## 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

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

DRAFT/Deliberative Document - FOIA Exempt

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

<< GHG Abatement Measures TSD-Chapter 3_04-14-14_InteragencyCommentsUnderEO12866_

EPA Edits Responses_5-15-14.docx >>

<< GHG Abatement Measures TSD-Chapter 6_04-10-14_InteragencyCommentsUnderEO12866_

5-14-14.docx >>

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1 

### GHG Abatement Measures Technical Support Document

Chapter 3: CO 2 

### 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 Formatted: Font:

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### Overview

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

lowering the carbon dioxide (CO 2 

### ) 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 oppor tunities 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 CO 2 

### 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 elec tricity 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 auth orities 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 SO 2 

### and NO

x 

### when scheduling unit dispatch, in response to costs and

1 Energy Policy Act of 2005

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

between supply, demand, and generation within a balanci ng 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 operat ors in 10 states partic ipating in the Regional

Greenhouse Gas Initiative have several years of experience with factoring CO 2 

### 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 principl e 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 Or ganizations (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 possi ble, 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 in to electricity markets such that their variable

costs are covered. For fossil fuel-fired electric ge nerating 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 vari able 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 a nd maintenance, and costs of

operating a pollution control and/or emission allowance charges. Formatted: Heading 1

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

“curve.” 5

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### Balancing Authorities

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

generation, transmission, and distribution infrastru cture, 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 lo west 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 po wer 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 an cillary 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, en sure 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 pa rties 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

. Formatted: Line spacing: 1.5 lines

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 re al-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 utili ty based on its own sche duling and pu rchasing

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 refe rs to a large interconnected electrical system

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

system operators continuously an alyze real-time and forecasted lo ad 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 Am erican 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 CO 2 

### emission rates 9 

### 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 – 9 0726 lbs/MWh

Coal- and oil/gas-fired boilers are consider ably 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

CO 2 

### emission reductions.

The lower emission rate of NGCC conveys th e 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

CO 2 

### 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 8,7 84 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 availab ility factors may reach as high as 92%. 11

8 http://www.nerc.com/

9 Emission rates in this document are shown on a net gene ration 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

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### If the existing NGCC fleet was already opera ting 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 oper ating data to determine capacity factors.

Redispatch for GHG abatement purposes woul d 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 us ed 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 f actor). 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 act ual 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 po tential for re-dispatch from higher CO 2 

### 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 reductio n 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 assu med 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 genera tion/name plate value to a ne t 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 fact or ceilings for a stat e’s NGCC fleet as part of BSER, the EPA

considered historical data and modeling proj ections 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 ach ieve high availability factors.

Table 3-1: Existing NGCC Capacity, by Age 15



### 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%CapacityFactor

% 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%CapacityFactor

% of Units 

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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 heav ily 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 NGCC s 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 defi ned as December, January, and February. Estimates are

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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 201 2. 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 po sition of gas-fired units relative to coal-fired

units. As a result, operators have shifted signifi cant quantities of generatio n from coal units to

NGCCs, absent any federal CO 2 

### 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 th e 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 a ssessment of the relative economics is informative

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

CO 2.



### The potential for redispatch from CO 2 

### intensive sources to less CO 2 

### intensive sources is

evidenced in historical data. EIA form 860 an d 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 in cludes 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 th e quick re-dispatch in response to market or

economic drivers.

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

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

in 2011 and $2.76/mmBtu in 2012. This $1. 24/mmBtu creates an ad ditional 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 CO 2 

### price signal would create. 21



### This historical data also shows a sharp increas e 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 gene ration. 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 contin ued and increasing redispatch to NGCC generating technology. 22



### Table 3-2: 2011 and 2012 Gas and Coal Generation 23



### Year NGCC

Name Plate

Capacity

(GW) NGCC Heat

Input for

Electricity

(TBtu) NGCC Net

Generation

(TWh) NGCC

Capacity

Factor H enry H ub

Natural Gas

Price

($/mmBtu Coal Net

Generation

(TWh)

2011 23 95 5,912 796 3 89 % $4.00 1,719

2012 24 42 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 ~ 90 th



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

and the cost-effectiveness of high NGCC utilizati on 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, hi storical 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

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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). Formatted ... [1]

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### recoverable natural gas resources will be substa ntially 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 pr ojects 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 natu ral 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)

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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 th e 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 dema nd 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 hist orical 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

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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 report ed 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 us e, 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/issu e-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/is sue-2/features/higher-availability-o f-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 2011 38 

### and resulted in a national average

capacity factor for NGCC of 4 5.89 % 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 constr aints 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 tec hnical 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 constraint s 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 tr ansmission and natural gas pipelin e 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 tec hnical 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 deliver ability 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 deliverab ility 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 in creases in pipeline deliverab ility, the EPA analyzed the

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

capacity for inflows and outflows by state. Howeve r, 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

Area 47

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 Foundati on, 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 Administrati on, 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 complian ce 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 an d 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 project ions) 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 Formatted: Space After: 10 pt, Line spacing:

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### the marginal value of gas transmission as a functi on 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 ev aluate the technical f easibility 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 CO 2



### emissions through re-dispatch. As part of this ef fort, 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 restrictiv e 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 in centivizing re-dispatch from more carbon-intensive to less carbonintensive EGUs, the EPA introduced two addi tional 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 capac ity expansion, electricity dispatch, and emission control strategies while

meeting energy demand and environmental, transmission, di spatch, 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 boundari es because least-cost supply must be balanced with

demand in real time over grid interconnects which span mul tiple 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 CO 2 

### 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 CO 2



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



### 2. Generation constraints that maintain the sum of state-level generation in the Base Case 51



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

boilers greater than 25 MW and with a CO 2 

### 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 capac ity. Utilizing IPM to conduct this analysis

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

reliability constraints, fuel market impacts, na tural gas transmission and distribution networks,

electric power transmission cons traints, 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 CO 2 

### 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 CO 2



### emissions (compared to the base case).

50 The addition of CO 2 costs represents a simple analytic a pproach to estimating the cost-effective CO 2 reductions

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

implementation, states would be free to select any polic y 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 – wh ich is distinct from the $/tonne CO 2 

### cost imposed in

these analytic scenarios on affected coal stea m, 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 60AverageCapacityFactor

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 60AverageCapacityFactor

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, a nd 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

CO 2 

### Cost Level

Imposed National Average

NGCC

Capacity Factor Average Cost

($/tonne) 2020 Power Sector CO 2



### 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 compliance 52 

### 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 CO 2 

### 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 CO 2 

### charge was applied

uniformly to all states in or der to quantify the ultimate am ount of in-state re-dispatch

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

low levels of CO 2 

### charges produce cost-effective re-dispatch opportunities relative to the

Base Case in almost all states. However, as the CO 2 

### 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 slop e of the best-fit line in Figure 3- 65 . A uniform

application of the same rising CO 2 

### charge in all states produces an outcome for many

states where the additional CO 2 

### 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 cost s imposed by these higher CO 2 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 th e 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 CO 2 

### emission reductions at an identical CO 2 

### charge

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

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

cost-effectiveness of re -dispatch potential.

To evaluate how EGU owners and grid operat ors 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 speci fied operating and reliability constraints for the

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

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

NGCC generation. Collectively, states must ach ieve 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 opportuniti es, comparison to the business-as-usual case

indicates that the average cost of the CO 2 

### reductions achieved ranged from [$xx] to [$xx] per

metric ton of CO 2



### . 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 CO 2 

### reductions

achieved over the 2020-2029 period was $21, $30, and $40 per metric ton of CO 2 

### , respectively.

However, we also note that the costs just desc ribed 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 utiliza tion 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, cont rary 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 ga s 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 grea ter re-dispatch flexibility, the cost of achieving

the quantity of CO 2 

### 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 Formatted: Subscript

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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 CO 2 

### 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 CO 2



### 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 exampl e, 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 ga s price volatility. For exam ple, 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 wholesal e electricity price

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

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

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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

CO 2 

### , 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%

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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 CO 2 

### emissions rate (lbs/MWh) in these boilers. The CO 2 

### 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 (H 2 

### O) than coal, but far less CO 2



### .

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 ex isting coal boiler, for reasons th at 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 CO 2 

### 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 tr ansition typically requires at least some plant

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

later in this chapter.

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2 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 pipeli ne 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 chan ges affecting heat transfer surfaces; the need

for sizing of flue gas recirculation fans; and ope rational changes to sootbl owers, spray flows, air

heaters, and emission controls.

Whether co-firing with coal or switching complete ly 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 he at lost up the stack in stead of being directed

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

modifications, some boilers may in cur 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 over all 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 SO 2



### 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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3 gas as a startup fuel, or are located at facilities wi th onsite gas-fired generators. These boilers are

likely able to co-fire to some degr ee with gas (at least 10% total output 1 

### ) 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 quanti ties sufficient for sustained utilization on site.

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

continue operating without increasing its CO 2 

### emissions rate (since it would likely need to

substitute more CO 2 

### -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 follows 2 

### :

$/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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4 $/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 com bustion we assume that a 50-mile gas pipeline 3 

### 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 rate 6 

### 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/air markets/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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5 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 outpu t 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 CO 2 

### 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 CO 2 

### 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. CO 2 

### Rates at Various Levels of Natural Gas Co-Firing

Case Heat Rate

(Btu/kWh) CO 2 

### Rate

(lbs/MWh net) Reduction in CO 2 

### 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 CO 2 

### emissions, natural gas co-firing at a coal-fired steam EGU will

generally also reduce criteria air pollution. Reducing CO 2 

### 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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6 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 PM 2.5 

### -related human health co-benefits of SO 2 

### , NO X 

### , and

direct-PM 2.5 

### emission reductions attributable to a ra nge of natural gas co-firing levels at an

illustrative coal steam unit burn ing bituminous coal in 2020. 11 

### The estimated monetized cobenefits do not include climate benefits or health effects from direct exposure to NO 2 

### , SO 2 

### , and

HAP; ecosystem effects; or visibility impairment. Only the unit-level emissions of SO 2 

### , NO X 

### and

direct-PM 2.5 

### are considered in this illustrative ex ercise. 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 Leve ls of Co-Firing, based on Illustrative Unit

(lbs/MWh net)

10%

Gas 100%

Gas

SO 2 0.3 3.1

NO X 0.2 2.04

PM 2.5 0.02 0.2



### To estimate human health co-benefits for this illustrative coal steam unit, the EPA used PM 2.5



### -

related benefit-per-ton estimates for SO 2 

### , NO X 

### , and direct-PM 2.5 

### emission reductions described

in detail in Chapter 5 of the RIA for this proposa l. 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 SO 2 

### , NO X 

### , and direct-PM 2.5 

### emissions by the PM 2.5 

### -related benefit per-ton estimates,

and add those values to get a measure of 2020 benefits. Table 6-3 shows the PM 2.5 

### -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 technol ogies 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

PM 2.5 and PM 2.5 precursors, SO 2 and NO X

. It is important to note that the monetized health co

‐ benefits do not include reduced health effects

from ozone or direct exposure to NO 2 , SO 2 , 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 huma n 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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8 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 CO 2 

### 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 $/tonne 14 

### cost of avoided CO 2 

### 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 pipeli ne 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 CO 2 

### 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 CO 2 

### and CO 2 

### 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 CO 2 

### ($/tonne) Change in CO 2 

### 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 CO 2 

### 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 CO 2 

### 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 CO 2 

### emission rates. Moreover, this

analysis shows that coal-to-gas conversion of an ex isting 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 discusse d above with a new NGCC facility would

reduce the net CO 2 

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

of avoided CO 2 

### under the base case projected gas price and about $81/tonne of avoided CO 2 

### 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 na tional level for the purpose of setting emissions

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

CO 2 

### are not available on a national basis from wi despread adoption of natural gas co-firing, it

does not preclude the potential for individual E GUs to utilize co-firing as a way to reduce CO 2



### 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 un its 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

CO 2 

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

support document, the physical CO 2 

### emissions rate at the boiler st ack 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 CO 2 

### 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 re ducing the physical CO 2 

### emission rate based only on the CO 2 

### coming

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

feasible as a means of reducing the coal-based CO 2 

### 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 others 19 

### and others , including a n earlier study by the State of Maryland 20 

### that

concluded as follows:

“Due to the higher cost of biomass fuels wh en 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 CO 2 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/biblio graphy/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 CO 2 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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11 Based on the basic analysis of the cost effectiv eness of biomass energy substitution in reducing

the physical CO 2 

### emission rate based only on the CO 2 

### 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 CO 2 

### (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 gi ven the delivered cost of available biomass

versus the cost of coal. However, the use of co-fi ring 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 s ector (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 CO 2 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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12 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 heati ng 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 n ecessary 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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13 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 situati ons. 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 tr ansportation, 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 un it 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-speci fic, 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/biblio graphy/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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14 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 “transfo rm 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 capab ility that are approximately repr esentative 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 CO 2 

### 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/air markets/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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15 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 hi ghly 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 transporta tion component depends primarily on the distance

that biomass needs to be transported. For exampl e, 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 biom ass 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 CO 2 

### reduction potential of biomass co-firing is di rectly related to the amount and type of

biomass co-fired and is due to the differen ce in heating value, moisture content and

hydrogen/carbon ratios 31 

### 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 en ergy 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 CO 2 

### 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 emission s accounting. See preamble Section VIII.G.

European studies show that biomass can signifi cantly displace fossil emissions in a co-fired

30 EIA, Electric Power Annual 2012

– Electricity (Table 7.4)

http://www.eia.gov/electricit y/annual/html/epa_07_04.html

31 IFRF Combustion Handbook, Combustion File No. 23, What is Biomass? (Van Krevelen Diagram),

http://www.handbook.ifrf.ne t/handbook/cf.html?id=23

32 Biomass Combined Heat and Power Catalog of Technologies, U.S. EPA, September 2007,

http://www.epa.gov/chp/docume nts/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 CO 2 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 potentia l reductions, the EPA first estimated the cost of

avoided coal CO 2 

### emissions in a hypothetical scenario where biomass CO 2 

### emissions are not

included in total stack CO 2 

### emissions (in effect, biogenic CO 2 

### emissions are subtracted from

total CO 2 

### 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 CO 2 

### for a “typical” baseload coal boiler co-firing 10%

biomass is $30/tonne. This estimated cost of avoided coal CO 2 

### emissions would increase if some

portion of the biogenic CO 2 

### emissions from the co-fired biomass were included. At higher

delivered fuel price differentials, the cost of avoided coal CO 2 

### emissions would increase (for

example, at a biomass price of $6/MMBtu, cost of avoided CO 2 

### is $80/tonne if CO 2 

### emissions

from biomass are not counted). Similarly, the costs of avoided coal CO 2 

### emissions would

decrease at lower fuel price differentials. deliver ed 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 CO 2 

### emission

increases. 33 

### Even if biogenic CO 2 

### emissions are not counted as pa rt of stack emissions, biomass

co-firing is a relatively costly approach to CO 2 

### 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 CO 2 

### emission rates.

33 Depending on biogenic feedstocks used and whether or not an assessment system is applied that evaluates

biogenic CO 2 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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17 The EPA is considering cost-effectiveness at a na tional level for the purpose of setting emissions

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

CO 2 

### are not available on a national basis from wide spread adoption of biomass co-firing, it does

not preclude the potential for individual EGUs to utilize co-firing as a way to reduce overall CO 2



### emissions, nor does it preclude states from factoring in that unit-level poten tial into the design of

state plans for compliance with the 111(d) standard. 34



### Partial Bibliography fo r Technical Feasibility of Biomass Co-firing

(a) Briggs, J. and J. M. Adams, Biomass Combus tion 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 System s, 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-firi ng of Biomass and Opportunity Fuels in Low NOx

Burners, PowerGen 2000 - Orlando, FL

(e) Tillman, D. A., Co-firing Biomass for Gr eenhouse Gas Mitigation, presented at Power-Gen

99, New Orleans, LA, November 30 – December 1, 1999.

(f) Tillman, D. A. and P. Hus, Blending Oppo rtunity 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 CO 2

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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18 (k) http://esm.versar.com/pprp/bib liography/PPES_06_ 02/PPES_06_02.pdf

(h) Tillman D, Conn R, Duong D (2010) Coal char acteristics 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/Free Pubs/PDFs/ub044.pdf

(j) Fernando R, Cofiring High Ratios of Bioma ss with Coal, IEA Clean Coal Centre (CCC/194),

January 2012

(k) DOE-EERE-ORNL, Biomass Energy Da ta Book- Edition 4, October 2012,

http://cta.ornl.gov/bedb/index.shtml