent years, the power transmission system has responded with increased transmission 

infrastructure when needed to allow the retirement of uneconomic coal plants.43 This rule 

provides for flexible implementation that will permit efficient scheduling of infrastructure 

upgrades as needed. Upgrades to pipeline and transmission infrastructure potentially needed to 

meet additional use of existing facilities will generally be less extensive than upgrades of that 

infrastructure potentially needed for siting of new capacity. In addition, this proposed rule is 

expected to result in significantly higher levels of end-use energy efficiency, which will reduce 

the load on the electricity transmission and natural gas pipeline infrastructure, while also 

providing other system wide benefits, such as decreased need for new generating units and 

reduced peak demands. 

                                                            

43 See http://www.pjm.com/~/media/about-pjm/newsroom/2013-releases/20131211-pjm-board-authorizes-4.6-

billion-in-chnages-to-regional-electric-grid.ashx for an example of short term transmission upgrades performed to 

facilitate environmental compliance. For technical description of these upgrades, see: 

http://www.pjm.com/~/media/committees-groups/committees/teac/20131211/20131211-december-2013-pjm-boardapproval-of-rtep-whitepaper.ashx. 
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In addition, natural gas pipeline capacity is regularly added in response to increased gas 

demand and supply, such as the addition of large amounts of new NGCC capacity in 2001 to 

2003, or the delivery to market of unconventional gas supplies since 2008.44 These pipeline 

capacity increases have added significant deliverability to the natural gas pipeline network to 

meet the potential demands from increased use of existing NGCCs. Over a longer time period, 

much more significant pipeline expansion is possible. In previous studies, when the pipeline 

system was expected to face very large demands for natural gas use by electric utilities about 10 

years ago, increases of up to 30% in total deliverability out of the pipeline system were judged to 

be possible by the pipeline industry.45 There have also been notable capacity expansions over 

the past five years, in response to increased natural gas supply estimates and advances in drilling 

techniques.46 

To examine the potential for increases in pipeline deliverability, the EPA analyzed the 

pipeline flow data from the Energy Information Administration. These data provide pipeline 

capacity for inflows and outflows by state. However, since the natural gas pipeline system is a 

network for flows into, across, and out of states and broader area, the level of gas supply that can 

be firmly delivered to a particular region depends on the amount of natural gas the will be 

required to be delivered out of the region to other regions. Consequently, it is important to focus 

on the net capacity – the difference between inflow capacity and outflow capacity -- in the 

relevant areas. The regions used by EIA for measuring regional natural gas deliverability are 

shown in Figure 3-54. Of these regions, the key regions for the analysis of the potential impact of 

the proposed rule are those natural gas consuming areas where there could be increases in natural 

gas consumption as a result of re-dispatch to comply with the proposed rule. These are the 

Northeast, Southeast, Midwest and Western regions in Figure 3-54. The net pipeline capacity for 

these regions from 2005 to 2011 is shown in Table 3-43 below. 

Table 3-43. Natural Gas Pipeline Net Capacity by Region, 2005 - 2011 by Gas Consuming 

Area47

                                                            

44 Energy Information Administration, Today in Energy, Natural Gas Pipeline Additions in 2011. Additions 

averaged around 20Bcf per day from 2008 to 2011. 

45 Pipeline and Storage Infrastructure Requirements for a 30 Tcf Market, INGAA Foundation, 1999 (Updated July, 

2004); U.S. gas groups confident of 30-tcf market, Oil and Gas Journal, 1999. 

46 http://www.eia.gov/naturalgas/data.cfm#pipelines 

47 Source: Energy Information Administration, http://www.eia.gov/naturalgas/data.cfm
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Region 2005 2006 2007 2008 2009 2010 2011

Capacity in MMCF/day 

Midwest 17,102 17,232 17,452 17,302 18,714 18,564 18,414 

Northeast 11,199 11,219 11,384 11,929 12,079 12,229 12,379 

Southeast 12,921 12,901 12,736 15,741 18,241 20,797 20,797 

Western 11,882 11,882 12,496 12,496 12,496 12,641 14,407 

All Areas 53,104 53,234 54,068 57,468 61,530 64,231 65,997 

Percent Change from 2005 

Midwest 0.0% 0.8% 2.0% 1.2% 9.4% 8.5% 7.7%

Northeast 0.0% 0.2% 1.7% 6.5% 7.9% 9.2% 10.5%

Southeast 0.0% -0.2% -1.4% 21.8% 41.2% 61.0% 61.0%

Western 0.0% 0.0% 5.2% 5.2% 5.2% 6.4% 21.3%

All Areas 0.0% 0.2% 1.8% 8.2% 15.9% 21.0% 24.3%

As a conservative assumption, the increase from the period 2005 to 2010 can be used as 

an estimator of the potential increase in pipeline capacity to accommodate compliance with the 

rule between 2015 and 2020. This is an extremely conservative assumption, since compliance is 

measured over a longer period and is not limited to re-dispatch approaches. Moreover, pipeline 

requirements for increased use of natural gas in existing facilities can be expected to be largely

on existing pipeline facilities and corridors, so that the types of capacity expansion required will 

be less expensive and take less time than new pipelines. Over 2005-2010, the total gas 

deliverability in gas consuming areas increased by 21%. Since the power sector currently uses 

approximately 30% of the total national natural gas consumption, and gas usage in other sectors 

is expected to be essentially flat through 2020, this historical increase indicates that pipeline 

capacity will be adequate to support any compliance changes in re-dispatch of natural gas power 

plants. 

Figure 3-54. Energy Information Administration Natural Gas Pipeline Regions
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Source: Energy Information Administration. 

Analysis of Cost-Effectiveness 

To further evaluate the technical capability of the natural gas supply and delivery system 

to provide increased quantities of natural gas and the capability of the electricity transmission 

system to accommodate shifting generation patterns, EPA employed the Integrated Planning 

Model (IPM), a multi-regional, dynamic, deterministic linear programming model of the U.S. 

electric power sector that the EPA has used for over two decades to evaluate the economic and 

emission impacts of prospective environmental policies. IPM provides a wide array of 

projections related to the electric power sector and its related markets (including least cost 

capacity expansion and electricity dispatch projections) while meeting fuel supply, transmission, 

dispatch, and reliability constraints. 

Natural gas supply, demand, transportation, storage, and related costs are modeled 

directly in IPM through the incorporation of a natural gas module. The module includes a detail 

rich representation of the natural gas pipeline network inclusive of discount curves that represent 

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the marginal value of gas transmission as a function of the pipeline’s load factor. IPM’s natural 

gas module has the capability to expand pipeline capacity on an economic basis. 

At the unit level, IPM contains a detailed representation of new and existing resource 

options, inclusive of key operational limitations. For example, turn down constraints are 

designed to account for the cycling capabilities of EGUs to ensure that the model properly 

reflects the distinct operating characteristics of peaking, cycling, and base load units. EPA 

believes IPM represents a powerful tool to evaluate the technical feasibility of requiring 

increasing levels of re-dispatch from higher to lower-emitting EGUs. 

The EPA has conducted extensive analysis to quantify the opportunity to reduce CO2

emissions through re-dispatch. As part of this effort, the EPA conducted an initial set of analyses 

utilizing the Integrated Planning Model (IPM) to provide a framework for understanding the 

broader economic and emissions implications of shifting generation from coal-fired steam EGUs 

to NGCC units within defined areas.48 In the most restrictive scenarios, re-dispatch was 

simulated only between EGUs located in the same state. These scenarios were designed to 

consider, even under a restrictive interpretation of the degree of re-dispatch that might constitute 

a component of BSER under CAA section 111(d),49 to what extent existing NGCC units could 

increase their dispatch cost-effectively taking into account the impact of that behavior on prices 

of natural gas and electricity. To evaluate how EGU operators and balancing authorities could 

respond to a state’s goal by incentivizing re-dispatch from more carbon-intensive to less carbonintensive EGUs, the EPA introduced two additional elements to the IPM framework: 

                                                            

48 IPM is a multi-regional, dynamic, deterministic linear programming model of the U.S. electric power sector. It 

provides forecasts of least cost capacity expansion, electricity dispatch, and emission control strategies while

meeting energy demand and environmental, transmission, dispatch, and reliability constraints. Full documentation 

of the IPM model can be found at http://www.epa.gov/powersectormodeling 49 In practice, unit dispatch does not respect state boundaries because least-cost supply must be balanced with 

demand in real time over grid interconnects which span multiple states (with the exception of the Electric Reliability 

Council of Texas interconnect). The design of this modeling scenario assumes artificial constraints on re-dispatch to 

force such behavior to respect state boundaries, given the context of this rulemaking’s quantification of individual 

state goals. These state boundary constraints necessarily forgo cost-effective opportunities to re-dispatch units in 

different states; as a result, costs and prices in this analysis are overstated. 
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1. The application of a CO2 charge to the variable cost of dispatch for all existing coal 

steam boilers, IGCC units, and oil/gas steam boilers greater than 25 MW and with a CO2

emissions rate greater than 1,100 lbs/MWh.50

2. Generation constraints that maintain the sum of state-level generation in the Base Case51

from existing NGCC of any size, plus existing coal steam, IGCC and oil/gas steam 

boilers greater than 25 MW and with a CO2 emissions rate >1,100 lbs/MWh. 

These elements test the economic and technical potential for re-dispatch by: (1) increasing 

dispatch costs for affected coal steam, IGCC, and O/G steam EGUs within each state, and (2) 

requiring that any reduction in output from those sources be offset in its entirety by an increase 

in output from that state’s existing NGCC capacity. Utilizing IPM to conduct this analysis 

ensures an integrated, least-cost, technically feasible solution subject to power sector system 

reliability constraints, fuel market impacts, natural gas transmission and distribution networks, 

electric power transmission constraints, and unit-specific characteristics (e.g., operating and 

maintenance costs, heat rate, turndown/cycling behavior). 

Cost and Availability of Economic Re-Dispatch Opportunities

In executing this analysis, the EPA conducted a number of scenarios to quantify the 

relationship between the amount and cost of re-dispatch. Figure 3-65 below presents the 

projected national average capacity factor for NGCCs in 2020 (the first year of the assumed redispatch incentive) and the associated average $/tonne of CO2 reduced by comparing emissions 

and costs against the EPA’s Base Case (the difference in total system cost divided by the 

difference in power sector emissions). While the charge is applied exogenously in IPM, the 

average $/tonne shown below is calculated from the modeling results and projections by dividing 

the increase in total system costs (compared to the base case) by the total change in CO2

emissions (compared to the base case). 

                                                            

50 The addition of CO2 costs represents a simple analytic approach to estimating the cost-effective CO2 reductions 

under this building block and acts as a proxy for some existing state policies that shift dispatch. In actual plan 

implementation, states would be free to select any policy approach that has the net effect of reducing the carbon 

intensity of generation and/or reducing overall emissions from affected sources. 

51 http://epa.gov/powersectormodeling/BaseCasev513.html

Comment [A10]: By imposing a carbon price,

one is modeling the most economically efficient

method of abatement, not the costs associated with

an increase in NGCC capacity factors. The former

has little bearing on the latter.

Comment [A11]: EPA Response:

EPA believes the commenter has mischaracterized

this particular analysis.  The charge is applied to a

certain set of sources to explore the concept of

redispatch and assess the potential impacts, to

directly support BSER.  The combination of the

charge on steam boilers with the constraint to

maintain total generation across fossil fuel‐fired

steam boilers and NGCCs is specifically designed to

analyze the costs associated with an increase in

NGCC capacity factors.

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Comment [A12]: EPA Comment:

While latter portions of this section have heavy

redline, it largely reflects reordering, and maintains

the same context (for the most part).

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Figure 3-65: NGCC National Capacity Factor, 2020 Initial Analyses 

The EPA believes average $/tonne – which is distinct from the $/tonne CO2 cost imposed in 

these analytic scenarios on affected coal steam, IGCC, and O/G steam EGUs – to be the most 

relevant metric in evaluating cost-effectiveness. System cost changes necessarily encompass all 

58%

62%

65%

68% 71%

74% 75%

0%

10%

20%

30%

40%

50%

60%

70%

80%

 ‐  10 20 30 40 50 60

Average Capacity Factor

Average $/tonne

Projected Capacity Factor for Existing NGCCs (2020)

58%

62%

65%

68% 71%

74% 75%

0%

10%

20%

30%

40%

50%

60%

70%

80%

 ‐  10 20 30 40 50 60

Average Capacity Factor

Average $/tonne

Projected Capacity Factor for Existing NGCCs (2020)

Comment [A13]: $/tonne costs seem high –

would be helpful to have more detail on

methodology/analysis used to derive these costs?  

Comment [A14]: EPA Response:

Some clarifying language was added to distinguish

between the “charge” and the avg $/tonne, and

how it is calculated.

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elements of cost across power, transmission, and fuel markets and therefore provide the most 

comprehensive perspective regarding cost-effectiveness. 

 
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Table 3-54: Power Sector Emission Reductions Due to Re-Dispatch 

CO2 Cost Level 

Imposed 

National Average 

NGCC 

Capacity Factor 

Average Cost 

($/tonne) 

2020 Power Sector CO2

Emissions 

(MMT / % Change from 

2020) 

Base Case 52% N/A 2,161 

$10/tonne 58% $17 2,038 / -6% 

$15/tonne 62% $18 1,997 / -8% 

$20/tonne 65% $21 1,961 / -9% 

$25/tonne 68% $27 1,928 / -11% 

$30/tonne 71% $34 1,901 / -12% 

$40/tonne 74% $44 1,866 / -14% 

$50/tonne 75% $50 1,852 / -14% 

 

Although the EPA views this estimated range of average $/tonne costs as reasonable, we 

expect the costs of implementing this requirement in a compliance52 setting will be considerably 

lower for several reasons: 

 Analytic construct used to simulate re-dispatch incentive: As described earlier in this 

chapter, the EPA’s initial analyses utilized CO2 charges on the variable cost of dispatch 

for existing coal steam, IGCC, and O/G steam with emission rates greater than 1,100 

lbs/MWh and a capacity greater than 25 MW, as an analytic construct to induce redispatch behavior in the model to existing NGCC facilities. The CO2 charge was applied 

uniformly to all states in order to quantify the ultimate amount of in-state re-dispatch 

opportunities available as that charge is increased across scenarios. In the initial analyses, 

low levels of CO2 charges produce cost-effective re-dispatch opportunities relative to the 

Base Case in almost all states. However, as the CO2 costs are increased to higher levels, 

economic re-dispatch, opportunities within some states may eventually plateau – a point 

                                                            

52 The Regulatory Impact Analysis supporting the proposal examines, in an illustrative manner, how the power

sector could respond to the state goals that are calculated from all of the building blocks in a cost effective

manner.

Comment [A15]: Can this be quantified?

Comment [A16]: EPA Response:

Footnote added.  This is shown, in an illustrative

manner, in the RIA.
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clearly illustrated in the declining slope of the best-fit line in Figure 3-65. A uniform 

application of the same rising CO2 charge in all states produces an outcome for many 

states where the additional CO2 costs imposed on affected coal steam, IGCC, and O/G 

steam are not able to produce incremental economic re-dispatch at units within that state; 

therefore, the additional costs imposed by these higher CO2 charges overstate the actual 

$/tonne necessary to induce achievable re-dispatch in each state. 

 Potential for multi-state compliance: The EPA also analyzed scenarios where shifting of 

generation among EGUs was not limited by state boundaries. In one set of analyses, redispatch was allowed to occur across the multi-state regions defined by NERC 

assessment areas (subject to other real-world constraints specified in the model, including 

transmission limits). In these scenarios with greater re-dispatch flexibility, the system 

was able to achieve 8% greater CO2 emission reductions at an identical CO2 charge

(relative to a scenario where it was limited on a state basis), , demonstrating that the main 

analysis’s imposition of artificial re-dispatch boundaries on state borders overstates the 

cost-effectiveness of re-dispatch potential. 

To evaluate how EGU owners and grid operators could respond to a state plan’s possible 

requirements, signals, or incentives to re-dispatch from more carbon-intensive to less carbonintensive EGUs, the EPA also analyzed an additional series of scenarios in which the fleet of 

NGCC units nationwide was required, on average, to achieve a specified annual utilization rate. 

Specifically, the scenarios required average NGCC unit utilization rates of 65, 70, and 75 

percent. For each scenario, dispatch decisions are allowed such that electricity demand is met at 

the lowest total cost, subject to all other specified operating and reliability constraints for the 

scenario, including the aforementioned state-by-state generation levels from the base case. This 

constraint effectively requires states that decrease coal generation to offset, in equal amounts, 

NGCC generation. Collectively, states must achieve the required capacity factor for NGCCs. 

The costs and economic impacts of the various scenarios were evaluated by comparing 

the total costs and emissions from each scenario to the costs and emissions from a business-asusual scenario. For the scenario reflecting a 70 percent NGCC utilization rate and a constraint 

prohibiting interstate re-dispatch opportunities, comparison to the business-as-usual case 

indicates that the average cost of the CO2 reductions achieved ranged from [$xx] to [$xx] per 

metric ton of CO2.

Comment [A18]: EPA Response:

Clarification added.

Comment [A17]: Can you clarify if this 8%

greater emission reduction is relative to base case

or relative to reductions achieved from redispatch

without regional scenario?

Comment [A19]: Also, can this be stated

alternately as a drop in cost for a given CO2

reduction level?

Comment [A20]: EPA Response:

The commenter’s intuition is correct, but we do not

have analytic scenarios that can quantify this

concept because we did not model “a given CO2

reduction level” between state and regional re‐

dispatch scenarios.

Comment [A21]: It would be helpful 

to have the results – can EPA 

provide this? Will it be in the 

docket?

Comment [A22]: EPA Response:  EPA will

provide this modeling in the docket for the

proposal.
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 The costs and economic impacts of the various scenarios were evaluated by comparing 

the total costs and emissions from each scenario to the costs and emissions from a business-asusual scenario. For the scenarios reflecting a 65, 70, and 75 percent NGCC utilization rate, 

comparison to the business-as-usual case indicates that the average cost of the CO2 reductions 

achieved over the 2020-2029 period was $21, $30, and $40 per metric ton of CO2, respectively. 

However, we also note that the costs just described are higher than we would expect to actually 

occur in real-world compliance with this proposal’s goals. This is because only 29 state goals are 

premised on the existing NGCC fleet achieving an average capacity factor of 70 percent. 

Consequently, a 70 percent utilization rate target for the existing NGCC fleet requires an average 

national capacity factor of 63 percent. 

These scenarios include constraints such that there will be no cost-effective re-dispatch 

opportunities among EGUs in different states, contrary to the reality that interstate flows of 

electricity routinely change in response to economic conditions. As a result, this case assumes no 

use of interstate electricity trading as a cost reduction mechanism, and thus overstates the 

impacts of re-dispatch. 

 In the 70 percent NGCC unit utilization rate scenario with restrictions on 

interstate re-dispatch, natural gas prices were projected to increase by a range of from [x] percent 

to [x] percent, which is within the range of historic natural gas price variability. Projected 

wholesale electricity price increases ranged from [x] to [x] percent, which similarly is within the 

range of historic electric price variability. 

The EPA also analyzed dispatch-only scenarios where shifting of generation among 

EGUs was not limited by state boundaries. In one set of analyses, re-dispatch was simulated to 

occur across the multi-state regions overseen by independent system operators (ISOs) and other 

regional transmission organizations (RTOs), while in another set of analyses, national redispatch was simulated (subject to other constraints specified in the model, including 

transmission limits). In these scenarios with greater re-dispatch flexibility, the cost of achieving 

the quantity of CO2 reductions corresponding to a nationwide average NGCC unit utilization of 

70% was notably lower. 

The EPA also analyzed dispatch-only scenarios where shifting of generation among 

EGUs was limited by state boundaries. In these scenarios with less re-dispatch flexibility, the 

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Comment [A23]: A lot of text has been devoted

to demonstrating how the NGCC fleet will cope with

increase dispatch from the coal fleet.  Analysis

should also be included of how the coal fleet will

respond to various levels of redispatch, and if there

is information on how coal plants can dial down

output when demand is reduced without having to

switch off.

Comment [A24]: EPA Response:

Some additional detail that addresses this comment

was added earlier, in the context of the modeling

framework.

Comment [A25]: Can the actual numbers on

costs be presented in a table or other format, other

than just stating “notably lower”?

Comment [A26]: A table has been added.
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cost of achieving the quantity of CO2 reductions corresponding to a nationwide average NGCC 

unit utilization of 70% was $33 per ton. 

Table 3-6: IPM Results from Re-Dispatch Scenarios 

Existing NGCC 

Average 

National 

Capacity 

Factor 

Re-Dispatch 

Constraint 

Average Cost 

($/tonne, 2020-

2029) 

Average CO2

Emissions 

(MMT, 2020-

2029) 

Reductions 

from Base Case 

(%, 2020-2029) 

Base Case NA NA 2,215 NA 

65% Regional $21 2,022 9% 

70% Regional $30 1,969 11% 

75% Regional $40 1,915 14% 

65% State $22 2,024 9% 

70% State $33 1,971 11% 

Natural Gas Price Impacts 

The extent of re-dispatch estimated in this building block can be achieved without 

causing significant economic impacts. For example, in neither of the 70 percent NGCC unit 

utilization rate scenarios – re-dispatch limited to regional or state boundaries – did delivered 

natural gas price projections increase by more than 10 percent in the 2020-2029 period, which is 

well within the range of historical natural gas price volatility. For example, the year-to-year 

percentage difference in Henry Hub prices reported by the Energy Information Administration 

averaged 18.5% over the period from 1981 to 2012.53 Projected wholesale electricity price 

increases over the same period were less than 7 percent in both cases, which similarly is well 

within the range of historic electric price variability. For example, the average year-to-year price 

                                                            

53 http://www.eia.gov/dnav/ng/hist/rngwhhdA.htm

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change for the PJM region was 19.5 percent over the period from 2000 to 2013. For all the ISOs 

in the East, the variation is virtually unchanged from the PJM example (at 19.6%).54 

However, for the reasons previously discussed with respect to estimated costs per ton of 

CO2, the actual implementation is expected to result in notably lower economic impacts, 

including natural gas price impacts, and are considerably larger than would actually occur in 

real-world compliance with this rule’s proposed goals. 

Table 3-X: National Average Delivered Natural Gas Price, 

Power Sector (Average 2020-2029) 

Existing NGCC 

Average National 

Capacity Factor 

Re-Dispatch 

Constraint Price ($/mmBtu) % Change 

Base Case NA $5.94 

65% Regional $6.36 7% 

70% Regional $6.53 10% 

75% Regional $6.69 13% 

65% State $6.37 7% 

70% State $6.52 10% 

Table 3-X: National Average Delivered Natural Gas Price, 

 Power Sector (Average 2020-2029) 

Price ($/mmBtu) % Change 

Base Case $6.05 

$10/tonne $6.21 3% 

$15/tonne $6.33 5% 

$20/tonne $6.42 6% 

$25/tonne $6.57 9% 

$30/tonne $6.61 9% 

                                                            

54 ISO Real‐Time data for all hours, from Ventx Velocity Suite data across Eastern ISOs (PJM, NYISO,ISO‐NE and

Midcontinent ISO).

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$40/tonne $6.78 12% 

$50/tonne $6.90 14% 

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INTERAGENCY WORKING COMMENTS ON DRAFT LANGUAGE UNDER EO12866

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Chapter 6: Fuel Switching 

Coal-to-Natural Gas Switching 

Introduction 

Firing natural gas in a boiler designed for coal-fired generation is one approach to reducing the 

output-based CO2 emissions rate (lbs/MWh) in these boilers. The CO2 emission rate is reduced 

when natural gas is substituted for coal because the gas has a much higher percentage of 

hydrogen and a lower percentage of carbon than the coal it replaces. When quantities of gas and 

coal are burned with oxygen from air to produce the same amounts of heat, the higher hydrogen 

content of natural gas produces more water vapor (H2O) than coal, but far less CO2. 

The discussion below focuses solely on the conversion of an existing coal-fired boiler to burn 

natural gas instead of, or along with, coal. There are other technical options for gas substitution 

in an existing coal-steam EGU that are not examined in any detail here. They include: 

 Repowering an existing coal EGU by providing heat input to the boiler from the exhaust 

of a newly installed gas turbine generator; and, 

 Gasification of coal, producing substitute natural gas (SNG) that provides heat input to 

the existing coal-fired boiler. 

These other options have higher capital cost and thus would not be as economic as the direct 

substitution of natural gas in an existing coal boiler, for reasons that will become apparent in this 

analysis. 

This chapter evaluates the cost-effectiveness of widespread adoption of coal-to-gas switching at 

a national level for the purpose of setting CO2 emissions goals consistently in each state. 

Description of Technology 

 Engineering Considerations 

Most existing coal-fired EGU boilers can be modified to switch to 100% gas input, or to co-fire 

gas with coal in any desired proportion. This transition typically requires at least some plant 

modifications and might have some negative impact on the efficiency of the unit as described 

later in this chapter. 
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A conversion from coal to gas firing first requires either an existing natural gas delivery system 

to the boiler or the installation of a new gas pipeline to serve the boiler. While it is sometimes 

assumed that a need to install a new gas pipeline would render the conversion uneconomic, this 

analysis will show that the cost of a new gas pipeline is not likely to be the determining factor for 

the project’s economic merit, given the significance of the change to the cost of fuel for 

generation from the converted boiler. 

Conversion to natural gas firing in a coal-fired boiler typically involves installation of new gas 

burners and supply piping, modifications to combustion air ducts and control dampers, and 

possibly modifications to the boiler’s steam superheater, reheater, and economizer heating 

surfaces that transfer heat from the hot flue gas exiting the boiler furnace. The conversion may 

also involve some modification and possible deactivation of some downstream air pollution 

emission control equipment. Engineering studies are performed to assess changes in furnace heat 

absorption and exit gas temperature; material changes affecting heat transfer surfaces; the need 

for sizing of flue gas recirculation fans; and operational changes to sootblowers, spray flows, air 

heaters, and emission controls. 

Whether co-firing with coal or switching completely to natural gas, boilers will become less 

efficient due to the high hydrogen content of natural gas. When combusted, the additional 

hydrogen yields increased moisture content (water vapor) in the flue gas. The increased 

moisture content, in turn, results in additional heat lost up the stack instead of being directed 

towards electricity generation. Additionally, depending on the design of the boiler and extent of 

modifications, some boilers may incur some derate (reduction in generating capacity) in order to 

maintain steam temperatures at or within design limits, or for other technical reasons. 

Even with a decrease in boiler efficiency, the overall net output efficiency of a coal-steam boiler 

EGU that switches from coal to natural gas firing may change only slightly, depending on how 

much auxiliary load is converted to net output by avoiding the need to run coal pulverizers, 

conveyors, ash sluice pumps, and relevant air pollution control equipment (e.g., PM and SO2

controls). 

Fuel Considerations 

Delivery of natural gas via pipeline is critical for conversion of a coal-fired boiler to a gas-fired 

boiler. Some coal boilers are connected to the natural gas pipeline network for purposes of using 

Comment [A1]: Would there also be a reduction

in emissions equipment (and possible removal of

baghouses, electrostatic precipitators, and

scrubbers.).If so, consider making this point.

EPA:  Clarification added.
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gas as a startup fuel, or are located at facilities with onsite gas-fired generators. These boilers are 

likely able to co-fire to some degree with gas (at least 10% total output1

) without constructing 

additional gas pipeline capacity. For purposes of this analysis, the EPA conservatively assumed 

that gas use of 10% or greater at these boilers, or any gas use at boilers without an existing gas 

pipeline, would require construction of additional pipeline capacity. 

Unlike coal, natural gas cannot be stored in quantities sufficient for sustained utilization on site. 

To the extent that firm (uninterruptible) gas supply is contractually unavailable or costprohibitive, any potential interruption in gas supply could impact the ability of the unit to 

continue operating without increasing its CO2 emissions rate (since it would likely need to 

substitute more CO2-intensive fuel for the unavailable natural gas). Additionally, for boilers that 

switch to 100% gas, interruption in gas impacts the ability of the unit to continue generating at 

all if gas is unavailable. For these reasons, an EGU switching to a large percentage of gas use 

may elect to install more than one new gas supply pipeline from separate sources. Although the 

EPA assumes the addition of one gas pipeline in the simplified cost analysis presented below, it 

will be seen that pipeline cost will generally not be the main driver of economic feasibility. 

Cost and Performance Impacts of Coal-to-Gas Switching 

The analysis described in this section presents a hypothetical conversion of a boiler from burning 

100% coal to burning varying proportions of gas (10%, 50%, and 100%). The capital cost of 

modifying a coal boiler to switch to natural gas includes the new gas burners and piping, 

combustion air ductwork and control damper modifications, air heater upgrades, gas 

recirculating fans, control systems modifications, and other site-specific modifications, as well as 

any pipeline installation costs that would be necessary to supply the unit’s assumed level of gas 

combustion following the conversion. 

For this analysis, the EPA assumes capital costs for pulverized coal (PC) and cyclone boiler 

modifications are as follows2

: 

$/kW = 267*(75/MW)0.35 (pulverized coal) 

                                                            

1 Based on assumed use of Class 1 igniters (10% of burner capacity) as defined in NFPA 85 Boiler and Combustion

Systems Hazards Code. 2 EPA assumptions on costing and performance associated with coal‐to‐gas conversion and pipeline additions in

this analysis are generally consistent with assumptions presented and discussed in EPA’s power sector modeling

documentation, Chapter 5.7, at: http://www.epa.gov/airmarkets/progsregs/epa‐ipm/docs/v513/Chapter_5.pdf
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$/kW = 374*(75/MW)0.35 (cyclone) 

Based on the above formula, a 500 MW pulverized coal unit would have a capital cost of 

$137/kW to convert the boiler such that it could burn any proportion of natural gas. For this 

illustrative example, to support 100% gas combustion we assume that a 50-mile gas pipeline3

 at 

$50 million, 4 or $100/kW for a 500 MW unit, is also required, which raises the unit’s total 

capital cost for conversion to $237/kW. Black & Veatch also used a similar cost level in a recent 

case study.5

 At a 14.3% capital charge rate6 and 75% annual capacity factor, the total capital cost 

in this example equates to an annualized capital cost of about $5/MWh. This $/MWh capital cost 

is relatively insignificant compared to the increase in fuel cost discussed later. 

Due to a reduced need for operators, maintenance materials, and maintenance staff, EPA 

engineering staff assumed that fixed O&M costs are reduced by 33% as a result of switching 

from coal to 100% gas. Similarly, variable O&M costs are assumed to be reduced by 25% due to 

reduced waste disposal, reduced auxiliary power requirement, and miscellaneous other costs. 

EPA engineering staff also assumed for this analysis that there would be no derate in the net 

EGU output, and estimated that the impact on net heat rate for an average unit would be a 3% 

increase for a switch from coal to 100% natural gas firing. The assumed 3% increase in net heat 

rate is conservative compared to the 2% assumption used by Black & Veatch in their previously 

mentioned case study. 

Cost of Fuel 

For this analysis, the EPA uses base case projections for delivered gas prices that are about 

double projected delivered coal prices on average ($2.62/MMBTU for coal, $5.36/MMBTU for 

                                                            

3 Based on EPA analysis, the majority of existing coal units would require less than 50 miles of new gas pipelines to

switch fuels from coal to 100% natural gas.  See Chapter 5 and Table 5‐22 of Documentation for EPA Base Case

v.5.13 Using the Integrated Planning Model, available at: http://www.epa.gov/airmarkets/progsregs/epa‐

ipm/BaseCasev513.html

4 For those plants that require additional pipeline capacity, the average capital cost of constructing new pipelines is

assumed to be approximately $1 million per mile of pipeline built, which is consistent with assumptions used in

EPA’s IPM modeling. 5 A Case Study on Coal to Natural Gas Fuel Switch, Black & Veatch, Power‐Gen International, December 2012,

available at http://bv.com/redirects . 6 Capital charge rate at 14.3% is the average of the regulated utility and unregulated merchant rates as used in

IPMv5.13 for environmental retrofits having a 15 year book life.  

Comment [A2]: Are there any references to cite

for fixed O&M and variable O&M cost reductions?

EPA: EPA included these assumptions only for 

completeness: annualized non-fuel O&M costs are 

small compared to the sum of annualized capital and 

fuel costs and do not materially affect the economics.

Comment [A3]: Suggest providing further

support for this choice. What is the sensitivity to

conclusions from this decision?

EPA:  This conservative assumption is not

controversial and has little effect on the economic

outcome.  
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gas).7 As a result, the fuel cost for a typical converted boiler burning 100% gas is expected to be 

at least double its prior fuel cost on an output basis as well ($27/MWh for coal, $57/MWh for 

gas).8,9 Compared to the estimated $5/MWh capital cost impact presented above, a $30/MWh 

increase in fuel cost would make the difference in fuel costs the most significant driver of project 

economics when switching from coal to gas in a coal boiler.10 This difference would increase 

with higher gas prices, which would be projected to result from an increase in overall gas 

demand caused by widespread adoption of gas co-firing. 

Emission Reduction Potential 

The CO2 reduction potential is directly related to the amount of gas co-fired, and is due largely to 

the different carbon intensities of each fuel. More reductions in CO2 rate are achieved at higher 

levels of gas co-firing as shown in Table 6-1. At 10% gas co-firing, the net emissions rate 

(lbs/MWh net) of a typical unit would decrease by approximately 4%. At 100% gas co-firing, 

the net emissions rate (lbs/MWh net) of a typical unit would decrease by approximately 40%. 

Table 6-1. CO2 Rates at Various Levels of Natural Gas Co-Firing 

Case Heat Rate

(Btu/kWh)

CO2 Rate

(lbs/MWh net)

Reduction in CO2 Rate from 100% Coal

(lbs/MWh net)

100% Coal 10,340 2,108 N/A

10% Gas 10,370 2,021 4%

50% Gas 10,490 1,673 21%

100% Gas 10,640 1,239 41%

In addition to reducing CO2 emissions, natural gas co-firing at a coal-fired steam EGU will 

generally also reduce criteria air pollution. Reducing CO2 and criteria air pollution will result in 

                                                            

7 EPA Base Case 5.13, projections for 2020    8 This estimated fuel cost also accounts for the decrease in efficiency that results from switching from coal to gas in

a boiler, as well as the decrease in parasitic power consumption. 9 Combusting natural gas using combined‐cycle turbine technology can remain economically attractive

notwithstanding these types of fuel price differentials because combined cycle turbine technology converts a

substantially higher share of the fuel’s heat input into electricity output as compared to boiler technology.  The

$/MWh impact of a higher gas price in that instance is significantly mitigated by higher MWh output produced for

a given amount of heat input from the fuel purchased. 10 This demonstration assumes that the converting boiler in question remains a “price taker” in the fuel

marketplace, such that the projected gas and coal prices would be unaffected by this hypothetical unit’s potential

decision to convert.  However, if enough other units might be expected to make similar conversions, the aggregate

increased demand for natural gas would be likely to further increase the price differential between coal and gas,

making fuel costs an even more influential factor in the evaluation of such a project’s economic merit.

Comment [A4]: Would it be worth mentioning

the potential volatility of natural gas prices (vs. coal

prices)?  

1.http://www.eia.gov/naturalgas/

http://www.eia.gov/coal/

Comment [A5]: EPA: We believe that annual

average fuel cost is a more appropriate metric for

making this assessment.

Comment [A6]: Suggest inclusion of heat rate

units.

Comment [A7]: EPA: Thank you.  See revised

table.
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climate benefits and human health co-benefits. The impacts of these pollutants on the 

environment and health are discussed in detail in Chapter 5 of the RIA for this proposed rule. 

For this analysis, EPA estimated the PM2.5-related human health co-benefits of SO2, NOX, and 

direct-PM2.5 emission reductions attributable to a range of natural gas co-firing levels at an 

illustrative coal steam unit burning bituminous coal in 2020.11 The estimated monetized cobenefits do not include climate benefits or health effects from direct exposure to NO2, SO2, and 

HAP; ecosystem effects; or visibility impairment. Only the unit-level emissions of SO2, NOX and 

direct-PM2.5 are considered in this illustrative exercise. Additionally, emissions from the 

extraction and transport of the fuels used by these technologies are not considered. Furthermore, 

there may be differences in upstream greenhouse gas emissions (in particular, methane) from 

different technologies but those were not quantified for this assessment. The estimated avoided 

emissions under 10% gas co-firing and a 100% switch to gas are presented Table 6-2. 

Table 6-2. Avoided Emissions at Various Levels of Co-Firing, based on Illustrative Unit 

(lbs/MWh net) 

 

10% 

Gas 

100% 

Gas 

SO2 0.3 3.1 

NOX 0.2 2.04 

PM2.5 0.02 0.2 

To estimate human health co-benefits for this illustrative coal steam unit, the EPA used PM2.5-

related benefit-per-ton estimates for SO2, NOX, and direct-PM2.5 emission reductions described 

in detail in Chapter 5 of the RIA for this proposal. To estimate the benefits associated with cofiring, we determine the emission reductions for co-firing in Table 6-2 and apply the 2020 social 

benefit values discussed in Chapter 5 of the RIA for this proposal. Specifically, we multiply the 

reduction in SO2, NOX, and direct-PM2.5 emissions by the PM2.5-related benefit per-ton estimates, 

and add those values to get a measure of 2020 benefits. Table 6-3 shows the PM2.5-related 

benefits expected based on the estimated emission reductions that would occur in this illustrative 

example. These estimates are purely illustrative as the EPA does not assert a specific location for 

                                                            

11 The illustrative unit in this analysis was assumed to be a 500 MW coal‐steam unit burning bituminous coal with a

heat rate of 10,339 btu/kWh (net) operating at 75% capacity factor.  Furthermore, this unit was assumed to

operate a wet scrubber, cold‐side ESP, and SNCR.
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7 

the illustrative electricity generation technologies and is therefore unable to specifically 

determine the population that would be affected by their emissions. Therefore, the benefits for 

any specific unit can be different than the estimates shown here. 

Table 6-3. Rounded PM2.5-related Co-benefits ($/MWh net) of Gas Co-firing (2011$) 

Health Co‐benefit Discount Rate

   3% Discount Rate 7% Discount Rate

Gas Co‐firing 10% $6.5 to $15 $5.9 to $13

Gas Co‐firing 100% $67 to $150 $61 to $140

Note: All estimates are rounded to two significant figures. Co‐benefits are based on national benefit‐per‐ton estimates for directly emitted

PM2.5 and PM2.5 precursors, SO2 and NOX. It is important to note that the monetized health co‐benefits do not include reduced health effects

from ozone or direct exposure to NO2, SO2, and HAP; ecosystem effects; or visibility impairment. Emissions of directly emitted particles are

disaggregated into EC+OC or crustal components using the method discussed in Appendix.12 5A of the RIA for this proposal. The health co‐

benefits reflect the sum of the PM2.5 co‐benefits and reflect the range based on adult mortality functions (e.g., from Krewski et al. (2009) to

Lepeule et al. (2012)).

The precise incremental health co-benefits associated with lower emissions would depend 

primarily on the location of the co-firing unit, the specific types of coals that natural gas would 

replace, and the pollution controls installed on that unit. This illustrative assessment is unable to 

account for these characteristics. However, these factors will not change the qualitative 

conclusion. There will always be incremental human health co-benefits associated with co-firing 

natural gas in an existing coal steam boiler, independent of the location, coal type, and operating 

pollution controls. 

A related beneficial use of natural gas in existing coal boilers can be via gas reburning, a NOx 

reduction technology.13 Gas reburning involves firing natural gas (between 10 and 25% of total 

heat input) above the primary combustion zone in the boiler furnace. This upper-level firing 

creates a slightly fuel-rich zone. NOx produced in the primary zone of the furnace is "reburned" 

in this zone and converted to molecular nitrogen and other reduced nitrogenous species. Overfire 

                                                            

12 Krewski D.; M. Jerrett; R.T. Burnett; R. Ma; E. Hughes; Y. Shi, et al. 2009. Extended Follow‐Up and Spatial Analysis

of the American Cancer Society Study Linking Particulate Air Pollution and Mortality. HEI Research Report, 140,

Health Effects Institute, Boston, MA.

Lepeule, J.; F. Laden; D. Dockery; J. Schwartz. 2012. “Chronic Exposure to Fine Particles and Mortality: An Extended

Follow‐Up of the Harvard Six Cities Study from 1974 to 2009.” Environmental Health Perspectives, July, 120(7):965‐

70.

13 DOE/NETL 2001, Evaluation of Gas Reburning and Low‐NOx Burners on a Wall‐Fired Boiler, DOE/NETL‐

2001/1143, February 2001, available at

http://www.netl.doe.gov/File%20Library/Research/Coal/major%20demonstrations/cctdp/Round3/GRLNBPPA.pdf
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air is injected downstream of the reburn zone to burn out the remaining combustibles and convert 

the reduced nitrogenous species to molecular nitrogen. The heat input from gas would 

approximately substitute for a similar heat input from coal, thus reducing CO2 and other coal 

emissions in a manner similar to gas co-firing as discussed above. 

Cost of Reductions and Cost Effectiveness 

This analysis examines the average $/tonne14 cost of avoided CO2 that results from applying a 

range of natural gas co-firing levels to a typical baseload coal boiler. We capture the capital 

costs of boiler modifications and new pipeline construction (assuming 50 miles of new 

pipeline),15 decreased FOM and VOM costs, and incremental fuel costs (based on IPMv5.13 

Base Case average delivered fuel price projections for coal and gas in 2020). For a typical coal 

boiler at current base case fuel prices, the average cost of avoided CO2 ranges from $83/tonne for 

100% gas switch to $150/tonne for co-firing at 10% (see Table 6-4). 

Table 6-4. Average Cost of Avoided CO2 and CO2 Emission Rate Reductions from 100% Coal at 

Various Levels of Natural Gas Co-Firing at Base Case Projected Gas Price ($5.36/MMBtu) 

Case Average Cost of Avoided CO2

($/tonne)

Change in CO2 Rate from 100% Coal

(lbs/MWh net)

100% Coal N/A N/A

10% Gas 150 4%

50% Gas 91 21%

100% Gas 83 41%

Note: Based on a typical 500 MW bituminous coal steam unit operating at 75% capacity factor.  Assumes

construction of new 50‐mile pipeline. EPA estimated reduced total capital costs for the 50% and 10% gas cases; for

example, total capital cost for 10% gas was estimated to be about one‐half of the capital costs for the 100% gas

case.

However, widespread adoption of gas co-firing would increase overall gas demand and place 

upward pressure on the natural gas price, which would consequently increase the average cost of 

avoided CO2 of a potential boiler conversion. 

   

                                                            

14 This document uses “tonne” to refer to a metric tonne.  All control costs in this analysis are presented in dollars

per metric tonne, or “$/tonne.” 15 Based on EPA analysis, the majority of existing coal units would require less than 50 miles of new gas pipelines to

switch fuels from coal to 100% natural gas.  See Chapter 5 and Table 5‐22 of Documentation for EPA Base Case

v.5.13 Using the Integrated Planning Model, available at: http://www.epa.gov/airmarkets/progsregs/epa‐

ipm/BaseCasev513.html

Comment [A8]: What is the sensitivity to your

gas price assumptions?  

Comment [A9]: EPA: These estimates are based

on projected base case fuel prices.  The following

paragraph explains that these estimates would

increase with widespread deployment of gas co‐

firing.  Since these estimates are at the lower end of

projected gas prices under a scenario that would in

practice increase gas use, we believe that our

conclusion is robust against other potential future

gas prices with or without increased gas co‐firing.  
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9 

Conclusion 

Switching from coal to gas is a relatively costly approach to CO2 reductions at existing coal 

steam boilers when compared to other measures such as heat rate improvements and re-dispatch 

of generation supply to other existing capacity with lower CO2 emission rates. Moreover, this 

analysis shows that coal-to-gas conversion of an existing boiler is less efficient than constructing 

a new natural gas combined cycle (NGCC) turbine in its place. For example, EPA analysis 

indicates that replacing the coal steam plant discussed above with a new NGCC facility would 

reduce the net CO2 emission rate of the generating capacity by 62% at a cost of about $50/tonne 

of avoided CO2 under the base case projected gas price and about $81/tonne of avoided CO2 at a 

future gas price 50% higher than the base case projection. [INSERT CROSS-REFERENCE TO 

LOCATION IN RULE MATERIALS WHERE WE EXPLAIN WHY WE ARE NOT 

CONSIDERING NEW NGCC POTENTIAL TO REPLACE EXISTING COAL AS A 

REDUCTION MEASURE FOR CRAFTING STATE GOALS.] See preamble section VI.C.3.c.

The EPA is considering cost-effectiveness at a national level for the purpose of setting emissions 

goals consistently in each state. While this analysis suggests that cost-effective reductions of 

CO2 are not available on a national basis from widespread adoption of natural gas co-firing, it 

does not preclude the potential for individual EGUs to utilize co-firing as a way to reduce CO2

and other emissions, nor does it preclude states from factoring in that unit-level potential into the 

design of state plans for compliance with the 111(d) standard. EPA notes that there are utilities 

that see merit in converting some existing coal units to burn 100% gas, and several are currently 

doing so.16,17

   

                                                            

16 Reuters 2014, “Southern to repower three Alabama coal power plants with natgas,” Reuters U.S. Edition,

January 16, 2014  , available at http://www.reuters.com/article/2014/01/16/utilities‐southern‐alabama‐

idUSL2N0KP1WA20140116

17 Dominion 2012, “Dominion Virginia Power Proposes To Convert Bremo Power Station From Coal To Natural

Gas,” Dominion News, September 5, 2012, available at http://dom.mediaroom.com/2012‐09‐05‐Dominion‐

Virginia‐Power‐Proposes‐To‐Convert‐Bremo‐Power‐Station‐From‐Coal‐To‐Natural‐Gas

Comment [A10]: Is there any reference to cite

for these numbers?

EPA:  Added clarification of source.

Comment [A11]: please fix.

EPA: Citation inserted.
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10 

Biomass Co-firing 

Introduction 

Co-firing biomass in existing boilers designed for coal-fired generation, or converting those 

boilers to consume entirely biomass, is another approach to potentially reduce the output-based 

CO2 emissions rate (lbs/MWh) of these boilers. In the analysis presented in this technical 

support document, the physical CO2 emissions rate at the boiler stack could increase or decrease, 

depending on the amount of coal energy replaced by biomass energy and differences in the 

properties of a selected biomass and the coal it replaces.18 

There are many possible combinations of coals and biomass types that could be co-fired. Sitespecific economics and accessibility would determine which combinations might actually be 

feasible. This TSD analysis does not attempt to estimate an economically feasible national 

average increase or decrease in CO2 emission rate via biomass co-firing. Instead, this analysis 

simply employs one reasonably representative case to evaluate the cost effectiveness of biomass 

energy substitution in reducing the physical CO2 emission rate based only on the CO2 coming 

from coal. This analysis indicates that while the co-firing of biomass with coal is technically 

feasible as a means of reducing the coal-based CO2 emission rate due to the substitution of 

biomass for coal, it generally has limited economic feasibility due to the generally higher cost of 

energy from biomass as compared to coal. This general finding largely explains the very limited 

amount of biomass co-firing currently practiced in the U.S. It is also consistent with recent 

findings by others19 and others, including an earlier study by the State of Maryland20 that 

concluded as follows: 

“Due to the higher cost of biomass fuels when compared to coal, cofiring with biomass 

will lead to an increase in fuel costs. Without consideration for any environmental 

benefits, it is unlikely that any Maryland coal-fired facility would make the investments 

required to cofire with a more expensive and less efficient fuel.” 

                                                            

18 Fuel properties particularly affecting relative CO2 emission rates are: higher heating value, carbon and hydrogen

contents, and as‐fired moisture content.    19 Nowling, Una, Black & Veatch, “Utility Biomass Use: Turning Over a New Leaf?, Power, May 2014, available at

http://accessintelligence.imirus.com/Mpowered/book/vpow14/i5/p52

20 The Potential for Biomass Cofiring in Maryland, Maryland Department of Natural Resources, March 2006, (pg 53)

http://esm.versar.com/pprp/bibliography/PPES_06_02/PPES_06_02.pdf

Comment [A12]: You might also mention coal

plants that have been retired (i.e. decommissioned)

or smaller facilities that have been converted

entirely to biomass (i.e. Schiller, NH and others).

EPA:  

We appreciate the commenter’s perspective

regarding biomass use in EGUs.  

This TSD analysis evaluates the co‐firing of about

10% biomass with coal in many existing large boilers

because we believe that scenario supports a

consideration of the theoretical impacts of generally

increasing biomass combustion.  We do not believe

that the potential conversion of individual boilers to

100% biomass (in limited instances where the

economics might be favorable) would materially

affect the evaluation we present here.  We have

selectively adopted the suggested edits in

accordance with this view.

Comment [A13]: Maryland is not representative

of biomass co‐firing across the United States,

neither is a 2006 study. For example, limiting to this

case ignores coal plants that have been retired or

facilities that have been converted entirely to

biomass (i.e. Schiller, NH and others).

EPA: Additional clarification added, with an

additional recent citation.  

Comment [A14]: : Biomass will be more

economically feasible with an implicit carbon tax on

fossil emissions, as well as increased recognition of

the other air quality benefits (e.g. lowered toxic

emissions, etc.) that could be realized by cofiring.

Indeed the co‐firing of biomass is much more

prevalent than is CCS, which EPA has described in

more generous terms in the 111(b) rulemaking. It

also ignores one of the major economic barriers to

biomass co‐firing which has been the difficulty/lack

of desire/cost to open up Clean Air Act permits to

allow biomass co‐firing where that was not part of

the original permitting proposal.  

EPA:  This chapter assesses the cost effectiveness of

fuel switching relative to other CO2 reduction

technologies from a technical perspective.  The

chapter does conclude that “[while] cost‐effective

reductions of CO2 are not available on a national

basis from widespread adoption of biomass co‐

firing, [this rule] does not preclude the potential for

individual EGUs to utilize co‐firing as a way to

reduce overall CO2 emissions, nor does it preclude

states from factoring in that unit‐level potential into

the design of state plans for compliance with the

111(d) standard.”

Formatted: Font: Italic
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Based on the basic analysis of the cost effectiveness of biomass energy substitution in reducing 

the physical CO2 emission rate based only on the CO2 coming from coal presented below, the 

EPA concludes in this TSD that biomass co-firing would not be a cost-effective measure on 

which to base state goals. 21 

This TSD’s analysis indicates that while the co-firing of biomass with coal is technically 

feasible, and in some cases it can yield increases in the stack emission rate of CO2 (lb/MWh). In 

the absence of this rulemaking or a program that puts an implicit price on fossil carbon biomass 

co-firing ) and has limited economic feasibility given the delivered cost of available biomass 

versus the cost of coal. However, the use of co-firing biomass to help meet the 111(d) state goals 

may be economically feasible if the cost of reducing fossil carbon emissions is high. For 

example, Europe is currently co-firing substantial amounts of biomass to help lower carbon 

emissions of their fossil fuel fired electricity sector (Ehrig and Behrendt 2013). That study notes 

that co-firing biomass is one of the lower cost options to reach the EU-2020 targets. 

Description of Technology 

Engineering/Economic Considerations 

The technical feasibility of biomass co-firing in existing coal-fired boilers has been thoroughly 

investigated in many research and engineering studies, as well as in test burns at coal power 

plants in the U.S. and globally.22 It has been demonstrated that the boiler and related systems of 

almost any existing coal-fired EGU can accept or be modified to support co-firing of at least 

                                                            

21 This analysis does not include evaluation of stack biogenic CO2 emissions relative to the net landscape and

process‐related carbon fluxes associated with the production and use of the biogenic feedstocks combusted. Issues

related to methods for assessing biogenic CO 2 emissions from stationary sources are currently being evaluated by

the EPA. In general, the overall net atmospheric contribution of CO 2 resulting from the use of a biogenic feedstock

by a stationary source, such as an EGU, will ultimately depend on the stationary source process and the type of

feedstock used, as well as the conditions under which that feedstock is grown and harvested. In September 2011,

the EPA submitted a draft Accounting Framework to the Science Advisory Board (SAB) Biogenic Carbon Emissions

(BCE) Panel for peer review. The SAB BCE Panel delivered its Peer Review Advisory to the EPA on September 28,

2012. In its Advisory, the SAB recommended revisions to the EPA's proposed accounting approach, and also noted

that biomass cannot be considered carbon neutral a priori, without an evaluation of the carbon cycle effects

related to the use of the type of biomass being considered.   22 See Partial Bibliography – Biomass Co‐firing at end of this section.

Comment [A15]: EPA: Thank you for the

comment and suggested edit.  See conclusion for

similar language regarding the potential for

individual EGUs to utilize co‐firing as a way to

reduce overall CO2 emissions.
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some small percentage of biomass. In some cases, major modifications can be made to support a 

switch to 100% biomass.23 

A decision to actually modify an existing coal-fired boiler for biomass co-firing at any 

percentage level depends on numerous technical and economic factors, including reliable 

availability of suitable biomass at an economic cost; adequate onsite space for biomass receiving, 

storage, preparation, and handling systems; potential corrosive effects of biomass ash in the 

boiler furnace; potential impacts of co-firing on boiler efficiency even at low biomass 

percentages, and the likely reduction (derate) in unit generating output at very high biomass 

percentages. 

There are considerable physical differences between coal and biomass that will generally limit 

the extent to which biomass can be reasonably used to replace coal in a boiler. For example, 

compared to most coals, many solid biomass fuels have both a significantly higher as-fired 

moisture content and a significantly lower heating value per unit of weight. Most solid biomass 

fuels are also significantly less dense than most coals. For example, a typical biomass might have 

twice the moisture, half the heating value, and less than half the density of coal.24 Important 

consequences of these physical differences are that the weight of biomass needed to provide a 

given amount of heat energy could be twice the weight of the coal it replaces, and the volume 

(cubic feet) of biomass needed could be four-to-eight times the volume of coal replaced. 

Biomass requires space for storage after delivery to a facility, and the length of time that the 

biogenic material would remain on site prior to use can differ. For example, wood chips could 

be delivered year-round while crop residue delivery would follow specific seasons in which the 

crop was grown. As noted above, the four-fold or greater increase in volume occupied by 

biomass relative to coal means that the necessary additional storage space could be large.

However, if pre-prepared or condensed biomass fuels such as pelletized or torrefied biomass is 

used, some of these concerns may not applybe lessened, recognizing that such pre-prepaerations 

of the feedstock couldwill entail additional costs. Stored biomass can be at even greater risk of 

                                                            

23 For example, one unit at Schiller Station (NH) was converted in 2006 to burn biomass exclusively.  See:

https://www.psnh.com/PlantsTerritory/Schiller‐Station.aspx. 24 Biomass Energy Data Book‐ Edition 4, October 2012, DOE‐EERE‐ORNL,  http://cta.ornl.gov/bedb/index.shtml

Comment [A16]: For example, Schiller, NH

facility.

EPA:  Thank you for the comment. Partial

Bibliography, includes references to extensive tests.  

Also, see new footnote 23.

Comment [A17]: A commenter suggest that EPA

could do the following here:

elaborate on the challenges of preparing biomass

fuel for cofiring in pulverized systems (i.e. in

reducing biomass fuel particle size to close to

pulverized coal size).  

consider the influence of biomass on the potential

markets for flyash in concrete.  

mention the need for fuel drying systems for many

types of biomass.  

EPA:  Thank you for the comment. EPA believes that

the current description of factors to consider in

biomass combustion is sufficiently detailed to

support the conclusions presented herein.

Comment [A18]: There is extensive effort and

additional research being done to mitigate these

concerns through pre‐preparation of the feedstock.

Wood pellets and low rank coal may have

approximately the same energy density, and

depending on the cost structure of the feedstock

supply chain, the reduced transportation and

storage benefits could outweigh the preparation

costs, particularly for cases like torrefaction that

may produce economic co‐products.  

EPA:  Thank you for the comment and the edit. We

accept the edit, with the slight modifications shown.
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spontaneous combustion than stored coal; this may limit the safe height of biomass piles and 

further increase storage area requirements.25

The volumetric differences alone can have other unexpected consequences. For this analysis, 

experienced EPA engineering staff estimated that a 500 MW baseload coal plant co-firing 10% 

biomass and receiving biomass deliveries 10 hours per day and 5 days per week would require a 

20-ton truck delivery to the plant every 10 minutes, in addition to the ongoing coal deliveries. 

Limiting traffic issues may arise in some situations. Also, because of the low energy density of 

biomass and its relatively higher transportation cost per unit of delivered energy, it may only be 

economically viable to transport biomass a limited distance from where it is grown. This could 

limit the both the percentage of biomass co-firing in a single boiler and the maximum MW 

output from biomass at a single site. New technologies under development, such as torrefaction 

of biomass, but could mitigate some of these transportation, storage and energy content concerns, 

but are not yet commercially available.

The relatively higher moisture content and lower heat content of biomass reduces boiler 

efficiency, and typically requires a derating in unit generation at very high co-firing percentages 

as furnace volume and boiler fan capacities become inadequate. 

For all of the above reasons, the EPA assumed for this analysis that coal-steam EGU boilers will 

generally only co-fire with biomass to a limited degree. While the actual level at which any 

plant can co-fire with biomass is highly site-specific, this analysis adopts the assumption used in 

EPA’s fleet wide IPM modeling of the electric power sector: a reasonable average limit on 

biomass co-firing is up to 10% on any single boiler, not to exceed 50 MW total biomass powered 

output at an individual plant site (which aligns with the magnitude of some of the larger such 

entities currently in the U.S.). This amount of co-firing has been used as representative practical 

limit in other studies as well.26 But EPA notes that higher percentages of co-firing and at higher 

levels may be available in other cases as have been noted in many other studies. 

                                                            

25 Properties of Wood Waste Stored for Energy Production, Purdue University, 2011,

http://www.extension.purdue.edu/extmedia/ID/ID‐421‐W.pdf   26 The Potential for Biomass Cofiring in Maryland, Maryland Department of Natural Resources, March 2006,

http://esm.versar.com/pprp/bibliography/PPES_06_02/PPES_06_02.pdf

Comment [A19]: The use of sawmill residues,

when avaialabe, could provide a high quality

feedstock at potentially lower moisture content (i.e.

planer shavings). A high quality feedstock could

justify greater transportation distances (perhaps

75+ miles)

EPA:  Thank you for the comment.

Comment [A20]: EPA:  Thank you for the edit.

We will include it as slightly modified.

Comment [A21]: : Might mention, for

perspective, that 50MW is in line with some of the

largest standalone biomass powered electrical

facilities in the US. Agreed that 50 MW upper limit is

realistic. However if EU cofiring practices were

adopted in the US, this could exceed 100MW at an

individual site.

EPA:  Thank you for the comment.
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For example, Europe’s 2nd biggest coal-fired power plant is being converted to burn wood 

pellets imported from the United States and Canada to power half of the plants 4 gigawatt 

capacity. The 700 million Euro project will “transform Drax from the largest carbon emitter by 

site in UK to one of the largest clean-energy plants in the world.” (Financial Times, August 14, 

2013). Similarly, in Canada the potential to reduce coal generation through co-firing is assumed 

to be 20 to 30%, much higher than IPM’s assumptions (See Canadian Clean Power Coalition 

http://www.canadiancleanpowercoalition.com/files/7813/2621/8340/Append ix%20C.pdf). As 

such EPA specifically requests for comment on data to support higher levels of biomass co-firing 

in the EPA’s IPM model and for this rulemaking. 

Costs and Performance Impacts of Retrofitted Biomass Co-firing 

For this analysis the EPA adopted capital and O&M costs, and performance impacts for 

retrofitted biomass co-firing capability that are approximately representative of EPA assumptions 

used in its IPM modeling and discussed in the documentation for IPM v.5.13.27

EPA estimated that the capital cost to install 50 MW of biomass co-firing capability would be at 

least $10 million.28 As applied to a 500 MW coal unit, the minimum cost of this 10% co-firing 

capability would then be $20/kW. Fixed O&M cost was estimated by EPA engineering staff to 

be 10% greater than with coal alone, and variable O&M cost was estimated to remain 

unchanged. 

The heat rate impact (Btu/kWh) of 10% biomass co-firing as estimated by EPA engineering staff 

for this analysis was an increase of slightly more than 1% compared to coal alone. At low 

biomass cofiring rates, this factor slightly affects calculated biomass fuel consumption and any 

associated CO2 emission from biomass. 

Cost of Fuel 

For this analysis, the EPA uses a delivered biomass cost of $4/MMBtu, representative of 

delivered woody crops grown specifically for energy-generating combustion,29 and roughly 50% 

                                                            

27 See Sec 5.3, pg 5‐19 at: http://www.epa.gov/airmarkets/progsregs/epa‐ipm/docs/v513/Chapter_5.pdf 28 Generally consistent with EPA assumptions in IPM modeling; also see the following source using the same

retrofit capital cost assumption: Cofiring Biomass and Coal for Fossil Fuel Reduction and Other Benefits – Status of

North American Facilities in 2010, USDA, August 2012, http://www.fs.fed.us/pnw/pubs/pnw_gtr867.pdf 29 Average biomass price as projected by EPA modeling in IPMv5.13 Base Case

Comment [A22]: EPA:  We respectfully decline

the suggested edits with regard to the Drax facility

and the Canadian business coalition’s assumptions

of biomass co‐firing potential with respect to power

sector modeling.  First of all, EPA believes that

making reference to the Drax facility would require

a fuller discussion of differences in regulatory and

economic variables affecting US and European

facilities that would unnecessarily complicate the

evaluation at hand.  Secondly, while this evaluation

“borrows” a technical framework for analysis from

IPM assumptions about the potential extent of

biomass co‐firing, the analysis is focused on the cost

and emission impacts of generally increasing

biomass combustion.  The drivers of that evaluation

and its conclusions described in this document are

not sensitive to the level of co‐firing potential

assumed; furthermore, this document only cites

IPM assumptions as a reference and starting point

for this technical evaluation, not in order to open a

discussion of power sector modeling assumptions

(which are not germane to this document’s

conclusions given that EPA is not relying on

modeling projections to make this evaluation or

reach these conclusions).

Comment [A23]: Should this number be

$200/kW? ($200/kW) x (1,000 kW/MW) x (50 MW)

=  $10 million

EPA:  At $10 million, $200/kW would be right for the

50,000 kW of biomass capacity. The $20/kW value is

applied to the entire 500 MW of unit capacity. They

are equivalent in this case.

Comment [A24]: There are some assumptions in

this section that state “estimated by EPA staff”.

Suggest providing further support if possible.

EPA:  Thank you for the comment.  This TSD includes

discussion of many routine power plant design,

operation, and engineering economics issues that

are generally neither speculative nor controversial

among those familiar with the subject matter. EPA

believes these estimates are adequately supported

by the document as written.   

Comment [A25]: This is intriguing, and it might

be worthwhile providing more detail about this

(perhaps in a separate Table)‐ especially given the

emphasis on heat rates in chapter 2.

EPA:  Thank you for the comment.  We believe the

current level of detail suffices.
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greater than IPM projected 2020 average delivered coal costs.30 This analysis also considers a 

sensitivity scenario assuming a higher $6/MMBtu biomass price. 

The EPA recognizes that the cost of biomass is highly site-specific, and in some cases could be 

largely comprised of collection and transportation cost (as is the case for opportunity fuels with 

little to no other market value). The transportation component depends primarily on the distance 

that biomass needs to be transported. For example, the EPA engineering staff estimate that for a 

one-way distance of 50 miles with a 20-ton semi-trailer truck, transportation costs could be $10-

20/ton. For biomass at a total delivered price of $4/MMBtu with an indicative heating value of 

5,000 Btu/lb (higher heating value (HHV) basis), transportation cost in this example case could 

account for 25-50 percent of the total delivered biomass cost. In any case, it is the total delivered 

price of biomass on a $/MMBtu basis that will primarily determine the economic feasibility of 

biomass co-firing. 

Emission Reduction Potential 

The CO2 reduction potential of biomass co-firing is directly related to the amount and type of 

biomass co-fired and is due to the difference in heating value, moisture content and 

hydrogen/carbon ratios31 for a selected biomass fuel compared to the particular coal it replaces. 

The types of biomass typically available to EGUs in the United States include woody-based 

feedstocks such as wood chips, forest industry byproducts, and to a lesser degree agricultural 

crop residues, as well as emerging dedicated energy crops such as switchgrass and short-rotation 

woody crops.32 In general, when comparing coal-only versus co-firing coal with biomass, cofiring may result in either an increase or decrease in the stack CO2 emission rate. The extent to 

which the use of biomass in lieu of fossil fuels to biogenic emissions can reduce fossil 

contributes to net emissions to the atmosphere is being considered in EPA’s current study on the 

framework for accounting for biogenic emissions accounting. See preamble Section VIII.G. 

European studies show that biomass can significantly displace fossil emissions in a co-fired 

                                                            

30 EIA, Electric Power Annual 2012 – Electricity (Table 7.4)

http://www.eia.gov/electricity/annual/html/epa_07_04.html 31 IFRF Combustion Handbook, Combustion File No. 23, What is Biomass? (Van Krevelen Diagram),

http://www.handbook.ifrf.net/handbook/cf.html?id=23 32 Biomass Combined Heat and Power Catalog of Technologies, U.S. EPA, September 2007,  

http://www.epa.gov/chp/documents/biomass_chp_catalog.pdf

Comment [A26]: It might be worth

distinguishing transportation costs for plantation

grown biomass vs. forest harvesting residues vs.

wood products manufacturing residues.

EPA:  Thank you for the comment.  We believe the

current level of detail suffices.

Comment [A28]: Shouldn’t this at least include a

discussion of the potential net/lifecycle emissions

benefits of utilizing biomass.

EPA:  This discussion is not necessary since this TSD

concludes that, even if CO2 emissions from biomass

are not counted, cost‐effective reductions of CO2

would not be available on a U.S. national basis from

widespread adoption of biomass co‐firing.

Comment [A27]: However, isn’t it safe to say

that most studies indicate a decrease in CO2

emissions with increasing biomass amounts.  

Example‐ Mann and Spath 2001.

http://link.springer.com/article/10.1007%2Fs10098

0100109

EPA:  EPA is adding language which directs the

reader to the preamble discussion of the biogenic

accounting framework, where comment solicitation

is more appropriate than in a TSD.  This document is

not intended to include any evaluation of biomass

accounting studies
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16 

plant. EPA specifically requests for comment on the degree to which biomass can be co-fired to 

reduce fossil emissions in the United States.

Cost of Reductions and Cost Effectiveness 

In order to evaluate cost-effectiveness of potential reductions, the EPA first estimated the cost of 

avoided coal CO2 emissions in a hypothetical scenario where biomass CO2 emissions are not 

included in total stack CO2 emissions (in effect, biogenic CO2 emissions are subtracted from 

total CO2 emissions measured at the stack). The estimated results presented below are based on 

a reasonably representative case using a baseload bituminous coal-fired boiler with a net heat 

rate of 10,340 btu/kWh that shifts from 100% bituminous coal to 90% coal and 10% biomass 

(assuming fuel prices of $2.62/MMBtu for coal in 2020 as projected in IPMv5.13 Base Case and 

$4/MMBtu for biomass as explained above). When biogenic stack emissions are not counted as 

part of total emissions, the cost of avoided CO2 for a “typical” baseload coal boiler co-firing 10% 

biomass is $30/tonne. This estimated cost of avoided coal CO2 emissions would increase if some 

portion of the biogenic CO2 emissions from the co-fired biomass were included. At higher 

delivered fuel price differentials, the cost of avoided coal CO2 emissions would increase (for 

example, at a biomass price of $6/MMBtu, cost of avoided CO2 is $80/tonne if CO2 emissions 

from biomass are not counted). Similarly, the costs of avoided coal CO2 emissions would 

decrease at lower fuel price differentials. delivered biomass prices associated with waste and 

residue materials, at higher coal prices than assumed here, or if other means of GHG reductions 

were less available. 

Conclusion 

Replacing some coal with low levels of biomass co-firing may result in stack CO2 emission 

increases.33 Even if biogenic CO2 emissions are not counted as part of stack emissions, biomass 

co-firing is a relatively costly approach to CO2 reductions at existing coal steam boilers when 

compared to other measures such as heat rate improvements and re-dispatch of generation supply 

to other existing capacity with lower CO2 emission rates. 

                                                            

33 Depending on biogenic feedstocks used and whether or not an assessment system is applied that evaluates

biogenic CO2 emissions from the stack in relation to the terrestrial carbon cycling associated with the production

and use of that biogenic feedstock.

Formatted: Subscript

Comment [A29]: EPA: Thank you for the

suggested edit, which we have adopted with slight

revisions.

Comment [A30]: EPA:  Thank you for the

suggested edits.  The purpose of this chapter is to

assess the cost‐effectiveness of fuel switching at a

national level for the purpose of setting emissions

goals consistently in each state, and this paragraph

as originally written appropriately summarizes EPA’s

finding.  EPA directs the commenter to the following

paragraph, which highlights the ability of some units

in some states to cost‐effectively co‐fire with

biomass.
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The EPA is considering cost-effectiveness at a national level for the purpose of setting emissions 

goals consistently in each state. While this analysis concludes that cost-effective reductions of 

CO2 are not available on a national basis from widespread adoption of biomass co-firing, it does 

not preclude the potential for individual EGUs to utilize co-firing as a way to reduce overall CO2

emissions, nor does it preclude states from factoring in that unit-level potential into the design of 

state plans for compliance with the 111(d) standard.34 

Partial Bibliography for Technical Feasibility of Biomass Co-firing 

(a) Briggs, J. and J. M. Adams, Biomass Combustion Options for Steam Generation, Presented at 

Power-Gen 97, Dallas, TX, December 9 – 11, 1997. 

(b) Grusha, J and S. Woldehanna, K. McCarthy, and G. Heinz, Long Term Results from the First 

US Low NOx Conversion of a Tangential Lignite Fired Unit, presented at 24th International 

Technical Conference on Coal & Fuel Systems, Clearwater, FL., March 8 – 11, 1999. 

(c) EPRI, Biomass Co-firing: Field Test Results: Summary of Results of the Bailly and Seward 

Demonstrations, Palo Alto, CA, supported by U.S. Department of Energy Division of Energy 

Efficiency and Renewable Energy, Washington D.C.; U.S. Department of Energy Division 

Federal Energy Technology Center, Pittsburgh PA; Northern Indiana Public Service Company, 

Merrillville, IN; and GPU Generation, Inc., Johnstown, PA: 1999. TR-113903. 

(d) Laux S., J. Grusha, and D. Tillman, Co-firing of Biomass and Opportunity Fuels in Low NOx 

Burners, PowerGen 2000 - Orlando, FL 

(e) Tillman, D. A., Co-firing Biomass for Greenhouse Gas Mitigation, presented at Power-Gen 

99, New Orleans, LA, November 30 – December 1, 1999. 

(f) Tillman, D. A. and P. Hus, Blending Opportunity Fuels with Coal for Efficiency and 

Environmental Benefit, presented at 25th International Technical Conference on Coal Utilization 

& Fuel Systems, Clearwater, FL., March 6 – 9, 2000 

(g) Tillman D A, Harding N S (2004) Fuels of opportunity: characteristics and uses in 

combustion systems. Elsevier, Oxford, UK 

                                                            

34 EPA notes that states will need to consider any future EPA finding regarding an assessment framework that

considers carbon fluxes on the biogenic feedstock production landscape applied when evaluating net stack CO2

emissions from biomass co‐firing.

Comment [A31]: Suggest the following 2

references: Spath, P.L.; Mann, M.K.  

Life Cycle Assessment of a Natural Gas Combined‐

Cycle Power Generation System  

http://www.nrel.gov/docs/fy00osti/27715.pdf

Mann, M.K.; Spath, P.L.  

A Life Cycle Assessment of biomass cofiring in a coal

fired power plant.  

https://www.bioenergykdf.net/sites/default/files/z

pdfzholderz/NREL_Dat a/KC_091102094512.pdf  

EPA:  we do not believe "lifecycle" assessments are

necessary to include here because the rule is

addressing EGU emissions, not lifecycle emissions.
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(k) http://esm.versar.com/pprp/bibliography/PPES_06_02/PPES_06_02.pdf 

(h) Tillman D, Conn R, Duong D (2010) Coal characteristics and biomass cofiring in pulverized 

coal boilers. In: Electric Power, Baltimore, MD, USA, 18 - 20 May, 2010 

(i) Renewable and Alternative Energy Fact Sheet – Co-firing Biomass with Coal, Pennsylvania 

State University, 2010, http://pubs.cas.psu.edu/FreePubs/PDFs/ub044.pdf 

(j) Fernando R, Cofiring High Ratios of Biomass with Coal, IEA Clean Coal Centre (CCC/194), 

January 2012 

(k) DOE-EERE-ORNL, Biomass Energy Data Book- Edition 4, October 2012, 

http://cta.ornl.gov/bedb/index.shtml