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EPA POWER PLANT REGULATIONS: 

IS THE TECHNOLOGY READY? 

JOINT HEARING 

BEFORE THE

SUBCOMMITTEE ON ENERGY & 

SUBCOMMITTEE ON ENVIRONMENT 

COMMITTEE ON SCIENCE, SPACE, AND 

TECHNOLOGY 

HOUSE OF REPRESENTATIVES 

ONE HUNDRED THIRTEENTH CONGRESS 

FIRST SESSION 

October 29, 2013 

Serial No. 113–51 

Printed for the use of the Committee on Science, Space, and Technology 

( 

Available via the World Wide Web: http://science.house.gov 
(II) 

COMMITTEE ON SCIENCE, SPACE, AND TECHNOLOGY 

HON. LAMAR S. SMITH, Texas, Chair 

DANA ROHRABACHER, California 

RALPH M. HALL, Texas 

F. JAMES SENSENBRENNER, JR., 

Wisconsin 

FRANK D. LUCAS, Oklahoma 

RANDY NEUGEBAUER, Texas 

MICHAEL T. MCCAUL, Texas 

PAUL C. BROUN, Georgia 

STEVEN M. PALAZZO, Mississippi 

MO BROOKS, Alabama 

RANDY HULTGREN, Illinois 

LARRY BUCSHON, Indiana 

STEVE STOCKMAN, Texas 

BILL POSEY, Florida 

CYNTHIA LUMMIS, Wyoming 

DAVID SCHWEIKERT, Arizona 

THOMAS MASSIE, Kentucky 

KEVIN CRAMER, North Dakota 

JIM BRIDENSTINE, Oklahoma 

RANDY WEBER, Texas 

CHRIS STEWART, Utah 

VACANCY 

EDDIE BERNICE JOHNSON, Texas 

ZOE LOFGREN, California 

DANIEL LIPINSKI, Illinois 

DONNA F. EDWARDS, Maryland 

FREDERICA S. WILSON, Florida 

SUZANNE BONAMICI, Oregon 

ERIC SWALWELL, California 

DAN MAFFEI, New York 

ALAN GRAYSON, Florida 

JOSEPH KENNEDY III, Massachusetts 

SCOTT PETERS, California 

DEREK KILMER, Washington 

AMI BERA, California 

ELIZABETH ESTY, Connecticut 

MARC VEASEY, Texas 

JULIA BROWNLEY, California 

MARK TAKANO, California 

ROBIN KELLY, Illinois 

SUBCOMMITTEE ON ENVIRONMENT

HON. CHRIS STEWART, Utah, Chair 

JIM BRIDENSTINE, Oklahoma 

F. JAMES SENSENBRENNER, JR., 

Wisconsin 

DANA ROHRABACHER, California 

RANDY NEUGEBAUER, Texas 

PAUL C. BROUN, Georgia 

RANDY WEBER, Texas 

LAMAR S. SMITH, Texas 

SUZANNE BONAMICI, Oregon 

JULIA BROWNLEY, California 

DONNA F. EDWARDS, Maryland 

MARK TAKANO, California 

ALAN GRAYSON, Florida 

EDDIE BERNICE JOHNSON, Texas 

SUBCOMMITTEE ON ENERGY

HON. CYNTHIA LUMMIS, Wyoming, Chair 

RALPH M. HALL, Texas 

FRANK D. LUCAS, Oklahoma 

RANDY NEUGEBAUER, Texas 

MICHAEL T. MCCAUL, Texas 

RANDY HULTGREN, Illinois 

THOMAS MASSIE, Kentucky 

KEVIN CRAMER, North Dakota 

RANDY WEBER, Texas 

LAMAR S. SMITH, Texas 

ERIC SWALWELL, California 

ALAN GRAYSON, Florida 

JOSEPH KENNEDY III, Massachusetts 

MARC VEASEY, Texas 

MARK TAKANO, California 

ZOE LOFGREN, California 

DANIEL LIPINSKI, Illinois 

EDDIE BERNICE JOHNSON, Texas 
(III) 

C O N T E N T S 

October 29, 2013 

Page 

Witness List ............................................................................................................. 2 

Hearing Charter ...................................................................................................... 3 

Opening Statements 

Statement by Representative Chris Stewart, Chairman, Subcommittee on 

Environment, Committee on Science, Space, and Technology, U.S. House 

of Representatives ................................................................................................ 8 

Written Statement ............................................................................................ 9 

Statement by Representative Suzanne Bonamici, Ranking Minority Member, 

Subcommittee on Environment, Committee on Science, Space, and Technology, U.S. House of Representatives ............................................................... 13 

Written Statement ............................................................................................ 14 

Statement by Representative Cynthia Lummis, Chairwoman, Subcommittee 

on Energy, Committee on Science, Space, and Technology, U.S. House of 

Representatives .................................................................................................... 15 

Written Statement ............................................................................................ 16 

Statement by Representative Eric Swalwell, Ranking Minority Member, Subcommittee on Energy, Committee on Science, Space, and Technology, U.S. 

House of Representatives .................................................................................... 17 

Written Statement ............................................................................................ 19 

Statement by Representative Lamar S. Smith, Chairman, Committee on 

Science, Space, and Technology, U.S. House of Representatives ..................... 20 

Written Statement ............................................................................................ 20 

Statement by Representative Eddie Bernice Johnson, Ranking Member, Committee on Science, Space, and Technology, U.S. House of Representatives .... 21 

Written Statement ............................................................................................ 21 

Witnesses: 

The Honorable Charles McConnell, Executive Director, Energy & Environment Initiative, Rice University 

Oral Statement ................................................................................................. 22 

Written Statement ............................................................................................ 24 

Dr. Richard Bajura, Director, National Research Center for Coal and Energy, 

West Virginia University 

Oral Statement ................................................................................................. 30 

Written Statement ............................................................................................ 32 

Mr. Kurt Waltzer, Managing Director, The Clean Air Task Force 

Oral Statement ................................................................................................. 40 

Written Statement ............................................................................................ 42 

Mr. Roger Martella, Partner, Environmental Practice Group, Sidley Austin 

Oral Statement ................................................................................................. 60 

Written Statement ............................................................................................ 62 

Discussion ................................................................................................................. 69 
Page

IV 

Appendix I: Answers to Post-Hearing Questions 

The Honorable Charles McConnell, Executive Director, Energy & Environment Initiative, Rice University ......................................................................... 92 

Dr. Richard Bajura, Director, National Research Center for Coal and Energy, 

West Virginia University ..................................................................................... 97 

Mr. Kurt Waltzer, Managing Director, The Clean Air Task Force ..................... 102 

Mr. Roger Martella, Partner, Environmental Practice Group, Sidley Austin .... 105 

Appendix II: Additional Material for the Record 

Fresh Tech, Difficult Decisions, Basin Electric has a history of trying new 

technology, submitted by Representative Kevin Cramer, Subcommittee on 

Energy, Committee on Science, Space, and Technology, U.S. House of Representatives ........................................................................................................... 112 

Letter addressed to The Honorable Gina McCarthy, Administrator, U.S. Environmental Protection Agency, submitted by Representative Kevin Cramer, 

Subcommittee on Energy, Committee on Science, Space, and Technology, 

U.S. House of Representatives ............................................................................ 114 

Potential Impacts of EPA Air, Coal Combustion Residuals, and Cooling Water 

Regulations report submitted by The Honorable Charles McConnell ............. 118 

Impacts of Seven EPA Regulations chart submitted by The Honorable Charles 

McConnell ............................................................................................................. 192 

Impact of EPA Regulations report submitted by The Honorable Charles 

McConnell ............................................................................................................. 196 

Peak Year Employment Losses Caused by EPA Regulations (Five key regions 

of the U.S.) map submitted by The Honorable Charles McConnell ................. 197 

Peak Year Annual Household Income Losses Caused by EPA Regulations 

(Five key regions of the U.S.) map submitted by The Honorable Charles 

McConnell ............................................................................................................. 198 

Total Employment Losses Caused by EPA Regulations, 2013–2034 (Five key 

regions of the U.S.)map submitted by The Honorable Charles McConnell ..... 199 

Total employment losses caused by EPA regulations over four-year period, 

2013–2016 map submitted by The Honorable Charles McConnell .................. 200 
(1) 

EPA POWER PLANT REGULATIONS: IS THE 

TECHNOLOGY READY? 

TUESDAY, OCTOBER 29, 2013 

HOUSE OF REPRESENTATIVES, 

JOINT HEARING WITH THE SUBCOMMITTEE ON

ENVIRONMENT AND THE SUBCOMMITTEE ON ENERGY

COMMITTEE ON SCIENCE, SPACE, AND TECHNOLOGY, 

Washington, D.C. 

The Subcommittees met, pursuant to call, at 10:07 a.m., in Room 

2318 of the Rayburn House Office Building, Hon. Chris Stewart 

[Chairman of the Subcommittee on Environment] presiding. 
2 

LAMAR S. SMITH .. TeXBs 

CHAIRMAN EDDIE BERNICE JOHNSON, Tax •• 

RANKING MEMBER 

[Ongrrss of thE tinittd ~tatrs 

lRoust of 'Rtprt.stntatiot.s 

COMMITIEE ON SCIENCE, SPACE, AND TECHNOLOGY 

2321 RAYBURN HOUSE OFFICE BUILDING 

WASHINGTON, DC 20515-6301 

{202i 225-6371 

www.science.housu.gov 

Subcommittee on Environment 

and 

Subcommittee on Energy 

EPA's Power Plant Regulations: Is the Technology Ready? 

Tuesday. October 29,2013 

10:00 a.m. -12:00 p.m. 

2318 Rayburn House Office Building 

Witnesses 

The Honorable Charles McConnen, Executive Director, Energy & Environment 

Initiative, Rice University 

Dr. Richard Bajura, Director, NationalResearch Center for Coal and Energy, West 

Virginia University 

Mr. Kurt Waltzer, Managing Director, The Clean Air Task Force 

Mr. Roger Martena, Partner, Environmental Practice Group, Sidley Austin 
3 

U.S. HOUSE OF REPRESENTATIVES 

COMMITTEE ON SCIENCE, SPACE, AND TECHNOLOGY 

SUBCOMMITTEE ON ENVIRONMENT 

SUBCOMMITTEE ON ENERGY 

HEARING CHARTER 

EPA Power Plant Regulations: Is the Technology Ready? 

PURPOSE 

Tuesday, October 29,2013 

10:00 a.m. -12:00 p.m. 

2318 Rayburn House Office Building 

The Subcommittees on Environment and Energy will hold ajoint hearing entitled EPA 

Power Plant Regulations: Is the Technology Ready? on Tuesday, October 29th, at 10:00 a.m. in 

Room 2318 of the Rayburn House Office Building. The hearing will cover what considerations 

the EPA relied in making its selection of best system of emissions reductions in the proposed 

New Source Performance Standards (NSPS) for electric generating units (EGUs). In so doing, 

the hearing will explore the technological basis for concluding that carbon capture and storage 

(CCS) is adequately demonstrated as a technology for controlling carbon dioxide emissions in 

full-scale commercial power plants. Further, the hearing will examine whether the rule promotes 

or deters technological development and American leadership in energy technologies. 

Fundamentally, this hearing seeks to answer the question: Has CCS technology been 

"adequately demonstrated?" 

WITNESS LIST 

• The Honorable Charles McConnell, Executive Director, Energy & Environment 

Initiative, Rice University 

• Dr. Richard Bajura, Director, National Research Center for Coal and Energy, West 

Virginia University 

• Mr. Kurt Waltzer, Managing Director, The Clean Air Task Force 

• Mr. Roger Martella, Partner, Environmental Practice Group, Sidley Austin LLP 

BACKGROUND 

Regulatory Context: 

Section 111 of the Clean Air Act (CAA) establishes a unique technology-based mechanism 

for controlling emissions from stationary sources. Section 111 (b) provides authority for EPA to 
4 

promulgate NSPS which apply to new and modified sources. Specifically, EPA is directed to set 

standards based on "the degree of emission limitation achievable through the application of the 

best system of emission reduction which (taking into account the cost of achieving such 

reduction and any non air quality health and environmental impact and energy requirements) the 

Administrator determines has been adequately demonstrated."] In setting the standard EPA is 

given some flexibility in that "emission limits may be established either for equipment within a 

facility or for an entire facility.,,2 

EPA first proposed a NSPS for emissions for carbon dioxide (C02) from power plants in 

2012. However, after more than 2.5 million comments on the original proposal, EPA decided 

that a new approach was warranted and rescinded the original proposal. 3 

Simultaneously, on September 20, 2013 Administrator Gina McCarthy announced EPA's 

re-proposed C02 NSPS for new fossil fuel-based electric generating units (EGUs). "These 

proposed standards reflect separate determinations ofthe best system of emission reduction 

(BSER) adequately demonstrated for utility boilers and IGCC units and for natural gas-fired 

stationary combustion turbines.,,4 

Under the proposal, EPA concluded that CCS has been adequately demonstrated as a 

technology for controlling C02 emissions in full-scale commercial applications at coal-fired 

EGUs, while reaching the opposite conclusion-that CCS is not adequately demonstrated-in 

the case of gas-fired EGUs. Based on this determination, EPA proposed an emissions limit for 

coal-fired sources of 1, I 00 Ibs of C02 per mega-Watt-Hour (MWH) and proposed standards for 

natural gas combined cycle sources from 1,000 to 1,100 lbs C02IMWH depending on the size 

and type ofunit.5 Electric Generating Units that primarily fire biomass are exempted from the 

proposed rule.6 

In examining the regulatory impact, EPA asserted that "coal units built between now and 

2020 would have CCS, even in the absence of this rule." In light of this modeling, "EPA 

projects that this proposed rule will result in negligible C02 emissions changes, quantified 

benefits, and costs by 2022.,,7 The proposal seeks comment. 

Technical Background: 

Carbon capture and storage (CCS) methods capture C02 from fossil fuel combustion 

before it is released into the atmosphere and store it underground in geological formations. 

Unlike some emission control devices, CCS is not simply one piece of technology; it requires a 

system of coordinating elements for successful implementation. Broadly speaking, there are four 

links in the CCS chain: capture, compression, transportation, and storage. Each link in the chain 

poses separate and distinct challenges to the efficacy of the technology. Among these 

I Clean Air Act § 111(a)(I), 42 USCA § 7411(a)(I) (2006). 

2 http://www2.epa.gov/sitesiproduction/files/20 13-09/documents/111 background.pdf 

3 Standards of Performance for Greenhouse Gas Emissions from New Stationary Sources: Electric Utility 

Generating Units, Proposed Rule, Preamble p. 14-5, Sep. 20, 2013. 

4 ld at 15. 

SId at 15-6. 

6 !d. at 30, fiI. 8. 

7 Id at 16-7. 

2 
5 

components, capture is the most technology-intensive and costly. Storage, on the other hand, 

poses the greatest liability and regulatory obstacles. 

In the NSPS proposal, EPA notes four projects which-with significant governmental 

financial assistance-are designed to use some type of capture technology.s Although none of 

these projects have been completed, EPA anticipates at least one of these demonstration projects 

will be operational in the near future. EPA cites Southern Company's 

Kemper County Energy Facility in Mississippi, SaskPower's Boundry 

Dam CCS Project in Canada, The Texas Clean Energy Project in 

Odessa, and Hydrogen Energy California, LLC. Each of these 

projects, when completed, will utilize some elements of the CCS 

system EPA has selected in this proposal. 

However, despite the promise of CCS technologies in power 

systems, currently there are no electric power plants operating with the 

CCS technology on a commercial scale. 

CO

2 

Sources 

Where does C02 come 

from? Nearly half of 

emissions come from 

mobile sources, like 

cars. But Stationary 

Sources also release 

C02. Each colored dot 

represents a different 

type of stationary 

source with the dot size 

representing the relative 

magnitude of the C02 

emission source (see 

map legend). This map 

displays stationary 

source data obtained 

from the Regional 

Carbon Sequestration 

Partnerships (RCSPs) 

and other external 

sources and compiled 

by the National Carbon 

Sequestration Database 

and Geographic 

Infonmation System 

(NATCARB). 

11 EPA cites Southern Company's Kemper County Energy Facility, SaskPower's Boundry Dam CCS Project, Texas 

Clean Energy Project, and Hydrogen Energy California, LLC'. 

3 
6 

Capture 

C02 capture may be achieved through pre-combustion, post-combustion, or oxycombustion technologies. Pre-combustion removal methods typically require the highconcentration of C02 associated with expensive gasification systems. Post-combustion, on the 

other hand, utilizes nitrogen-based solvents to scrub the C02 from the flue gas. However, 

because post-combustion capture requires substantial heat input to release the C02 and 

regenerate the solvent, it results in significant reductions in overall plant efficiency and a 

substantial increase in cost. A third process, oxy combustion, requires expensive and energy 

intensive air separation units. While oxy systems hold promise, they are more experimental. 

Overall, while capture technologies exist, the new challenges associated with operating at a 

larger scale will not become clear until after full-scale deployment. 

Source: E. S. Rubin. 'Will urbon Caprure lnd Storage be Avaibble in Tlme!~ Prot. MAS AnI'Iua/ Meeoog, San 

DlerO, C4. 18-22 Feblltaly 201 0, AmerrCln Academy for the Advancement of xlence, Washington, DC 

Storage 

Compression & Transport 

Once the C02 is captured, it 

must be compressed. As with capture, 

compression is an energy intensive 

process. After compression, 

transportation to a storage site is 

required. Although dedicated C02 

pipelines have potential, technical 

challenges remain to ensure safe and 

reliable transport. Given the numerous 

policy and regulatory issues related to 

siting, permitting, and environmental 

requirements, creation of a full-scale 

C02 pipeline infrastructure requires 

tremendous capital investment. 

The critical final step in a CCS system is storage. However, permanently storing 

emissions is highly dependent on geologic systems. Geological storage is potentially available in 

deep saline formations, depleted oil fields, un-mineable coal seams, or for enhanced oil or gas 

recovery (EOR). However, lessons learned from failed storage sites in Africa demonstrate that 

maps of promising geologic formations do not always equate to locations where carbon storage 

can occur. Consequently, unresolved issues related to property rights acquisition, pore space 

management, regulatory structure, environmental protection issues, and liability remain a 

challenge. Significantly, EPA is unable to release operators from federal liability and litigation 

risk without legislative changes to existing environmental law. 

4 
7 

Because of these challenges and the 

potential to offset the significant cost of 

CCS, the proposed rule focuses on the use 

ofthe captured C02 for enhanced oil 

recovery (EaR). EaR has been used as a 

way to increase production in depleted oil 

fields by injecting C02 into the oil deposit 

and pumping previously unrecoverable oil 

to surface. While EaR provides 

outstanding opportunities to increase oil 

production in some regions, many 

locations do not have access to an EaR 

market. Absent a robust EaR market, 

C02 would simply be stored geologically. 

Future of CCS Demand: 

According to the Global CCS Institute's 2013 report, 

seventeen (65 percent) of the 26 cancelled or delayed 

CCS projects are in power generation. 

As discussions of new climate strategies continue, pressure for additional C02 

restrictions will likely increase. Simultaneously, worldwide energy demand, particularly in 

emerging economies, is growing rapidly. Much of the current and future demand for energy will 

continue to be supplied by fossil fuels. Consequently, many projections suggest a strong longterm need for affordable technologies that can supply low-carbon energy from fossil fuels. 

Additional Reading: 

CONGRESSIONAL RESEARCH SERVICE, Carbon Capture and Sequestration (CCS): A Primer. July 

16,2013. Available at: http://www.crs.gov/pdfloader/R42532. 

OLOOAL CCS INSTITUTE, Global Status ofCCS: 2013. Oct. 10,2013. Available at: 

http://www.globalccsinstitute.com/publications/global-status-ccs-20 13/online/117741. 

Hearing Chartcr, HOUSE SCIENCE, SPACE, AND TECHNOLOGY, SUOCOMMITTEE ON ENERGY AND 

ENVIRONMENT HEARING, The Future 01Coal: Utilizing America's Abundal1t El1ergy Resources, 

July 25, 2013. Available at: 

http://science.house.gov/sites/republicans.science.house.gov /files/documents/H HRO-113-

S Y20-20 130725-SDOO I %20.pdf. 

U.S. ENVIRONMENTAL PROTECTION AGENCY, Standard5 of Pelf or mance for Greenhouse Gas 

Emissions fi'om New Stationary Sources: Electric Utility Generating Units. 40 CFR Part 60. 

Sep. 20, 2013 . Available at: http://www2.epa.gov/carbon-pollution-standards/2013-

proposed-carbon-pollution-standard-new-power-plants. 

5 
8 

Chairman STEWART. The joint hearing of the Subcommittee on 

Environment and the Subcommittee on Energy will come to order. 

Good morning, everyone. Welcome to today’s joint hearing titled 

‘‘EPA’s Power Plant Regulations: Is the Technology Ready?’’ In 

front of each member are packets containing the written testimony, 

biographies and Truth in Testimony disclosures for today’s witnesses. 

Before we get started, since this is a joint hearing involving two 

Subcommittees, I want to explain how we will operate procedurally 

so that all Members understand how the question-and-answer period will be handled. After first recognizing the Chair and the 

Ranking Members of the Environment and Energy Subcommittees, 

we will recognize those Members present at the gavel in order of 

seniority of the full Committee, and those coming in after the gavel 

will be recognized in order of their arrival. And just as a side note, 

we had a Republican conference this morning, and that is going a 

little bit long. We expect other Members to be joining us shortly. 

And in the event that Ms. Lummis and others are not here for 

their opening comments, we will allow them to have that time allocated to them for their comments upon their arrival. I now recognize myself for five minutes for an opening statement. 

I would like to thank the witnesses for being here today. I have 

had the chance to introduce myself and to meet you, and we appreciate your time and your sacrificing in attending with us, and we 

have an excellent panel before us, but I am disappointed EPA 

didn’t accept our invitation to join us, and perhaps Ms. McCabe 

will be able to join us in the future hearing on this topic. 

The significance of EPA’s proposed New Source Performance 

Standards for new power plants simply can’t be understated. As 

the first GHG standards for the statutory sources under the Clean 

Air Act, the rule does more than affect power plants. It sets the 

benchmark for standards affecting all industries, standards that 

will touch every aspect of our economy. Most troubling, however, 

is the proposal appears to be based on a hypothetical plant. This 

is a very dangerous precedent. 

Under the Clean Air Act, setting the standards is basically a 

three-step process: first, establish the universe of adequately demonstrated technology; second, determine an achievable level based 

upon on that technology; and third, we consider the cost. In its proposal, EPA conveniently skips over step one. It then heavily focuses 

its analysis on modeling scenarios that project the answers to the 

steps two and three. These model-only-based arguments are outlandish to experts and engineers and to the general public. We 

don’t need to look further than the botched-out rollout of 

healthcare.gov to appreciate the consequences of disregarding testing of a full-scale product. But EPA thinks it can get away with 

it due, primarily, I think to the court’s deference. 

But the focus of this hearing, and the first question the EPA 

must answer, is not what standards do we set or even is this costprohibitive? Instead, our hearing today focuses only on step one, 

and that is, is the technology ready? This question exposes the soft 

underbelly of the rule. When the facts and experts make clear the 

technology is not ready, there is no need to model emissions levels 

or ask economists to make projections. 
9 

To be clear, EPA relies on DOE modeling to conduct their analysis, and this is how they circumvent the step one ‘‘is it ready’’ 

question. They simply assume that it is ready and then they plow 

ahead. The model is only as good as the assumptions that go into 

it. Even a critical design review cannot account for irregular behavior in a full-scale product. Take, for example, the first Tacoma Narrows Bridge. Everything appeared to be operational until a 40-milean-hour wind toppled what was the third longest suspension bridge 

in the world. 

Here, because the technology isn’t ready, all of EPA’s subsequent 

claims are purely hypothetical. Its claims are mere conjecture that 

ignores the fact that, in DOE’s words, the technology is unproven. 

After the Agency has finished looking into its crystal ball, analyzing an imaginary world, it tries to justify its claim of adequate 

demonstration with weak post hoc citations to cherry-picked literature, experiences with vastly scaled-down technology components and power plants that are under construction. 

In order to comply with EPA’s rule, carbon capture and sequestration is required. CCS, as it is commonly known, is not one piece 

of equipment; rather, is it a complicated system of many separate 

technologies. Each piece of this chain, which includes capture, compression, transportation and sequestration, must work in a 

seamlessly integrated fashion on a full-scale power plant. No CCS 

project in the world meets these criteria. 

In its proposed rule, EPA points to several examples of fledgling 

CCS projects as proof that the technology is adequately demonstrated, but let us take a look at some of those examples. If you 

could look here to the screen, here are a few examples of the Texas 

Summit Clean Energy project, which in EPA’s words is ‘‘under construction.’’ My favorite picture, which is coming up, is at the 

project’s web page, ‘‘small common grave by train tracks in 

Penwell.’’ Actually, this is the only CCS currently occurring on the 

site. 

Emissions modeling and economic projections based on a hypothetical plant are irrelevant. EPA’s rule won’t be implemented in 

a fairy tale world. This rule will affect real power plants and real 

people. This hearing is about what unicorns, Bigfoot, and the adequately demonstrated CCS for power plants all have in common: 

they are mere figments of the imagination. 

Talk of emissions levels and cost based on a hypothetical modeling scenario is just a bunch of noise, a distraction from the fact 

that the technology isn’t ready. EPA attempts to lawyer its way 

around this fact but ultimately, EPA cannot paper over the truth. 

To quote John Adams: ‘‘Facts are stubborn things.’’ 

I look forward to our experts’ discussion today on this step one 

question: is the technology ready? 

[The prepared statement of Mr. Stewart follows:] 

PREPARED STATEMENT OF SUBCOMMITTEE ON ENVIRONMENT CHAIRMAN CHRIS

STEWART

I would like to thank the witnesses for being here today. While we have an excellent panel before us, I am disappointed EPA didn’t accept our invitation. Perhaps 

Ms. McCabe will be able to join us for a future hearing on this topic. 
10 

The significance of EPA’s proposed New Source Performance Standards (NSPS) 

for new power plants cannot be understated. As the first GHG standards for stationary sources under the Clean Air Act, the rule does more than affect power 

plants. It sets the benchmark for standards affecting all industries—standards that 

will touch every aspect of our economy. 

Most troubling, however, is the proposal appears to be based on a hypothetical 

plant. This is a dangerous precedent. Under the Clean Air Act, setting the standards is basically a three step process: First, establish the universe of ‘‘adequately 

demonstrated’’ technology. Second, determine an achievable level based on that 

technology. Third, consider the costs.In its proposal, EPA conveniently skips over 

step 1. It then heavily focuses its analysis on modeling scenarios that project the 

answers to the steps 2 and 3. 

These model-only based arguments are outlandish to the experts, engineers and 

the public. We don’t need to look further than the botched roll-out of healthcare.gov 

to appreciate the consequences of disregarding testing of a full scale product. But 

EPA thinks it can get away with it due to the court’s deference. 

But the focus of this hearing—the first question that EPA must answer—is not 

‘‘what standards do we set?’’ or even ‘‘is this cost prohibitive?’’ Instead, our hearing 

today focuses on step 1: ‘‘is the technology ready?’’ 

This question exposes the soft under-belly of the rule. When the facts and experts 

make clear the technology is not ready, there is no need to model emissions levels 

or ask economists to make projections. 

To be clear, EPA relies on DOE modeling to conduct their analysis—that is how 

they circumvent the Step 1 ‘‘is it ready’’ question. They simply assume that it is and 

plow ahead. A model is only as good as the assumptions that go into it. Even a critical design review cannot account for anomalous behavior in a full scale product. 

Take for example the first Takoma Narrows Bridge. Everything appeared operational until a 40 mile-an-hour wind toppled what was the third longest suspension 

bridge in the world. 

Here, because the technology isn’t ready, all of EPA’s subsequent claims—are hypothetical. Its claims are mere conjecture that ignores the fact that, in DOE’s words, 

the technology is ‘‘unproven.’’ 

After the Agency is done looking into its crystal ball, analyzing an imaginary 

world, it tries to justify its claim of ‘‘adequate demonstration’’ with post hoc citations 

to cherry-picked literature, experience with vastly scaled down technology ‘‘components,’’ and power plants ‘‘under construction.’’ 

In order to comply with EPA’s rule, carbon capture and sequestration (CCS) is 

required. CCS, as it is commonly known, is not one piece of equipment; rather, is 

it a complicated system of many separate technologies. Each piece of this chain, 

which includes capture, compression, transportation and sequestration, must work 

in a seamlessly integrated fashion on a full scale power plant. No CCS project in 

the world meets these criteria. 

In its proposed rule, EPA points to several examples of fledgling CCS projects as 

proof that the technology is adequately demonstrated. Let’s take a look at one of 

those examples. 

Here are a few pictures of the Texas Summit Clean Energy project, which in 

EPA’s words is ‘‘under construction. 
11 

My favorite picture is at the bottom of the Project’s web page—‘‘Small common 

grave by train tracks in Penwell.’’ 
12 

Actually, that is the only CCS currently occurring at the site. 

Emissions modeling and economic projections based on a hypothetical plant are 

irrelevant. EPA’s rule won’t be implemented in a fairy tale world. This rule will affect real power plants and real people. This hearing is about what Unicorns, Bigfoot, 

and ‘‘adequately demonstrated’’ CCS for power plants all have in common—they are 

figments of the imagination. 

Talk of emissions levels and cost based on a hypothetical modeling scenario is just 

a bunch of noise—a distraction from the fact that the technology isn’t ready. 

EPA attempts to ‘‘lawyer’’ its way around the facts. But ultimately, EPA cannot 

paper over the truth. To quote John Adams: ‘‘Facts are stubborn things; and whatever may be our wishes., our inclinations, or the dictates of our passion, they cannot 

alter the state of facts and evidence.’’ 

I look forward to our expert panel’s discussion of this Step 1 question: Is the technology ready? 
13 

Chairman STEWART. With that, I now recognize the Ranking 

Member, Ms. Bonamici, for her opening statement. 

Ms. BONAMICI. Thank you very much, Chairman Stewart and 

Chair Lummis, for holding this hearing today. And to our panel, 

welcome to the Committee on Science, Space, and Technology. 

I join those who are very pleased by the proposal from the Administration and the United States Environmental Protection 

Agency to take the first steps to set carbon emission limits for all 

future natural gas and coal power plants. We have known for some 

time that dangerously high levels of carbon dioxide pollution are altering our planet’s climate system. According to the latest statistics 

compiled by the EPA, American power plants released more than 

2.4 billion tons of carbon dioxide into the environment in 2011. Fossil fuel power plants are responsible for a majority of these emissions, and coal-fired power plants emit more carbon dioxide than 

any other source. 

Last month, the Intergovernmental Panel on Climate Change released the global comprehensive scientific assessment confirming 

that it is extremely likely that human influence has been the dominant cause of the observed warming since the mid-20th century. 

The report also confirmed that carbon dioxide increases are primarily the result of fossil fuel emissions, and have increased by 40 

percent since the pre-industrial period. Addressing the effects of 

carbon pollution globally will require an international effort, but 

the United States can and must be a leader and set an example 

for other nations by reducing our own carbon pollution at home. 

We must do a better job of preventing the harmful effects of carbon 

dioxide emissions produced by natural gas and coal-fired power 

plants. 

The coal industry’s claim that the new carbon rule will kill jobs 

and bring down our recovering economy are scare tactics that have 

no basis in reality. The EPA proposal will not apply to existing 

power plants. The new rule will only apply to new coal-fired power 

plants that will be built in the future. 

As we look forward to the EPA issuing the new carbon emissions 

standard, it is worth reminding ourselves of what we get with 

these standards: better air quality, which means better health for 

us, for our children, and for our grandchildren. In the four decades 

since it was signed, the Clean Air Act has saved thousands of lives 

and helped fuel job growth. 

Additionally, and importantly, the passage of the Clean Air Act 

led to innovative advancements in technology. Environmental protection technology industries created innovations like catalytic converters, and sulfur dioxide and nitrogen oxide control technology. 

When the EPA took steps to require the application of these technologies, the industry made claims against those rules similar to 

the contentions that the coal industry is using today to undermine 

the carbon emission standard for new fossil fuel power plants: that 

our economy would be weakened and the industry would be devastated. And as we know, that did not come to fruition. Those industries adjusted and incorporated the technologies into their operations and went on to be more profitable than they had been, and 

we got cleaner air and healthier children. 
14 

The future of our planet and our environment depends on us 

making smart investments in innovative environmental protection 

technologies and reducing the amount of greenhouse gases we emit 

into our environment. The new EPA rule under the Clean Air Act 

will incentivize the development of these technologies that will in 

turn result in a safer, more secure and less carbon-dependent energy future. 

And before I close, Mr. Chair, I want to clarify. It is my understanding that according to the EPA, they did offer to appear at a 

hearing in November. They were unable to appear today because 

once the government reopened after the shutdown which, as you 

know, lasted more than a couple weeks, they did not have enough 

time to prepare for today with the backlog from the shutdown. So 

I don’t think they intended not to show; they did not get an invitation until September 27th, immediately before the shutdown. 

So thank you, Mr. Chairman. I look forward to the testimony and 

answers to our questions, and I yield back. 

[The prepared statement of Ms. Bonamici follows:] 

PREPARED STATEMENT OF SUBCOMMITTEE ON ENVIRONMENT RANKING MEMBER

SUZANNE BONAMICI

Thank you Chair Stewart and Chair Lummis, for holding this hearing today. And, 

to our panel of witnesses, welcome to the Committee on Science, Space, and Technology. 

I join those who are very pleased by the proposal from the Administration and 

the United States Environmental Protection Agency to take the first steps to set 

carbon emission limits for all future natural gas and coal power plants. We have 

known for some time that dangerously high levels of carbon dioxide pollution are 

altering our planet’s climate system. According to the latest statistics compiled by 

the EPA, American power plants released more than 2.4 billion tons of carbon dioxide into the environment in 2011. Fossil fuel power plants are responsible for a majority of these emissions, and coal-fired power plants emit more carbon dioxide than 

any other source. 

Last month, the Intergovernmental Panel on Climate Change released the global 

comprehensive scientific assessment confirming that it is ‘‘extremely likely that 

human influence has been the dominant cause of the observed warming since the 

mid-20th century.’’ The report also confirmed that carbon dioxide increases are primarily the result of fossil fuel emissions, and have increased by 40 percent since 

the pre-industrial period. Addressing the effects of carbon pollution globally will require an international effort, but the United States can and must be a leader and 

set an example for other nations by reducing our own carbon pollution at home. 

We must do a better job of preventing the harmful effects of carbon dioxide emissions produced by natural gas and coal-fired power plants. The coal industry’s claim 

that the new carbon rule will kill jobs and bring down our recovering economy are 

scare tactics that have no basis in reality. The EPA proposal will not apply to existing power plants. The new rule will only apply to new coal-fired power plants that 

will be built in the future. 

As we look forward to the EPA issuing the new carbon emissions standard, it is 

worth reminding ourselves of what we get out of these standards: better air quality, 

which means better health for us, for our children, and for our grandchildren. In 

the four decades since it was signed, the Clean Air Act has saved thousands of lives 

and helped to fuel job growth. 

Additionally the passage of the Clean Air Act led to important advancements in 

technology. Environmental protection technology industries created innovations like 

catalytic converters, and sulfur dioxide and nitrogen oxide control technology. When 

the EPA took steps to require the application of these technologies, the industry 

made claims against those rules similar to the contentions that the coal industry 

is using today to undermine the carbon emission standard for new fossil fuel power 

plants: that our economy would be weakened and the industry would be devastated. 

As we know, that never came to fruition. Those industries adjusted and incorporated the technologies into their operations and went on to become more profitable than they had ever been. And, we got cleaner air and healthier children. 
15 

The future of our planet and our environment depends on us making smart investments in innovative environmental protection technologies and reducing the 

amount of greenhouse gases we emit into our environment. The new EPA rule 

under the Clean Air Act will incentivize the development of these new technologies 

that will in turn result in a safer, more secure, and less carbon dependent energy 

future. 

Chairman STEWART. Thank you, Ms. Bonamici, and regardless of 

the reasons why, we do look forward to subsequent conversations 

with the EPA, and we anticipate that they will be accommodating 

to us at that point. 

The chair now recognizes the chairwoman of the Subcommittee 

on Energy, Ms. Lummis, for her opening statement. 

Chairwoman LUMMIS. Thank you, Mr. Chairman and Ranking 

Member. Good morning, and thank you, witnesses, for joining us 

at today’s hearing on carbon capture and storage technology. I do 

wish the EPA was here today, at least to listen to our concerns, 

and I consider an invitation extended on September 27th for a 

hearing that is occurring about a month later to be pretty good 

time to prepare, especially since it is their own rules that we are 

asking them to defend. 

The EPA has proposed New Source Performance Standards for 

any future coal-fired power plant. These standards can be achieved 

only through the application of carbon capture and storage, a technology that is not currently in operation at a commercial-scale 

power plant anywhere in the world. 

Instead of basing these requirements on technologies that are actually proven achievable on a commercial scale, EPA is redefining 

and stretching the requirement that technology be adequately demonstrated. This leaves many unanswered questions: Will the carbon 

capture technology function as intended when installed in full-scale 

plants? Is the pipeline infrastructure available for transportation 

on a large scale? And what is the liability for storage of carbon dioxide over the long term? EPA ignores many of these questions as 

the rule only impacts future coal plants. 

The Obama Administration has spent much of the past few years 

casting coal as a villain. This regulation effectively bans the building of new coal plants, and fulfills President Obama’s campaign 

promise to bankrupt coal companies. 

But this hearing is not only about the proposed regulation. It is 

also about the legal precedent of mandating unproven technologies. 

The distinction the agency makes between coal and natural gas 

plants is dubious at best. By claiming that carbon capture technology is adequately demonstrated for coal, there is scant justification, legal or technical, for not requiring it for natural gas units. 

If EPA is allowed to twist the definition of ‘‘adequately demonstrated’’ to include yet-to-be-proven technologies for power 

plants, there is also little time—excuse me—there is also little to 

stop EPA from doing the same for other manufacturers like refiners, cement or steel plants. Not only would this throw our economy 

into a tailspin, it would force manufacturers to flee to countries 

with less restrictive environmental requirements, costing jobs and 

increasing global emissions. 

Coal is our country’s most abundant and affordable energy 

source. Thanks to the deployment of proven technologies, its pro-
16 

duction is much safer and environmentally sound, and the Clean 

Air Act has worked. It has produced cleaner air every year since 

it was passed. Coal is not only our country’s most abundant and 

affordable energy source, one that the President is making clear 

that his goal is to apply standards to existing plants as well, thereby making it difficult for existing plants to stay in business. This 

policy of picking winners and losers, of saying we are going to have 

wind and solar energy but not fossil fuel energy or nuclear energy, 

even though those are the only ones sufficient to create baseload, 

is reckless, and it is dangerous for our country if we want to advance economically and create jobs and return to a sound economy. 

I continue to support an all-of-the-above energy policy, not one 

based on politics, and all of the above means all of the above including fossil fuel and including wind and solar. 

From an economic outlook, none of this should be taken lightly. 

Affordable, reliable electricity is the backbone of a healthy economy. Rising electricity prices affect everything, the cost of basic 

commodities, like food to our competitive position in the world. And 

because increasing energy prices act are like a regressive tax, they 

hit the poor and those on fixed incomes the hardest. Just ask any 

single mother who pulls up to a gas station when the price of gasoline hovers near 4 bucks. 

America cannot afford to allow EPA edicts to control our energy 

policy. These new regulations will make life harder for working 

families, for single moms struggling to get by, and for anyone who 

lives paycheck to paycheck. This is something we should be guarding against, not encouraging. 

I look forward to the hearing. I look forward to this panel of witnesses. I want to hear you discuss the development of this technology, its potential as well as its limitations. I also want to understand the impact this rule could have on future advances in carbon 

capturing and also conversion of coal to liquids and other opportunities that create a cleaner future for our country while enjoying 

and utilizing our ingenuity and our abundant coal resources. If you 

really want to see whether somebody is affected by coal, I strongly 

encourage you to go out around 12:30 on the west front of the Capitol today. There is an American energy jobs rally. There are coal 

miners and the companies they serve here on the Capitol steps, 

and if you think that it is not going to matter or whether you can 

pass regulations that the technology is unproven but will suddenly 

appear and the prices that won’t go up and that coal plants will 

continue to be built and those jobs will still exist, try listening to 

the people on the Capitol steps here today who will prove you 

wrong with their real-life stories. 

Thank you very much, Mr. Chairman. I yield back the balance 

of my time. 

[The prepared statement of Mrs. Lummis follows:] 

PREPARED STATEMENT OF SUBCOMMITTEE ON ENERGY CHAIRMAN CYNTHIA LUMMIS

Good morning and thank you for joining us for today’s hearing on Carbon Capture 

and Storage Technology. 

The EPA has proposed New Source Performance Standards (NSPS) for any future 

coal fired power plants. These standards can be achieved only through the applica-
17 

tion of Carbon Capture and Storage (CCS)—a technology that is not currently in operation at a commercial scale power plant anywhere in the world. 

Instead of basing these requirements on technologies that are actually proven 

achievable on a commercial scale, EPA is redefining and stretching the requirement 

that technology be ‘‘adequately demonstrated.’’ This leaves many unanswered questions: will the installment of carbon capture technology be functional? Are there 

plans for transportation on a large scale basis? What is the liability for storage of 

carbon dioxide over the long-term? 

EPA would like Congress oversight of these standards to include only its impact 

on future coal plants. The Obama Administration has spent much of the past few 

years casting coal as a villain. This regulation effectively bans the building of new 

coal plants, and fulfills President Obama’s campaign promise to ‘‘bankrupt’’ coal 

companies. 

But this hearing is not only about the proposed regulation. It is also about the 

legal precedent of mandating unproven technologies. The distinction the agency 

makes between coal and natural gas plants is dubious at best. By claiming that carbon capture technology is adequately demonstrated for coal, there is scant justification—legal or technical—for not requiring it for natural gas units. 

If EPA is allowed to twist the definition of ‘‘adequately demonstrated’’ to include 

yet-to-be-proven technologies for power plants, there is also little to stop EPA from 

doing the same for other manufacturers like refiners, cement or steel plants. Not 

only would this throw our economy into tail-spin, it would force manufacturers to 

flee to countries with less strict environmental requirements, costing jobs and increasing global emissions. 

Coal is our country’s most abundant and affordable energy sources. Thanks to the 

deployment of proven technologies, its production is safe and environmentally 

sound. The President has already made it clear that his goal is to apply these standards to existing plants as well. This policy of picking winners and losers through 

environmental regulations is reckless and dangerous. I continue to support an allof-the-above energy policy, not one based purely on politics. 

None of this should be taken lightly. Affordable, reliable electricity is the backbone of a healthy economy. Rising electricity prices affect everything—from the cost 

of basic commodities, like food—to our competitive position in the world. And because increasing energy prices act as a regressive tax, they hit the poor and those 

on fixed incomes the hardest. 

America cannot afford to allow EPA edicts to control our energy policy. These new 

regulations will make life harder for working families, for single moms struggling 

to get by, and for anyone who lives paycheck to paycheck. This is something we 

should be guarding against, not encouraging. 

I look forward to hearing the panel of witnesses discuss the development of this 

technology, its potential and limitations and the impact this rule could have on future advances. Thank you for joining us. 

Chairman STEWART. Thank you, Ms. Lummis. 

The Chairman now recognizes the Ranking Member of the Subcommittee on Energy, Mr. Swalwell, for his opening statement. 

Mr. SWALWELL. Thank you, Chairman Stewart and Chairman 

Lummis, for holding this hearing, and I look forward to working 

with our witnesses today. 

I do have to say, I think it is unfair, Mr. Chairman, to accuse 

the EPA of not accepting the invitation to be here today. That invitation was extended right before the shutdown and they have offered to appear in November. I look forward to having them here, 

but you can’t turn off the power and then complain that no one answered the phone, and that is what I think is happening right 

here, and I think that is an unfair way to start this hearing. 

Global climate change, though, is one of the greatest challenges 

that we face, and last month, the Intergovernmental Panel on Climate Change released a report which states with 95 percent certainty that human activities are responsible for climate change. 

This report was based on a rigorous review of thousands of scientific papers published by over 800 of the world’s top scientists. 

The report also makes it clear that if we do not take steps to halt 
18 

this damage and make this change, the repercussions for humans 

and the environment will be catastrophic. We need to move forward 

and take the necessary steps to combat the warming of our planet 

before these impacts become inevitable. 

We know that humans are impacting the climate in a number of 

ways, through emissions from the vehicles we drive, deforestation 

and changes in agricultural practices among other things. But fossil fuel-based power plants are the biggest producers of greenhouse 

gasses, accounting for roughly a third of our total emissions last 

year. 

I have repeatedly said, just as Chairman Lummis has, that I 

favor an all-of-the-above approach to energy production. As I often 

say, if we can make it safe, let us make it happen. But I have to 

make it clear that we must take steps to make sure that we are 

reducing greenhouse gas emissions and lessening their impact on 

human health, the environment and global change. 

That is exactly what the proposed standards for new coal and 

natural burning gases aim to do, which is why I support their implementation. And like Ms. Bonamici, I want to reinforce that they 

will have no effect on existing plants, so we aren’t going to see a 

wave of shuttered plants and massive layoffs as a result of their 

implementation, and if we can display the first slide? Slide number 

one that is going to be displayed shows all of the existing coal 

plants in the United States, approximately 600 of them. Slide two 

is a map of the United States, and it has on it all of the plants 

that are affected by these new standards. You don’t need a magnifying glass to see that the number is zero. Zero plants are affected 

by these standards. Zero jobs today will be lost by these new standards. And I think it is important not to confuse the issue here. 

There are in-depth discussions underway about establishing 

standards for existing plants, which the EPA currently plans to 

propose next June, and there are ongoing, extensive engagement 

with all of the stakeholders to make sure that those standards will 

be flexible and won’t have negative effects on state economies and 

job creation. I think we also cannot discount the value of certainty. 

The fact that there was uncertainty in what the regulations were 

going to be was also affecting job creation in existing plants and 

plans for new plants, and now that we have standards, that lends 

certainty to the marketplace. 

Finally, there is nobody I know in Congress who intentionally 

wants to destroy or kill a job. I think what we want to do here is 

to make sure that we have healthy air for our children to breathe, 

a healthy future, and mitigate the effects on the economy to the 

best degree possible, but if you want to count job-killing by the 

numbers, the cost of the government shutdown for 16 days: 120,000 

jobs, $24 billion to our economy. There is no policy that we can create today or that the EPA has created today that will kill as many 

jobs as that or wreak as much havoc on our economy as that government shutdown, and I think if we want to compare the two, 

that is a stark, stark contrast. 

Finally, my colleagues on the other side of the aisle often say 

that our children and grandchildren will be left holding the bag if 

we do not reduce our deficits and national debt, and something I 

greatly agree with them about, but I think similarly, future genera-
19 

tions will be the ones who will suffer if we do not take important 

and meaningful steps to confront climate change, but in this case, 

as the global scientific community has made clear again and again, 

the consequences of our inaction will be much, much more severe. 

And with that, Mr. Chairman, I yield back the balance of my 

time. 

[The prepared statement of Mr. Swalwell follows:] 

PREPARED STATEMENT OF SUBCOMMITTEE ON ENERGY RANKING MEMBER ERIC

SWALWELL

Thank you Chairman Stewart and Chairman Lummis for holding this hearing, 

and I also want to thank the witnesses for their testimony and for being here today. 

Global climate change is one of the greatest challenges that we face. Last month, 

the Intergovernmental Panel on Climate Change released a report which states with 

95 percent certainty that human activities are responsible for climate change. This 

report was based on a rigorous review of thousands of scientific papers published 

by over 800 of the world’s top scientists. The report also makes it clear that if we 

don’t take steps to halt this change, the repercussions for humans and the environment will be catastrophic. We now need move forward and take the necessary steps 

to combat the warming of our planet before these impacts become inevitable. 

We know that humans are impacting the climate in a number of ways—through 

emissions from the vehicles we drive, deforestation, and changes in agricultural 

practices among other things. But fossil fuel-based power plants are the biggest producers of greenhouse gasses, accounting for roughly a third of our total emissions 

last year. 

I have repeatedly said that I am for an ‘‘all of the above’’ approach to energy production as we transition to clean energy technologies. But I have also made it clear 

that, as part of this ‘‘all of the above’’ approach, we must take steps to ensure that 

we are reducing greenhouse gas emissions and lessening their impact on human 

health, the environment, and the global climate. That is exactly what the proposed 

standards for new coal and natural gas burning plants aim to do, which is why I 

support their implementation. And, like Ms. Bonamici, I want to reinforce that these 

are only proposed standards for any new plants that may be built and will have 

no effect on existing plants, so we aren’t going to see a wave of shuttered plants 

and massive layoffs as a result of their implementation. There are in-depth discussions underway about establishing standards for existing plants, which the EPA 

currently plans to propose next June, and there is ongoing, extensive engagement 

with all stakeholders to make sure that those standards will be flexible and won’t 

have negative effects on state economies and job creation. 

It has been my hope that Congress would act on this issue immediately. Unfortunately, too many of my colleagues choose to ignore the scientific consensus that 

human beings are playing a significant role in the warming of our planet, so I’m 

not expecting that much will be done legislatively to sufficiently address this issue 

anytime soon. The President made it clear in his State of the Union Address back 

in January that, in the absence of Congressional action, his Administration was 

going to take the lead in efforts to reduce greenhouse gas emissions. These proposed 

standards reflect that commitment, and I fully support the President in this effort. 

My colleagues on the other side of the aisle often say that our children and grandchildren are going to be left holding the bag if we don’t reduce our deficits and the 

national debt, and I agree that it would be irresponsible of us not to take serious 

steps to put our fiscal house in order. Similarly, future generations will be the ones 

who will suffer if we don’t take immediate and meaningful steps to confront climate 

change, but in this case—as the global scientific community has made clear again 

and again—the consequences of our inaction will be far more severe. 

Chairman STEWART. Thank you, Mr. Swalwell. 

Very quickly, we understand that there are differences of opinion 

and we can discuss or argue among ourselves whether the EPA had 

adequate time, some of us feel that they did, others may disagree 

with that. What is really clear is that in a pattern that has been 

established for more than just this hearing but for, frankly, for as 

long as I’ve sat in this chair, we have had to struggle to get them 
20 

to come and to participate in many of our hearings, and this is just 

another example of that. But as I said earlier, we look forward to 

working with them and getting their representatives to come and 

meet with us. 

With that, we will now turn to the Chairman of the full Committee, Chairman Smith, for his opening statement. 

Chairman SMITH. Thank you, Mr. Chairman. 

Today’s hearing will allow us to hear from top experts in energy 

and environmental fields and examine important technical issues 

associated with EPA’s new power plant regulations. 

In the regulatory process, it is often difficult to separate technical issues from legal issues, and the technology question we focus 

on here today is also ultimately a legal question. 

If you take a look at the EPA’s rule on air quality standards, the 

proposal looks more like a legal brief than a rule about protecting 

the air. It appears the EPA is up to an old legal trick: if you can’t 

win the argument on the merits, start arguing about the definition 

of words. 

In this proposal, the EPA redefines the law to accommodate its 

ever-expanding regulatory agenda. By redefining what the term 

‘‘adequately demonstrated’’ means in the Clean Air Act, the EPA 

is making another major power grab, one that reaches well beyond 

coal. That is because the New Source Performance Standards for 

power plants is the first greenhouse gas standard under the Clean 

Air Act. Consequently, it sets the precedent for all other sources, 

and underpins everything from the price we pay at the pump to the 

cost of electricity and food. 

If the EPA continues to play fast and loose with the law, we can 

expect to see more costly, heavy-handed rules that risk jobs and 

economic growth. Working families will bear these costs. 

Even more troubling is the way this proposal appears to intentionally block the courts from reviewing the rule. By claiming that 

no one will build coal-fired power plants anyway, the EPA wants 

to prevent the courts from reviewing the rule on its merits. 

Our founders recognized that elections alone may not provide 

adequate protection for the liberties they fought so hard to establish. They made sure that the Constitution provides a means for 

the American people to obtain a fair hearing before impartial 

judges. One of the most underrated rights Americans enjoy today 

may be the right to judicial review. This proposal is an attempt to 

prevent judicial review. Americans deserve to understand exactly 

what this proposal would do and retain the right to challenge it. 

Thank you, Mr. Chairman. Before I yield back, let me apologize 

at the outset. I have another committee that is in the middle of 

marking up legislation that I will go to and another committee is 

also having a hearing, so I will be shuttling back and forth but appreciate your holding this hearing. It is a very, very important one. 

Yield back. 

[The prepared statement of Mr. Smith follows:] 

PREPARED STATEMENT OF FULL COMMITTEE CHAIRMAN LAMAR SMITH

Today’s hearing will allow us to hear from top experts in energy and environment 

fields and examine important technical issues associated with EPA’s new power 

plant regulations. 
21 

In the regulatory process, it’s often difficult to separate technical issues from legal 

issues. And the technology question we focus on here today is also ultimately a legal 

question. 

If you take a look at the EPA’s rule on air quality standards, the proposal looks 

more like a legal brief than a rule about protecting the air. 

It appears the EPA is up to an old legal trick: If you can’t win the argument on 

the merits, start arguing about the definition of words. 

In this proposal, the EPA re-defines the law to accommodate its ever-expanding 

regulatory agenda. By re-defining what the term, ‘‘adequately demonstrated,’’ means 

in the Clean Air Act, the EPA is making another major power grab—one that 

reaches well beyond coal. 

That’s because the New Source Performance Standards for power plants is the 

first greenhouse gas standard under the Clean Air Act. Consequently, it sets the 

precedent for all other sources, and underpins everything from the price we pay at 

the pump to the cost of electricity and food. 

If the EPA continues to play fast-and-loose with the law, we can expect to see 

more costly, heavy-handed rules that risk jobs and economic growth. Working families will bear these costs. 

Even more troubling is the way this proposal appears to intentionally block the 

courts from reviewing the rule. By claiming that no one will build coal-fired power 

plants anyway, the EPA wants to prevent the courts from reviewing the rule on its 

merits. 

Our founders recognized that elections alone may not provide adequate protection 

for the liberties they fought so hard to establish. They made sure that the Constitution provides a means for the American people to obtain a fair hearing before impartial judges. 

This may be one of the most under-rated rights Americans enjoy today: the Right 

to Judicial Review. 

This proposal is an attempt to prevent Judicial Review. Americans deserve to understand exactly what this proposal would do and retain the right to challenge it. 

Chairman STEWART. Thank you, Mr. Chairman, and you are welcome to participate as much as you can. Thank you. 

If there are Members who wish to submit additional opening 

statements, your statements will be added to the record at this 

point. 

[The prepared statement of Ms. Johnson follows:] 

PREPARED STATEMENT OF FULL COMMITTEE RANKING MEMBER EDDIE BERNICE

JOHNSON

I want to thank Chairman Stewart and Chairwoman Lummis for holding this 

hearing to discuss the EPA’s proposal to set national carbon emission limits for new 

natural gas and coal power plants. I also want to thank the witnesses for being here 

today to provide their input on this important topic. 

The benefits from the Clean Air Act are countless; they come in the form of lives 

saved, reductions in illnesses, technological advancements in environmental protection, and economic growth. I join my colleagues Ms. Bonamici and Mr. Swalwell in 

expressing my approval of the Obama Administration’s and the EPA’s first steps toward protecting future generations from the harmful effects of carbon pollution that 

threatens our health and is changing our climate system. And, they are making 

those steps by advancing clean energy technologies. We would all prefer to address 

these important issues with common sense legislation, but until we can agree on 

both sides of the aisle that climate change is a real and pressing problem, bi-partisan collaboration on solutions does not appear to be possible. 

Throughout history industry has often resisted addressing environmental problems that emerge as a result of a greater scientific understanding of our impact on 

the environment and our health. And, in many of these cases, they simply will not 

do so without regulatory intervention and proper government oversight. I challenge 

industry leaders to be a helpful partner in reducing our carbon emissions going forward. If they will, we can have both a cleaner environment and a strong economy. 

Chairman STEWART. As our witnesses should know, spoken testimony is limited to five minutes, after which the Members of the 
22 

Committee have five minutes each to ask you questions, and your 

written testimony will also be included in the record of the hearing. 

And I would like now to introduce our witnesses today, and I will 

introduce you individually. We will turn the time over to you for 

five minutes, then I will introduce the next witness. 

Our first witness is the Hon. Charles McConnell, Executive Directive at the Energy and Environment Initiative, Rice University. 

Previously, Mr. McConnell served as the Assistant Secretary for 

Fossil Fuel at the U.S. Department of Energy. At DOE, he was responsible for the strategic policy, leadership, budgets, project management, research and development of the Department’s coal, oil 

and gas and advanced technology programs, and the National Energy Laboratory’s Technology Laboratory. Prior to joining DOE, Mr. 

McConnell served as Vice President of the Carbon Management at 

Battelle Energy Technology. And Mr. McConnell, we turn the time 

over to you now for five minutes for your opening statement. 

TESTIMONY OF THE HON. CHARLES MCCONNELL, 

EXECUTIVE DIRECTOR, 

ENERGY & ENVIRONMENT INITIATIVE, RICE 

Hon. MCCONNELL. Thank you. It is an honor to participate at 

this hearing and have the opportunity to have a fact-based discussion about the science of CCS technology. I might also add, it is refreshing to prepare my remarks today without any OMB oversight. 

Let me start by saying that we do have a problem. CO2 capture, 

utilization and storage technology is a requirement to meet greenhouse gas standards. It is a requirement to meet New Source Performance Standards, and it has not been commercially demonstrated at scale and cannot be deemed demonstrated technology. 

CCS is an environmental solution. It is an energy security issue, 

and it is also about economic competitiveness. All three of these 

things contribute to our success as a Nation. CCS has the potential 

to make us stronger and more successful as long as we don’t forfeit 

that potential by rushing deployment of a technology that is not yet 

ready. 

The world is and will remain dependent for many decades to 

come on fossil fuels to provide low-cost, available and reliable energy. The International Energy Agency has already projected by 

2050 the world’s demand for energy will double. One point seven 

billion people in the world today live in energy poverty. And yet by 

2050, because we will need every single megawatt, megatherm and 

energy source available to us, we will still have 85 percent of our 

energy in the world provided by fossil fuels. So having fossil technology isn’t an option, it is a requirement, as is an all-of-the-above 

strategy. 

Commercial CCS technology is not available to meet the EPA’s 

proposed rule. The cost of capture technology is much too high to 

be commercially viable, much the same as the economic threshold 

similar to subsidized carbon-free alternatives such as solar, wind, 

et cetera. We are investing in all of the above across the board because it is critical to our future. 

In June, the Administration released its Climate Action Plan, a 

comprehensive program of domestic GHG emission reductions. The 

President’s plan can only be achieved through the broad deploy-
23 

ment of low-cost, commercially viable technology for capturing and 

permanently and safely storing CO2 from all fossil sources. 

But it is about energy security as well. CCS is necessary to assure a sustainable, diversified domestic energy portfolio for our energy security. It enables a true all-of-the-above energy portfolio. It 

is also a business strategy. CCS, or CCUS, where the U means utilization of CO2 for purposes such as enhanced oil recovery, create 

a marketplace for implementation of these applications. It leads to 

broad deployment and it also gives us a commercial and business 

background to bring that technology to the marketplace. CO2 EOR 

has been practiced in this country for over 50 years very successfully, and it includes the safe, long-term permanent storage of CO2. 

But as I said, the technology isn’t ready yet. The technology exists 

for separation and capture of CO2 at the plant but it increases the 

cost of generated electricity by as much as 50 to 80 percent, and 

that depends on the power plant or the industrial application in 

which it is being used. CO2 pipeline and transmission systems are 

mature but they face incredible siting difficulties for expansion of 

this marketplace. 

DOE’s regional carbon sequestration partnerships must continue 

to develop the needed database to help analyze the success of this 

deployment, and of course, the injection of CO2 faces regulatory 

barriers as well: unresolved property rights, long-term liability 

issues, all of the issues that in many cases the EPA is very involved in and needs to be supportive of to allow this technology to 

move forward. 

But the technology is being demonstrated. It is successfully deployed in some early first-of-a-kind projects but it is clearly not 

ready. It is really that simple. Focusing other questions are hypothetical but not about the demonstrated results of these plants or 

projects or the technology associated with it. The technology can be 

made ready over time, and will have to have the support of the 

EPA as well as the marketplace and industry. 

To summarize, in my opinion, it is disingenuous to state that the 

technology is ready, and at the same time, starve the R&D programs for our Nation’s energy security, global competitiveness or 

our global leadership in terms of economic performance. Thank 

you. 

[The prepared statement of Hon. McConnell follows:] 
24 

U.S. House of Representatives Committee on Science, Space, and 

Technology Subcommittees on Environment and Energy 

EPA Power Plant Regulations: 

Is the Technology Ready? 

Oct 29, 2013 10:00 a.m. 

The Honorable Charles D. McConnell 

Executive Director, Energy and Environment Initiative (e2i) 

Rice University 

RICE" 
25 

Thank you for the opportunity to address this very important topic. 

Carbon Capture and Storage as well as Carbon Capture Utilization and Storage 

(CCS/CCUS) are critically important to our nation, and I am glad Members of Congress are 

taking the time to understand the state of today' s technology. CCUS is both an environmental 

solution and an important component of a business strategy. It is a business strategy that allows 

companies to meet EPA greenhouse gas (GHG) regulations, increase domestic oil production, 

and create domestic jobs by means of CO2-EOR. CCUS also is necessary to assure a diversified 

domestic energy portfolio for energy security. It also helps minimize future rapid escalations in 

electricity prices, allowing a real "All of the Above" energy portfolio that includes our most 

abundant domestic resources - clean fossil energy from coal, oil, and natural gas. 

Studies have verified that implementation of CCUS technology is necessary to comply 

with EPA's proposed New Source Performance Standard (NSPS) regulation and meet the GHG 

targets necessary for limiting CO2 emissions to our atmosphere. However, commercial CCUS 

technology currently is not available to meet EPA's proposed rule. The cost of current CO2 

capture technology is much too high to be commercially viable and places the technology at 

similar economic thresholds of alternative clean, carbon-free energy alternatives currently being 

subsidized. 

CCUS is also necessary to achieve President Obama's June 25th Climate Action Plan, a 

comprehensive program of domestic GHG emission reductions, adaptation measures, and 

international activities to address climate change. Global climate change, as the name indicates, 

2 
26 

must be addressed globally in order to make a difference. The world is and will remain 

dependent on fossil fuels for many decades to come to provide low cost, readily available and 

reliable energy. 

The President's Plan can only be achieved through the broad global deployment of low 

cost, commercially viable technology for capturing and permanently and safely storing/utilizing 

CO2 from all fossil energy sources. Technology exists for separation and capture of CO2 at the 

plant, but it increases the cost of generated electricity by about 80%. CO2 pipeline technology is 

mature, but can face siting issues. While injection of CO2 into deep geologic storage formations 

is being evaluated, it has only been done successfully on a relatively small scale at a few sites 

around the globe. And the Department of Energy's (DOE) Regional Carbon Sequestration 

Partnerships are still developing the needed data base to help analyze the success of its 

deployment. Saline injection also faces regulatory barriers, such as liability for leakage extending 

50 years beyond the time injection ceases, and unresolved property rights issues. CO2 injection 

into oil bearing geologies for Enhanced Oil Recovery (EOR) has been practiced safely for over 

50 years. Although the geologies are known to have permanence for storage, the long-term 

measurement, monitoring, and verification of these geologies has not been practiced for CO2 

storage. 

DOE, in partnership with industry, is pursuing a research, development, and 

demonstration (RD&D) program to address all of these issues, especially C02 capture cost 

reduction, but affordable solutions may be decades away with the current level offunding and 

resultant R&D strategy. Moreover, the timing of retirement of existing coal-fired units, based on 

3 
27 

age and regulatory pressures, and the modest amount of new domestic power plant capacity 

resulting in part from the weak economic recovery, could lead to further delays in 

commercializing this necessary technology in our country. Internationally, however, the drive to 

provide electricity to those in developing nations is in full force and the year-over-year demand 

for coal globally is up 20% due to the pressure to eliminate energy poverty. 

The DOE's coal research and development funding levels must be increased to enable the 

pursuit of demonstration projects to move transformational, low cost eeus technology from the 

laboratory to the commercial marketplace in a timely manner. The sequester and persistently 

low budget request numbers have resulted in cuts to coal R&D at rates significantly lower than 

other DOE programs. An additional $100 million per year directed at low-cost, transformational 

eeus could enable the demonstration of commercially viable e02 capture technology within 

ten years. While a considerable amount of technical risk would be required to undertake a 

program with this short of a schedule, it can be done. 

Such risk could be made manageable through the build-out of DOE's extensive scientific 

and engineering eeus database, along with the scaling and system integration experience 

provided by the major ees demonstration projects - such as the Kemper Project, scheduled to 

go on line in 2014. 

These demonstration projects were funded with stimulus dollars. However, the stimulus 

dollars were focused on near term jobs creation and had associated "sunset clauses" not typically 

part of demonstration program funding. Sunset clauses force the demonstration of first of kind 

technologies on an "artificial" legislated schedule - not a schedule determined by the 

4 
28 

management of risks associated with the scaling and integration of complex new technologies 

and the acquisition of financing for multi-billion dollar first-of-a-kind plants. While a large 

amount of stimulus monies were provided, they were sufficient to cover only about 20% or less 

of the costs of many of the major fossil/CCS/CCUS power plant demonstration projects. This 

required DOE's project partners to acquire billions of dollars in financing for technically and 

financially risky projects during a period that the U.S. was going through a deep recession not 

easily done. This takes much time and effort to accomplish. The stimulus funding sunset 

provisions scheduled for September 2015 allow for very little time to secure such financing and 

many good projects could be lost as a result. The Congress may wish to consider extending the 

sunset provisions and also allowing DOE to transfer stimulus funding between ongoing projects 

to maximize success. 

It is obvious that there is a need for continued funding as is defined by technologies that 

are not deemed to be "commercially available." To summarize, in my opinion, it is disingenuous 

to state that the technology is "ready" and it is wrong to underfund to assure failure if the true 

goal is "All of the Above." 

5 
29 

Charles D . . McC(!fIllell Executive Director of Rice Uniwrsity's 

university-wide integration of science. engineering. eC')IHllnic 

the diverse and challenges associated with 

and ;mstainubilily. emlrl to 

external stakeholders and position Ric.: as an impartial broker that \:ombincs technology and 

to energy platfbrm for excellence resource and 

Inc., providing business and strategic 

and chemicals markets. oil 

technology R&D activities. 

chemical engineering n'om 

Cleveland (1984). 
30 

Chairman STEWART. Thank you, Mr. Secretary. 

Our second witness today is Dr. Richard Bajura, Director of the 

National Research Center for Coal and Energy at West Virginia 

University. And Doctor, did I pronounce your name correctly? 

Dr. BAJURA. Yes, sir. 

Chairman STEWART. Thank you. He has spent the past 21 years 

facilitating research programs in energy at West Virginia University, and during this time he developed and managed eight major 

interdisciplinary and interinstitutional research programs addressing a wide range of energy applications from research extraction to 

alternative fuels. And Doctor, we turn the time over to you now. 

TESTIMONY OF DR. RICHARD BAJURA, 

DIRECTOR, NATIONAL RESEARCH CENTER 

FOR COAL AND ENERGY, WEST VIRGINIA 

Dr. BAJURA. Thank you, Mr. Chairman. Thank you for inviting 

me. 

I consider coal to be a valuable resource and I believe we should 

maintain technology options to keep it as part of our energy future. 

As proposed, I think the EPA regulations will stifle coal’s continued 

involvement. 

I will summarize my comments in terms of lessons and observations that we have gained over the years of using coal technologies. 

Pulverized coal technologies are mature, integrating gasification 

and combined cycle technologies. There are only nine of them operating on coal in the world and only four in the United States. We 

have also learned that performance degrades with scale-up. What 

we learned in the laboratory doesn’t always hold true when we go 

into the full-scale system. Many gremlins occur. Also, we have observed that delays in implementing projects, financing, technology 

costs and meeting schedules are important in determining the 

deployability of a technology. 

The next topic deals with first-of-a-kind and nth-of-a-kind technologies. Over the years, we have developed what I will call learning-curve theory. What we find is the most expensive plant occurs 

on the first edition. By the time we get to the nth edition, the technology is mature and costs are reduced. Learning-curve technology 

for coal uses a factor that they call .06, which means that by the 

time you get to mature technology, you have reduced the cost by 

25 percent. In the case of the Kemper plant, a $4 billion program, 

25 percent reduction is $1 billion. Also in the case of Kemper, we 

are talking about $8,000 a kilowatt for the cost of the plant versus 

$1,000 a kilowatt for a natural gas combined cycle plant. 

Coal is different from gas. Coal comes in three typical forms: bituminous, subbituminous and lignite. Natural gas, you can buy it 

anywhere. It is the same thing. Also, when you look at the deployment of technologies, what I learned on my technology is different 

from what you learn on your technologies. I don’t share my results. 

As a result, while we might say we have different examples of technologies, they are almost first of a kind because they don’t share 

the technology, they have different systems they apply to different 

coal. Technology integration is also important. We have to integrate a plant that has a new component with a pipeline, with a reservoir, and in many cases with the grid because we have to inte-
31 

grate the up-and-down performance of coal plants that might need 

changed from baseload to intermittent or peaking time of the situation. 

In terms of the demonstrations that we have talked about that 

relate to this hearing, there are nine demonstrations that are referenced. Three relate to chemicals production. Two are IGCC 

plants. One is them is based on the Kemper plant, which has not 

demonstrated, and the other one is a first of a kind as well. Saline 

aquifers are the kind of aquifers that I think we are looking at 

with future-gen deployments, and there is only one example of 

that, and that future-gen plant is not going to be onboard until 

2017. 

We have heard that capture technology is very expensive for coal 

plants. Capture technology for the most part is based on amines. 

We know that works. But these technologies were developed for 

chemical plants where the products that you sell can justify the 

extra cost they would need to use those technologies. It is very expensive for a standalone coal plant. 

Also, we have issues concerned with legal and societal issues that 

also affect the cost of a plant and must be addressed. Cost and feasibility are not necessarily demonstrated. We can’t find guarantees 

for the projects that we would want to put in place, and I am concerned with the legislation in the way it is proposed, it will stifle 

development and planning for new plants, and without a driver, 

there will be no technology developed. Our friends in China are 

very interested in developing coal-based technologies, they have 

strong government support and they are ahead of us in chemicals 

production, in power generation, and in their next five-year plan, 

they will be ahead of us in CCS deployment. We require strong 

Federal support to maintain coal’s presence in the marketplace, 

and I believe Congress and the Federal Government and the Executive Branch should be more supportive of coal and maintaining it 

as part of our mix. 

In summary, I don’t think the technologies that we are discussing are ready for deployment in the sense of being fundable by 

financiers or getting guarantees. I believe that if we are not keeping coal in our future mix, we will run out of workforce. People like 

me are getting older. And I believe Federal support will help us to 

achieve the kind of goals that we want in introducing new technologies. Thank you. 

[The prepared statement of Dr. Bajura follows:] 
32 

Rpnm<;pr1!"ji"O" Chris Stewart 

nrp"PI1,,,,lh,P Suzanne Bonamici 

Subcommittee on Environment 

Committee on Science, Space 

and Technology 

U, S, House of Representatives 

2321 House Office Building 

D, C 20515-6301 

Office of Director 

Research Center For Coal Energy 

Richard A 8ajura 

Subcommittee on 

Committee on Science, 

and 

U, S, House of RA')Cf'RC."h,tic'''R 

October 27,2013 

232'1 House Office Building 

\Ne."hiinn'inn D, C, 20515-630'1 

Testimony on 

Presented 

Richard A, 

Director 

National Research Center for Coal and Energy 

West Virginia University 

October 29, 2013 

Members of Ihe Subcommittees on Environment and Energy: 

to offer testimony on the New Source Performance Standards 

~".,e"",,,'pr1 by U, S, Environmental Protection Agency (EPA) under Section 1 

of the Clean Air Act of 1970, 

EPA identified the following key factors in their criteria for the proposed rulemaking: 

Feasibility whether the system of emissions reduction is technically feasible 

• Costs whether the costs of the system are reasonable 

• Size of the Emissions Reductions - amount of C02 emissions reduction resulting from tile 

system 

• Technology Development whether the system promotes implementation and further 

development of technology 
33 

Page 2 of7 

My testimony will focus on coal-fired electricity generation. Topics discussed are lessons learned 

about technology development, the stage of development of CCS (carbon capture and storage) 

technologies, technology development in other nations, and the need for federal support for 

research and demonstration projects. 

Lessons Learned in Technology Development 

Coal Plant Deployments and Performance 

Thomas Sarkus of the National Energy Technology Laboratory (NETL) provided an overview of the 

U. S. Government's program in developing Clean Coal Technologies in a presentation at the 2013 

Pittsburgh International Coal Conference. 1 

He noted that pulverized coal boilers were commercialized in the 1920s and 1930s, and that there 

are about 5,000 units operating world-wide with approximately 1,100 operating in the U. S. 

Fluidized bed coal combustion boilers were commercialized in the 1970s-1980s, and there are 

around 500 units operating world-wide with about 150, mostly small, units in the U.S. However, for 

Integrated Gasification Combined-Cycle (IGCC) coal power plants, there are only nine units 

operating world-wide and only four in the U. S. 

He also shared his experience as a project manager for demonstration projects. He observed that 

technology performance often degrades with scale-up. In other words, a technology that looks 

promising in a small laboratory setting may not achieve the predicted operating performance at 

commercial scales. We often discover that new factors arise in larger systems that were not 

apparent in laboratory experiments. Also, project financing, cost of a system, and meeting 

construction schedules are all important considerations in determining if a technology is ready for 

commercial deployment. 

First and Nth of a Kind Plants 

In studying the development of technology for full scale systems that are deployed in large numbers 

such as the 5,000 pulverized coal plants referenced above, engineers have been able to quantify 

concepts that are called technology learning curves. Typically the highest cost for a full scale unit is 

the first of a kind (FOAK). As more copies of the same deSign are built and debugged, the 

performance of the design will generally improve and the cost for construction and operation will 

decrease. EPA is counting on the learning curve effect in making its projections for future 

performance and cost of CCS-based coal plants in establishing the proposed emissions limits on 

coal systems. 

Care is needed, however, in in defining FOAK units and NOAK (Nth of a kind) units. Large scale 

units are usually based on a particular manufacturer's technology. Observations in the DOE/NETL34/042211 report 2 illustrate the example that although gasification technologies are similar, it is 

unlikely that one vendor will share its experience with rivals. They comment that the E-Gas IGCC 

system (Conoco-Phillips technology) proposed for the Excelsior project is only a second of a kind 

1 Thomas Sarkus, Lessons Learned from U. S. Government Support of Clean Coal Technologies, 

International Pittsburgh Coal Conference, 2013, Beijing 

2 Quality Guidelines for Energy System Studies - Technology Learning Curve (FOAK and 

NOAK), DOE/NETL-341-042211, January, 2012 National Energy Technology Laboratory 

E:\Testimony to SS&T Committee 2.doc 
34 

Page 30f7 

IGCC based on the Wabash project experience. Little or no benefit will accrue to the E-Gas 

designers from the Pinion Pines (KRW technology) plant that failed, the Polk (GEE technology) in 

Florida, or the Buggenum and Puertollano (Shell) projects. Since the Excelsior project did not go 

forward to construction, of the nine IGCC plants cited by Sarkus above, it is possible they could all 

be FOAK plants. In this case, we would have only one, high-cost demonstration of each type that 

still has many major design parameters to be worked out to bring costs down and performance up 

to the values for an Nih of a kind plant. 

We must also recognize that, unlike natural gas that is readily available nationally as a uniform 

commodity, coal varies from region to region in its characteristics. Coal power plants must be 

designed to accommodate the particular characteristics ofthe coal supplied. Hence, a large 

number of plants must be tested over a range of coals to bring a technology to a state of 

commercial readiness whereby a financial backer is willing to provide financing and a technology 

vendor is willing to guarantee system performance under penalty of paying the costs for operation 

of underperforming units. 

Traditional pulverized coal plants have achieved demonstrated technology status. New designs 

such as ultra-supercritical systems or oxygen fired (oxyfuel) systems have not achieved that level of 

performance attainment given their relatively new introduction as a next-generation technology. 

Some of EPA's criteria in the NSPS proposal are based on only a FOAK system rather than a 

NOAK system. Experience has shown that FOAK systems are not commercially available and 

additional iterations on the technology are required to achieve commercial status. 

Technology Integration 

Technology learning curve theory also includes the proposition that some plants may have 

components of a technology that can be considered as Nih of a kind, but have critical components 

that are new and first of a kind. Hence, a pulverized coal technology plant that uses a new 

technology for carbon capture, such as a membrane, could be considered as a FOAK kind of a 

plant for the following reason. Control and operational problems usually have to be overcome due 

to the difficulties of integrating the new component with an older component that was not originally 

designed to be a good interface with advanced technology systems. 

Integrating CCS with a power generation plant introduces complexities. The full system must be 

designed to handle contingencies that may occur. What if access to the carbon storage reservoir 

becomes unavailable - what happens to the C02 captured? Alternatively, if the plant goes off line 

and the reservoir performance is based on continuous injection of C02 to avoid damage to the long 

term performance of the reservoir, where does the plant or reservoir operator get the C02 needed? 

C02 injection studies into geologic reservoirs have only been carried out at scales of tens of 

thousands of tons of C02 per site. Larger scale studies are underway. For a full scale operating 

plant, a million tons of C02 per year may be generated and would need to be injected to handle the 

plant's output. We need to validate geologic storage at this scale to prove out an integrated system 

with a C02 capture plant. FutureGen, which is scheduled to be on line in 2017, will integrate the 

operation of the Meredosia plant with the storage reservoir operations. Integration of all 

components will be a challenge. This experiment will be a FOAK kind of plant in the context of the 

present discussion. Since this plant is still not in operation, we have not yet achieved a FOAK 

status with regard to developing a lessons learned notebook on demonstrating the technology. 

E:lTestimony to 88&T c.,mmittee 2.doc 
35 

Page 4 of7 

Status of Carbon Capture Technologies 

Many of the currently discussed post-combustion carbon capture technologies are based on the 

use of amines or chilled ammonia (recent technology developed by Alstom). The amine 

technology was originally developed for the chemical industry. In a chemicals plant, it is often 

necessary to remove C02 from the process stream. Amine systems have high operating costs. 

Energy is required to disassociate the captured C02 from the amine in order to use it again in the 

process stream. Chemical plants producing high value products can afford the extra expense since 

costs are recovered in the price of the product. 

The price of the electricity is one of the lowest "value-added" components of a multi-product planti.e, for a polygeneration plant. Here fertilizer could be made, the captured C02 sold for enhanced 

oil recovery (EOR) and process steam sold for district heating. Electricity is a smaller component of 

the overall outputs of the plant. The Summit and HECA plants referenced in the EPA proposal are 

plants of this type. 

The cost of operating an amine technology for carbon capture in a stand-alone power plant is 

relatively more than in a chemicals plant. In a plant dedicated solely to generating electricity, the 

cost of using the traditional amine technology is generally summarized as: 

• 45-70% increase in the cost of electricity 

• 35-110% increase in capital costs 

• 15-21% decrease in the plant's electricity output compared to operations before carbon 

capture equipment was added 

While it has been demonstrated that carbon capture using amines will work technologically, this 

type of technology is not cost competitive for a stand-alone power generation plant as compared to 

a chemical refinery or a polygeneration plant. Using newer advanced technologies such as 

membranes or ionic liquids, or revised power cycles that minimize the steps required to separate 

and capture C02 are ways to reduce costs. However, these are newer technologies that have not 

been demonstrated at commercial scales. 

Legal and Social Issues 

The large number of legal and social issues associated with developing a carbon sequestration site 

can delay construction and must be factored into the assessment of a technology's readiness for 

deployment. Data from many sources show that the cost of electricity from new natural gas plants 

would be low compared to new coal fired plants. Around 22% of the total cost of electricity for a 

natural gas combined-cycle plant is the capital cost, whereas capital costs could be as much as 

50% of the total cost of electricity for a coallGCC plant. Given the large fraction of a coal plant's 

cost that is tied up in debt service for financing and the long operating time over which payback may 

occur (typically 30-40 yeas), it is important that project construction occur on a timely basis. 

Otherwise, the increased cost of capital over the delay period would raise the cost of electricity 

even higher for the coal plant. 

Practice has shown, however, that the following factors often add to cost increases that affect 

financing, technology development, and timeliness for the construction of coal plants: 

• Regulatory Issues - permitting, treatment of C02, ... 

E:\Testimony to SS&T Committee 2.doc 
36 

Page 5 of7 

• Infrastructure Development - pipeline construction and permitting, ... 

• Human Capital- need for developing a new workforce skilled in building and managing the 

equipment inside the plant boundary and handling the transport and storage of C02 in the 

field, ..... 

• Legal Framework - liability for the C02 once it is injected, ownership of the pore space under 

ground, ownership of the C02 once injected, legal hassles between states over crossboundary transport of C02 underground, .... 

• Public Acceptance - NIMBY -7 NUMBY perception by the general public 

• Uncertainty - uncertainty about future legislation on C02 emissions, .... 

Carbon storage in geologic reservoirs must also overcome the concerns about injecting fluid into a 

space that is already crowded as compared to EOR injections. Using C02 injection for enhanced 

oil recovery has been ongoing for a long time. In EOR, the injection of C02 can be likened to repressurizing the reservoir to an original condition and thereby counterbalances the subsidence that 

could occur from removing the oil. For geologic storage in saline aquifers, the injection amounts to 

over-pressurizing the formation, promoting migration of fluids to other areas. This result generates 

more concerns than for EOR processes. These factors lead to delays in permitting and 

construction, and hence must be considered as a part of the cost and technical readiness of a 

technology. These issues have not been adequately resolved to attract power plant financers to 

invest money in projects with CCS. 

Demonstration Status of CCS Technologies 

The following comments address the theme of the present hearing, namely, has the commercial 

deployment of CCS technologies been "adequately demonstrated" to meet the key criteria of EPA 

cited above. 

Feasibilitv 

As noted above, the feasibility of using amine solutions for capturing C02 has long been 

demonstrated in the chemicals industry. While technically feaSible, the cost of the amine solution 

process is very expensive for power generation. The use of these amine solutions over extended 

duty cycles in coal gas atmospheres needs further development. 

System integration issues are also a concern with regard to the operation of amine towers. The 

process works by trickling the solution down a wall that is exposed to the C02 gas. Most chemical 

plants operate with one tower where instabilities in the falling film of amine caused by the upward 

rush of the C02-laden air can be managed based on operating experience. For a large scale 

power plant, multiple amine towers will be required. Fluid flow instabilities in one tower can affect 

the operation of adjacent towers due to switching air flows in reaction to the tower upsets. This 

situation is one example of integration studies that need to be performed on large scale 

demonstration units before the technology can be said to be adequately demonstrated at 

commercial scale. 

Coal-based IGCC systems have not been demonstrated in sufficient numbers as noted above, 

especially in carbon capture applications. Many of the examples cited in the EPA proposal have 

been for polygeneration systems. Additional research and demonstration is needed for stand-alone 

IGCC power generation systems. 

E:lTestimony to SS&T Committee 2.doc 
37 

Page 60f7 

Long-term storage of C02 in geological reservoirs has not been demonstrated for large volumes of 

injected fluid on a continuous basis. 

As noted above, costs associated with amine capture are high compared to costs that are expected 

to be realized when advanced carbon capture technologies come to fruition. 

Additional costs are incurred due to the social and legal aspects of permitting a CCS power plantstorage field operation. These factors must be considered in assessing the cost of compliance with 

the 1,100 pounds of C02 per megawatt hour standard proposed by EPA. 

The latest pulverized coal plant that is an indication of the state of pulverized coal technology is the 

Turk plant, which is estimated to operate at a rate of 1,800 pounds of C02 per megawatt hour. A 

significant cost and performance penalty will apply to reduce the emissions to 1,100 pounds per 

megawatt hour. Large scale operations of a coupled plant and storage system have not been 

operated sufficiently long to develop cost estimates of a combined operation. 

The cost of using currently available carbon capture technologies is considered to be too expensive 

to be competitive for coal based systems. 

Size of Emissions Reductions 

Given the uncertainties associated with questions of feasibility and costs as noted above, it is likely 

that few if any coal plants will be deployed in the time frame proposed by EPA. Hence, the present 

proposal will not lead to significant reductions as stated by EPA. 

However, if the proposal could be modified to delay the lower C02 emissions requirement, there 

may be opportunities to propose new plants based on technologies that could be developed in the 

near future. Therefore, emissions reductions could result from a delay in implementing the 

standard. 

Technology Development 

As above, if no new plants would be built, there is no driver for developing technology for C02 

capture and storage. It is deSirable to maintain a diverse portfolio of fuels to meet our energy 

needs. Programs that would encourage technology development are essential. Phasing in the 

standards over a longer time would provide a window for developing advanced technologies that 

could be demonstrated on a timely basis to achieve the goals of the EPA proposal. 

Comments on Global Technology Development 

The use of coal for power generation and chemicals production (liquid fuels, fertilizer, chemical 

products, .... ) in China has passed the U. S. usages and the gap between the U. S. and China will 

continue to widen with respect to coal technologies. 

E:\Testimony to SS&T Committee 2,doc 
38 

Page 7 of7 

Chinese planners have been willing to make investments in new technologies through support of 

fundamental and engineering scale research, and development of coal-based systems from large 

pilot plant operations to full scale development. These investments have been made by the 

government or by government-owned industries. 

As a result, China has taken a leadership role in coal-to-chemicals and coal-to-liquid fuels 

production technologies, and is rapidly developing technologies for advanced power generation with 

coal systems and carbon storage. Their next Five Year plan will include a focus on government 

supported CCS activities, with active involvement in geological storage research and 

demonstrations. 

Federal Support for Research and Demonstration Projects 

The U. S. research and development program for coal-based technologies has made progress in 

developing advanced pulverized coal and gasification systems that include higher efficiency 

processes and carbon capture and storage applications. However, more progress needs to be 

made to achieve the goals proposed by EPA. A robust federal research, development and 

demonstration program is needed. 

Advances in fundamental research in developing new materials, new control and integration 

technologies, and advanced cycles offer promise for higher efficiency in terms of power generation 

and in carbon capture and storage. Demonstration programs are more-or-Iess at the first of a kind 

status in developing ideas to the scale where their commercial viability and performance can be 

evaluated. In both of these areas, we need continued and strong support from Congress to ensure 

continued development of coal as a viable fuel for our nation. 

Efficient coal technologies will ensure our energy and economic security by maintaining diversity in 

our portfolio of fuels. As a nation, we can show global leadership by developing and exporting 

technologies that address mounting concerns about carbon emissions. A risk we take by not acting 

in a strong leadership manner is that we will be buying our technology from other nations who are 

more aggressive in developing their technology base. 

Closing Comments 

W~hout the building of new plants, no technology advancement would occur to demonstrate the 

commercial readiness of new carbon capture and storage plants. Investments in a strong research, 

development and demonstration program, coupled with a delayed phase-in of the standards 

proposed by EPA would provide improved opportunities for technologists to meet the challenges 

proposed to us by EPA to improve our environment and economic competitiveness through 

advanced coal technologies. I recommend your consideration for both of these approaches. 

E:ITestimony to SS&T Committee 2.doe 
39 

Richard Bajura, Director 

INVU National Research Center for Coal and Energy 

For the past 28 years, Richard Bajura served in various roles facilitating, leading, and managing energy 

and environment programs in research and technical outreach at West Virginia University. During this 

time, he led seven major interdisciplinary - inter-institutional research programs and multiple WVU 

campus-wide interdisciplinary programs addressing a wide range of energy applications from resource 

extraction to alternative fuels. He is skilled at coordinating and managing research programs involving 

interdisciplinary groups of faculty members. As the Director of the NRCCE, he oversees a research 

enterprise with total annual budget averaging approximately $10 million. As an administrator, he has 

been instrumental in facilitating over $50 million in support for research faculty members at WVU. The 

NRCCE has developed financial and administrative management expertise to coordinate the efforts of 

faculty researchers working on jOint programs. 

In his earlier career as an active faculty member and researcher, Bajura's research interests included fluid 

dynamics and energy processes. His professional service included leadership in the Fluids Engineering 

Division of ASME where he also served as Vice President for the Basic Engineering Technical Group, 

representing one-sixth of the ASME membership and over 40% the Society's technical programs. He is 

currently active on the ASME Energy Committee, and is a member of the National Coal Council, the Coal 

Utilization Research Council (CURC), the Pittsburgh Coal Conference Advisory Board, and the 

Washington Coal Club Board of Directors. He is the Group Leader for the fuels program on the CURC 

Technical Committee for developing a technology road map for coal R&D programs. He serves as a 

technical program coordinator for WVU programs under the US-China Clean Energy Research Center. 

January 2013 

C:\Users\trj\AppData\Local\Microsoft\Windows\Temporary Internet 

Files\Content.Outlook\GQXNBGON\Dr Bajura Bio.docx 
40 

Chairman STEWART. Thank you, Dr. Bajura. 

Our third witness is Mr. Kurt Waltzer, Managing Director at the 

Clean Air Task Force. In this role, he provides oversight and support of organizational management as well as ongoing development 

and implementation of organizational strategy. Mr. Waltzer has led 

the development of incentive policies for carbon capture that have 

been included in Federal legislative proposals and helped lead the 

NGO support for several carbon capture projects. Mr. Waltzer. 

TESTIMONY OF MR. KURT WALTZER, 

MANAGING DIRECTOR, 

THE CLEAN AIR TASK FORCE 

Mr. WALTZER. Chairman Stewart, Chairman Lummis and Ranking Members Swalwell and Bonamici, thank you for the opportunity to testify today. My name is Kurt Waltzer, and I am the 

Managing Director of the Clean Air Task Force, an environmental 

nonprofit dedicated to catalyzing the development and global deployment of low-carbon energy technologies. 

First, let me explain why we believe CCS is needed. The world’s 

power sector annual emissions are expected to double from 12 to 

24 gigatons by mid-century. By 2015, China will have added 900 

gigawatts of coal plants on top of our roughly 300 gigawatts of coal 

plants in the United States. India and other developing countries 

are following suit. Without significant CCS deployment, we simply 

will not be able to achieve the deep reductions in CO2 emissions 

that are necessary to reduce the risk of catastrophic climate 

change. 

Returning to the question in front of the Committee, CCS is technically feasible in the context of this rule because the rule requires 

partial, not full CCS, and because the rule allows a plant up to 

eight years to meet this standard. The 40 percent capture level is 

well within the experience of the technology. Moreover, if a plant 

intends to capture CO2 on the day it opens and can’t because of unforeseen issues with, for example,, completion of a CO2 pipeline, 

the air compliance flexibility provision allows the plant to meet the 

standard over a longer time frame. The partial capture and sequestration requirement and flexibility provisions along with the ability 

to store CO2 in conjunction with enhanced oil recovery, or EOR, 

helps ensure the rule can be met at reasonable cost, even before 

any Federal subsidies are considered. 

CATF undertook an analysis of the initial NSPS rule first proposed in April of 2012. As we can see by figure one on page 8 of 

my testimony, the cost of electricity at a new coal plant that meets 

the partial CCS standard with EOR and takes advantage of the 

regulatory flexibility provision is only 13 percent higher than that 

of a new coal plant without CCS. CCS has been adequately demonstrated over its 40-year history in the United States. Since the 

1970s and 1980s, large industrial plants have captured and stored 

large amounts of CO2 on a per-plant basis up to 7 million tons per 

year. This experience is migrating to power plants. Nearly all new 

coal plants plan to have some level of CCS installed when they 

open. These include projects like the 582-megawatt Kemper plant 

in Mississippi, the Texas Clean Energy project and the Sask Power’s coal retrofit project in Canada, known as Boundary Dam. 
41 

Each of the components of CCS have had a long history of use 

in the United States and around the world. Over 850 megatons of 

CO2 have been stored underground in Texas for EOR operations 

over the last 30 years. There are currently 4,000 miles of CO2 pipeline connecting CO2 with enhanced oil recovery projects. Pre-combustion capture technology has been commercially available since 

the 1950s and 1960s with over 200 plant applications across the 

world, and post-combustion capture has been successfully applied 

to natural gas and coal plants with commercial guarantees offered 

from several vendors. 

Does CATF also support incentives for CCS? Absolutely. Many 

technologies such as SO2 scrubbers that have been deployed based 

on emission limits have continued to receive subsidies in order to 

make the technology more efficient and less costly. The EPA has 

long recognized that such subsidies are appropriately considered in 

evaluating the real cost of a standard. CATF is a member of the 

National EOR Initiative, an unusual coalition of advocacy groups, 

industry and labor organizations that are coming together in support of self-financing production tax credits for CO2 EOR sourced 

by power plants and industrial sources. 

I should note that in addition to EOR’s value in reducing cost, 

it also provides significant potential scale. The National Energy 

Technology Laboratory estimates the technical potential to sequester CO2 through EOR in the United States is as high as 80 million 

barrels, or 4 million barrels a day, and require 20 gigatons of CO2. That represents about half of the total U.S. power sector emissions 

for the next 30 years. 

We believe that EPA’s rules on sound legal and technical footing 

is not the end of coal. Instead, it is the beginning of CCS worldwide. 

I appreciate the opportunity to testify this morning and look forward to answering your questions. 

[The prepared statement of Mr. Waltzer follows:] 
42 

BEFORE THE HOUSE SUBCOMMITTEE ON ENVIRONMENT 

AND THE SUBCOMMITTEE ON ENERGY OF THE 

COMMITTEE ON SCIENCE, SPACE, AND TECHNOLOGY 

TECHNOLOGIES TO MEET EPA'S PROPOSED NEW SOURCE 

PERFORMANCE STANDARD FOR CARBON DIOXIDE 

EMISSIONS FROM ELECTRIC GENERATING UNITS 

TESTIMONY OF KURT WALTZER 

MANAGING DIRECTOR 

ON BEHALF OF THE CLEAN AIR TASK FORCE 

OCTOBER 29TH, 2013 

1 
43 

Chairman Stewart, Chairman Lummis and Ranking Members Swalwell and Bonamici, 

thank you for the opportunity to testify today. My name is Kurt Waltzer and I am the 

Managing Director of the Clean Air Task Force. The Clean Air Task Force is an 

environmental non-profit dedicated to catalyzing the development and global 

deployment of low carbon energy technologies, and other climate protective 

technologies, through research, public advocacy leadership, and partnerships with 

the private sector. 

The purpose of this hearing is to explore the technological requirements of EPA's 

proposed New Source Performance Standard. Before addressing this topic 

specifically, I'd like to make some general points. 

First, wide-scale deployment of CCS technology is vital to averting the worst 

aspects of climate change. Almost two-thirds of the roughly 30 gigatons of C02 

emissions released from human activity can be addressed through CCS technology. 

That's because CCS can be applied to two key emissions sectors-power plants and 

large-scale industrial plants. My remarks today will focus on the power sectors, 

where global emissions from fossil fuel power plants total about 11. 9Gt per year. If 

no action is taken, annual power plant emissions will nearly double (24 Gt) by 2050. 

In developing countries, new coal plants are being built at an astounding rate. By 

2015,900 GW of coal power plants will be in operation in China-three times the 

size of US fleet. The vast majority of these plants are new. The vast majority of these 

plants are new. It is extremely important to drive controls on these plants, in the US and 

abroad, because plants such as these regularly last for fifty years or more, and if such 

development occurs without any control, we simply will not be able to achieve the deep 

reductions in C02 emissions that are necessary to reduce the risk of catastrophic climate 

change. 

Second, wide-use of C02 captured from power and industrial plants is vital to 

driving expanded use of enhanced oil recovery (EaR) in the US that will increase 

US oil production and decrease dependence offoreign oil. EOR recovers oil from 

aging oil field by injecting C02 deep into oil formations. The C02 mixes with the oil, 

freeing it from tight pores in the rock, and moving it to producing wells. EOR 

currently accounts for about 6% of US oil production. But new estimates from DOE 

suggest that there is enough capacity in US oil fields to store half the C02 emissions 

from the power sector over the next 30 years. That would produce almost 80 billion 

barrels of oil, or about 4 million barrels a day, which is over 50% of current US oil 

production. 

Third, despite what some in industry have said, EPA's proposed C02 NSPS 

regulations are not the end of coal, but the beginning ofCCS. In examining the 

proposed EPA's rules, the committee should consider the flexibility in the rule's 

structure and implementation, and how the rule helps drive CCS technology 

adoption. The flexibility of the proposed rules includes these features: 

2 
44 

An emission limit of 1100 Ibs/MWh that can be met through partial, rather 

than full C02 capture. Partial capture is less expensive to implement than full 

capture (90% or more) on power plants. 

The proposed rules allow up to eight years to meet the rule's emission 

standard. This flexibility has a profound and positive impact on new coal 

plants. It means that a new plant can go into operation and if delays with 

establishing storage sites or pipelines are encountered, the plant can 

continue to run. 

So as the subcommittees consider the status of CCS to meet the proposed EPA 

standards, it's key to focus the discussion within the context of the proposed rule. 

The rule is based upon partial, not full capture. The rule provides ample flexibility 

to meet this standard. And as I will describe later, at today's low natural gas prices, 

it is unlikely that any form of new coal plant will be built in the next decade whether 

or not it has CCS controls. Taken together, EPA's proposed rule is clearly a "Best 

System of Emission Reduction" for new coal plantsl. 

I'd like to turn now to the status of CCS technology. 

Status of CCS Technology 

Large, integrated CCS projects began in the United States in the 1970 and 1980s at 

industrial facilities2 where CO2 was sold for enhanced oil recovery (EaR). Some of 

these projects capture and store 1 million tons CO2 per year, 5 million tons CO2 per year, 

and 7 million tons of C02per year. From its beginning in industrial facilities, CCS has 

migrated to power plants where it can reduce CO2 emissions by greater than 90%. This 

combined industrial and power plant experience is significant. In the US we have over 

4,000 miles of existing CO2 pipelines and 40 years worth of experience with injecting 

managing and ultimately geologically trapping nearly a billion tons of CO2 due to CO2 

enhanced oil recovery. 

Because the component pieces of what we call CCS systems have been in widespread 

and safe use, separately, for 40 years or more, they are more than adequately 

1 section 111(a)(1) of the Clean Air Act (CAA) directs EPA to set standards of 

performance that: [R ]eflect the degrce of emission limitation achievable through the 

application of the best system of emission reduction which (taking into account the cost 

of achieving such reduction and any nonair quality health and environmental impact and 

energy requirements) the Administrator determines has been adequately demonstrated. 42 

U.S.C. § 741 1 (a)(1). 

2 These inelude Val Verde natural gas processing plant, Enid Fertilizer project, Shute 

Creek natural gas processing plant, Great Plains Synfuels plant, Century natural gas 

processing plant 

3 
45 

demonstrated to fonn the basis for an emissions standard for power plant combustion of 

fossil fuels. Indeed, the component parts of CCS systems are not only "adequately 

demonstrated" they are commercially available. 

The absence of a U.S. regulatory driver has hampered the expansion of this technology. 

It is hard to convince an investor to put money into controls that are not required, or to 

convince a utility commission to grant rate recovery for investment in pollution controls 

that arcn't rcquircd. That is true even though the enonnous potential for future carbon 

emissions reductions associated with CCS systems makes investment in these systems 

very cost-effective. We need these systems to bc thc nonn in the future, if our country is 

to continue to generate electricity using coal. We are not talking about an expensive 

technology with only marginal benefits. Instead, simply put, CCS systems are the only 

currently available technology that can pennit the use of coal and gas for the production 

of clectricity, at near zero carbon - and conventional air pollution -- emissions levels. 

The migration of CCS technology to the power sector has startcd, and with stronger 

regulatory drivers, this migration will accelerate. Key projects for coal CCS includc: 

The Dakota Gasification Plant (a lignite coal to Synthetic Natural Gas plant) 

located in North Dakota has been using pre-combustion capture technology 

sincc 2000, capturing 90% of its cmissions and shipping it to pennanent EOR 

sequestration in oil fields in Canada. The plant convcrts 18,000 tpd of lignite 

to SNG using gasification technology, capturing 1.8 MT C02/yr using 

Rectisol. The plant has been fully operational since 2000. 

In Kemper County Mississippi, Plant Radcliffc is a new 582 MW coal power 

plant currently under construction. When it opcns in 2014, thc plant will 

capture 65% of its C02 and sequester thcm dccp underground through EOR 

activity. The emissions from this plant are estimatcd at 550 IbIMWWh 

(gross). 

In Odessa Texas, the Texas Clean Energy Project (TCEP) is expected to break 

ground later this year. The 400 MW project will tum coal into base load 

power, and fertilizer, and will produce C02 that will be sequestered deep 

underground through EOR activity. TCEP will capture over 90% of the C02 

it would otherwise emit. The carbon dioxide emission rate for this plant when 

it goes into operation in 2015 will be 2281bIMWWh (gross). 

FutureGen 2.0 is an oxy-combustion plant that will use Babcock & Wilcox 

(B&W) and Air Liquide technology. The 200MW plant will capture 90% of 

its carbon dioxide resulting in 1 MT/yr C02 captured, and will sequester all of 

that C02 in deep saline (non oil-producinglnon-EOR) geologic layers in the 

Mt. Simon fonnation. The plant is expected to come online mid-2016. 

4 
46 

Plant Barry, Alabama- This post-combustion capture demonstration captures a 

slip stream of about 150,000 tons of carbon dioxide per year which is injected 

in a saline formation about 16 miles from the plant. 

Boundary Dam, Saskatchewan, Canada (Sask Power)- This retrofit of capture 

and sequestration technology onto an existing 110 MW pulverized coal unit 

will capture 90% of its CO2 (1 million tons per year) for EaR and saline 

permanent sequestration. Start-up of the CCS controls will begin in late 2013 

and go into full operation in spring of2014. 

Clean Air Act Frame and Costs 

The Clean Air Act's framework recognizes that new sources of air pollution are 

generally in the best position to integrate pollution controls into project designs and 

to invest in new pollution controls. That is why the statute takes a forward looking 

and technology forcing perspective on performance standards, and requires every 8 

year reviews to accommodate advances in technologies that have occurred in 

response to the standards. This approach has been an important contributor to the 

fact that U.S. air quality has gotten consistently better throughout the 40 years since 

the statute was passed in its current form. And it remains true, for CCS technology, 

although the Sask Power retrofit also shows that where an existing unit can 

accommodate it, CCS retrofits on older plants also are possible. 

As noted above the Act directs EPA to set allowable pollutant emissions 

rates/standards of performance that take into account the cost of achieving such 

reduction and any nonair quality health and environmental impact and energy 

requirements.3 

The courts also have articulated this inquiry as ensuring that the costs imposed by 

the standard are not "greater than the industry could bear and survive" but instead 

are costs to which the industry can "adjust" in a "healthy economic fashion to the 

3 The D.C. Circuit has fleshed out this mandate through a series of cases decided across 

several decades. See, e.g., Essex Chern. Corp. v. Ruckelshaus, 486 F.2d 427 (D.C. Cir. 

1973); Nat 'I Lime Assoc. v. EPA, 627 F.2d 416 (D.C. Cir. 1980); Lignite Energy Council 

v. EPA, 198 F .3d 930 (D.C. Cir. 1999). For instance, the court in Essex held that the 

standard must be based on a system ofpollution control that: [H]as been shown to be 

reasonably reliable, reasonably efficient, and which can reasonably be expected to serve 

the interests of pollution control without becoming exorbitantly costly in an economic or 

environmental way. 486 F.2d at 433 (emphasis added). 

5 
47 

end sought by the Act as represented by the standards prescribed." Portland Cement 

Assoc. v. Train, 513 F.2d 506,508 (D.C. Cir. 1975). 

Thus, the statute requires EPA to balance the environmental and economic and 

energy related costs of requiring emissions rate-base performance standards. EPA 

is given a good deal of discretion to do this, although that discretion is not 

unbounded. The cost-effectiveness of any particular standard is particularly 

relevant to EPA's ultimate evaluation of whether the industry can bear the costs, as 

are questions about what the investment in new units in an industry looks like even 

before the standard has issued. 

Here, the fact that CCS offers the opportunity for near zero emissions from coal 

generated electricity production, combined with the fact that the industry, as a 

matter of pure market economics, is now not investing in coal, are going to be 

significant factors. Courts have said that in situations like this, EPA's decisionmaking based on the future of the industry during the regulated period will be 

upheld. Additionally, EPA's past standards have required significant investments in 

controls representing, for example, 12 percent of the full investment in plant, and 5-

7 percent annual operating cost increases, and in other instances lOs of billions ov 

dollars over a 20 year period, and have been upheld as reasonable given the 

pollution benefits to be achieved (and that we today benefit from). So, the relevant 

points in this inquiry are how much reduction in the pollution in question is 

available through application of the standard, and what the relevant price impacts of 

the standard will be where the industry is one that produces a commodity. 

With this frame in mind, and to investigate the price impacts of partial CCS on a 

mid-western coal plant, CATF published a whitepaper in December, 2012 

analyzing the potential cost of EPA's then-proposed 1000 pounds per megawatt 

hour standard for C02, coupled with a longer time frame for compliance.4 The 

analysis is based on cost estimates developed by NETL, but considers the flexibility 

mechanisms in terms of longer term compliance periods included in the initial 

proposed rule and as well as potential income from enhanced oil recovery. The 

current proposal also contains f1exibilities, which are tied to the regulatory period 

of 8 years between review cycles for NSPS, whereas the original proposal included 

a 30 year averaging period for compliance, under which the CCS system needed to 

be operating in year 10. So, while our 2012 report is based on the 30 year 

4 "How Much Does CCS Really Cost? - An Analysis of Phased Investment in 

Partial C02 Capture and Storage for New Coal Power Plants in the United 

States", Clean Air Task Force, December 20,2012. In its initial proposal, the 

Agency allowed for CCS phase in over a 30 year averaging period, wherein the 

partial capture and sequestration system did not need to be operational until year 

10 of the plant's lifetime, and the emissions rate needed to be met over a 30 year 

annual averaging period. The current proposal also includes a longer time frame, 

which is tied directly to the "regulatory period" of 8 years between reviews. 

6 
48 

averaging provision, it still requires immediate work on construction and near 

term operation of the CCS systems. 

CATF's Modeled Cost Estimates Based on Performance Standard 

CATF published a whitepaper in December, 2012 analyzing the potential cost of 

EPA's first proposed NSPS rule from April, 20125• The analysis is based on cost 

estimates developed by NETL, but considers the flexibility mechanisms included in 

the proposed rule as well as potential income from enhanced oil recovery. It's 

important to note these cost estimates included scenarios where developers 

delayed the installation of CCS for up to a decade, based on the proposed rule 

flexibility. Under the current proposed rule, developers would likely delay 

installation seven or eight years at most. Thus while the cost numbers will 

directionally stay the same, they may be somewhat higher than is outlined below. 

CATF will update this analysis based on the most recent proposal in the future. 

The results are summarized in Figure 1 below. We found that the 2017 COE for a 

new natural gas combined cycle plant would be $56/MWh (Case 4), while 

that for a new supercritical coal power plant without CCS would be $100 per 

MWh (Case 0), and that for a new supercritical coal power plant with enough CCS 

to meet EPA's Day 1 standard would be $124 per MWh (Case 1, including 

revenue from sales of C02 for EOR). $124 per MWh represents roughly a 24% 

premium on the price of power the facility owner must charge in order to 

comply with the proposed Day 1 standard by using CCS, if it is assumed to get full 

rate recovery in the investment in the technology. If, however, the investment in CCS is 

delayed by 10 years, and the appropriate anticipatory work is done, a new 

supercritical coal power plant with CCS might be constructed which meets EPA's 

Phased standard for only $113 per MWh, representing only a 13% power price 

premium over the uncontrolled coal case (again after accounting for revenue associated 

with selling the C02 for EOR sequestration). 

For Case 1 (50% CCS from Day 1), without EOR 

For Case 1 (50% CCS from Day 1) without EOR revenue the COE premium is 36% 

(versus 24% with EOR revenue). For Case 3 (70% CCS, Phased approach) 

without EOR revenue the COE premium rises is 19% (versus 13% with EOR 

revenue). These cases are labeled Case Ib and Case 3b, respectively in Table 2. 

Relative power costs for our primary cases are indicated in Figure 1 below. 

5 "How Much Does CCS Really Cost? - An Analysis of Phased Investment in 

Partial C02 Capture and Storage for New Coal Power Plants in thc United 

States", Clean Air Task Force, December 20, 2012 

7 
49 

Figure 1 

Cost Relationship to NSPS 

The Clean Air Act's framework recognizes that new sources of air pollution are 

generally in the best position to integrate pollution controls into project designs and 

to invest in new pollution controls. That is why the statute takes a forward looking 

and technology forcing perspective on performance standards, and requires every 8 

year reviews to accommodate advances in technologies that have occurred in 

response to the standards. This approach has been an important contributor to the 

fact that U.S. air quality has gotten consistently better throughout the 40 years since 

the statute was passed in its current form. And it remains true, for CCS technology, 

although the Sask Power retrofit also shows that where an existing unit can 

accommodate it, CCS retrofits on older plants also are possible. 

As noted above the Act directs EPA to set allowable pollutant emissions 

rates/standards of performance that take into account the cost of achieving such 

reduction and any nonair quality health and environmental impact and energy 

requirements 6• 

6 The D.C. Circuit has fleshed out this mandate through a series of cases decided across 

several decades. See, e.g., Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427 (D.C. Cir. 

1973); Nat 'I Lime Assoc. v. EPA, 627 F.2d 416 (D.C. Cir. 1980); Lignite Energy Council 

v. EPA, 198 F.3d 930 (D.C. Cir. 1999). For instance, the court in Essex held that the 

standard must be based on a system of pollution control that: [H]as been shown to be 

reasonably reliable, reasonably efficient, and which can reasonably be expected to serve 

the interests of pollution control without becoming exorbitantly costly in an economic or 

environmental way. 486 F.2d at 433 (emphasis added). 

8 
50 

The D.C. Circuit has also articulated this inquiry as ensuring that the costs imposed 

by the standard are not "greater than the industry could bear and survive" but 

instead are costs to which the industry can "adjust" in a "healthy economic fashion 

to the end sought by the Act as represented by the standards prescribed." Portland 

CementAssoc. v. Train, 513 F.2d 506, 508 (D.C. Cir.1975). 

Thus the statute requires EPA to balance the environmental and economic and 

energy related costs of requiring emissions rate-base performance standards'. EPA 

is given a good deal of discretion to do this, although that discretion is not 

unbounded. 

The cost-effectiveness of any particular standard is particularly relevant to EPA's 

ultimate evaluation of whether the industry can bear the costs, as are questions 

about what the investment in new units in an industry looks like even before the 

standard has issued. Here, the fact that CCS offers the opportunity for near zero 

emissions from coal generated electricity production, combined with the fact that 

the industry, as a matter of pure market economics, is now not investing in coal, are 

going to be significant factors. Courts have said that in situations like this, EPA's 

decision-making based on the future of the industry during the regulated period will 

be upheld. Additionally, EPA's past standards have required significant investments 

in controls representing, for example, 12 percent of the full investment in plant, and 

5-7 percent annual operating cost increases, and in other instances lOs of billions ov 

dollars over a 20 year period, and have been upheld as reasonable given the 

pollution benefits to be achieved (and that we today benefit from). So, the relevant 

pOints in this inquiry are how much reduction in the pollution in question is 

available through application of the standard, and what the relevant price impacts of 

the standard will be where the industry is one that produces a commodity. 

With this frame in mind, and to investigate the price impacts of partial CCS on a 

mid-western coal plant, CATF published a whitepaper in December, 2012 

analyzing the potential cost of EPA's then-proposed 1000 pounds per megawatt 

hour standard for C02, coupled with a longer time frame for compliance.1 The 

analysis is based on cost estimates developed by NETL, but considers the flexibility 

mechanisms in terms of longer term compliance periods included in the initial 

proposed rule and as well as potential income from enhanced oil recovery. The 

current proposal also contains flexibilities, which are tied to the regulatory period 

7 "How Much Does CCS Really Cost? - An Analysis of Phased Investment in 

Partial C02 Capture and Storage for New Coal Power Plants in the United 

States", Clean Air Task Force, December 20, 2012. In its initial proposal, the 

Agency allowed for CCS phase in over a 30 year averaging period, wherein the 

partial capture and sequestration system did not need to be operational until year 

10 of the plant's lifetime, and the emissions rate needed to be met over a 30 year 

annual averaging period. The current proposal also includes a longer time frame, 

which is tied directly to the "regulatory period" of 8 years between reviews. 

9 
51 

of 8 years between review cycles for NSPS, whereas the original proposal included 

a 30 year averaging period for compliance, under which the CCS system needed to 

be operating in year 10. So, while our 2012 report is based on the 30 year 

averaging provision, it still requires immediate work on construction and near 

term operation of the CCS systems. 

Carbon Capture 

CCS is demonstrated and available for use at new coal- (and gas-) fired power 

plants and its core processes (C02 capture, transportation and sequestration) 

have already been utilized at large scale. 

Pre-combustion capture of C02 is the process by which C02 is removed from the 

syngas ofa gasification plant so that the remainder is mostly hydrogen. A 2010 

U.S. DOE database of gasification projects lists 125 individual coal gasifiers (and 2 

petcoke gasifiers) at 19 commercial projects which are used to produce either 

ammonia, substitute natural gas (SNG), or gaseous feedstock for liquid fuels 

production.8 All three of those processes (ammonia production, SNG, and liquid 

fuels production) entail significant amounts C02 capture as a part of a purification 

process ofthe industrial gas products. The total thermal capacity of these projects 

exceeds 20,000 MW; and some have been operating for decades. 

As noted above, C02 captured at the Dakota Gasification project is transported by 

pipeline to Canada, where it is used for enhanced oil recovery (EaR) and 

sequestered (see more below). C02 from the Coffeyville project is currently 

vented, but reportedly agreements have been signed to transport the C02 to 

Oklahoma for EaR and sequestration. 

Summit's TCEP coal IGCC project in Texas will also use Rectisol®, and it 

was the basis for the C02 emission limits in a May 7, 2012 Indiana Department of 

Environmental Management (IDEM) air quality permit for a proposed gasification 

plant in Rockport, Indiana that would manufacture substitute natural gas from 

coal.9 

In the coal gasification to power process, the C02 must results in elevatedhydrogen syngas, which must be burned in a combined cycle combustion turbine 

to produce electricity for sale. This change presents no unreasonable technical 

challenges to the turbine, however. By 2006 Siemens had already accumulated 

more than 750,000 hours of operation with elevated- hydrogen fuels in 

8 CATF analysis of DOE data. The DOE data is available at 

http://www.netl.doe.gov Itechnologies Icoalpower Igasifi cation Iworlddatabase lind 

ex.html,. 

9 See Permit IDEM No. T147-30464-00060, Condition 0.4.9 (Available at 

http://permits.air.idem.in.gov 130464p.pdf). 

10 
52 

combustion turbines,lo and GE had accumulated over 900,000 hours.ll Another 

turbine and gasification vendor, MHI, also offers an IGCC with Selexol'" to achieve 

60-65 percent CCS.12 As a result, in their evaluation of high-hydrogen combustion 

turbines for the HECA IGCC project with 90 percent CCS, HEI determined that 

"commercial guarantees for F class turbines operating on high-hydrogen fuels 

would be likely."13 

Post-combustion capture is based on aqueous solutions of amines (a family of 

nitrogen compounds similar to ammonia) that are commonly employed in 

industrial processes outside the power generation industry. These systems have 

been applied successfully to exhaust from natural gas (including a combined cycle 

power plant) and coal plants. 

Table 1 

Vendor Location Exhaust Stream C02 Use 

ABB Searles Coal Boiler Chemicals Industry 

Vallev, 

ABB Warrior Run, MD Coal Boiler Food Industry 

ABB Shady Point, OK Coal Boiler Food Industry 

TPRI Shanghai, PRC Coal Boiler Food Industry 

TPRI Beijing, PRC Coal Boiler Demonstration, 

Food 

MHI Kedah Darul Aman, NG fired SR flue gas* Urea production 

Malavsia 

MHI Aonla, India N G fired SR flue gas* Urea Production 

MHI Phulpur, India NG fired SR flue gas* Urea Production 

MHI Kakinada, India NG fired SR flue gas* Urea Production 

MHI Viiaipur, India NG fired SR flue gas* Urea Production 

MHI Bahrain NG fired SR flue gas* Urea Production 

MHI Phu My, Vietnam NG fired SR flue gas* Urea Production 

MHI Fukuoka, Japan NG fired SR flue gas* General use 

MHI Abu Dhabi, UAE NG fired SR flue gas* Urea Production 

MHI District NG fired SR flue gas* Urea Production 

Ghotoki 

10 HEI, HECA Feasibility Study Report #2 - Power Block Gas Turbine Selection (May 29, 

2009) (citing Brown, P., Siemens Gas Turbine H2 Combustionfor Low Carbon [GCC, 

(Oct. 2007)). 

11 Shilling, N., Testimony of Norman Shillingon Behalf of Joint Petitioners in Cause 

No. 43144 Before the Indiana Utility Regulatory Commission (Oct. 24,2006). 

12 Sakamoto, K., "Commercialization oflGCC/Gasification Technology for US Market", 

Oct. 7, 2008. 

13 HEI, HECA Feasibility Study Report #2 - Power Block Gas Turbine Selection (May 29, 

2009). 

11 
53 

MHI Kedah Darul Aman, NG fired SR flue gas* Urea production 

Malaysia 

MHI Plant Barry, AL Coal Boiler Demo (aminel 

Fluor Bellingham, MA, USA Gas Turbine Exhaust Food Industry 

Fluor Lubbock, TX, USA Natural Gas Enhanced 

Oil 

Fluor Carlsbad, NM Natural Gas Enhanced 

Oil 

Fluor Santa Domingo, DR Light Fuel Oil Enhanced 

Oil 

Fluor Barranquilla, Natural Gas Food 

Columbia Industry 

Fluor Quito, Ecuador Light Fuel Oil Food 

Industry 

Fluor Brazil NG / Heavy Fuel Oil Food 

IndusITY 

Fluor Rio DeJa nero, Brazil Steam Reformer Methanol 

Productio 

Fluor Sao Paulo, Brazil Gas Engine Exhaust Food 

Productio 

Fluor Argentina Steam Reformer Urea Plant 

Feed 

Fluor Spain Gas Engine Exhaust Food 

Industry 

Fluor Barcelona, Spain Gas Engine Exhaust Food 

Industry 

Fluor Bithor County, Heavy Fuel Oil Food 

Romania Industry 

Fluor Cairo, Egypt Light Fuel Oil Food 

Industry 

Fluor Israel Heavy Oil Boiler Food 

Industry 

Fluor Uttar Pradesh, India NG Reformer Urea Plant 

Furnace Feed 

Fluor Sechuan Province, NGReformer Urea Plant 

PRC Furnace Feed 

Fluor Singapore Steam Reformer Food 

Industry 

Fluor San Fernando, Light Fuel Oil Food 

Philippines Industry 

Fluor Manila, Philippines Light Fuel Oil Food 

Industry 

Fluor Osaka, Japan LPG Demo Plant 

Fluor Yokosuka, Japan Coal/Heavy Fuel 011 Demo Plant 

12 
54 

Fluor Botany Australia Natural Gas Food 

Industry 

Fluor Alton, Australia Natural Gas Food 

Industry 

Alstom Mountaineer, WV Coal Boiler Demo 

(ammonia 

Alstom Mongstad, Norway NG turbine/refinery Demo 

(ammonia 

Aker Mongstad, Norway NG turbine/refinery Demo 

(amine) 

All of these vendors above, except perhaps for ABB, offer commercial PCC systems 

for coal power projects. In fact, Fluor has said "[t]he Econamine FG+ technology is 

ready for full scale deployment in: Gas- and Coal-fired Power plants,"14 and recent 

commercial activity supports their assertion. A January 2012 front-end 

engineering and design (FEED) study for Tenaska Trailblazer Partners LLC for a 

760 MW (gross) pulverized coal power plant with 85 to 90 percent carbon capture 

to be located in Texas concluded that "Tenaska and Fluor achieved the goals of the 

[carbon capture plant] FEED study, resulting in ... establishment of performance 

guarantees which, after the addition of an appropriate margin, were consistent 

with the expected performance in Fluor's indicative bid:,56 Regarding their postcombustion COz capture, technology, MHI says "[i]t must also be reinforced that 

MHI is NOW ready to provide large scale, single train commercial PCC plants for 

natural gas fired installations (with completed basic design for a 3,000 [tons per 

day] plant train) and intends to leverage this experience for application to large 

scale COz capture for coal fired flue gas streams." 

C02 Pipelines 

There are presently approximately 4000 miles of COz pipeline connecting 

naturally mined and anthropogenic sources of COz with enhanced oil recovery 

projects.1S In total, this system now carries approximately 50 million metric tons 

per year of COz throughput. The Denbury "Green" pipeline, completed in 2009, 

extends from Jackson MS to Houston TX, collecting and delivering both naturally 

mined and anthropogenic COz. 

Based on IGCC and industrial coal gasification projects that were planned in the 

Ohio River Valley, Denbury had proposed 320-mile long extension of the Denbury 

Green pipeline to southern Illinois. While the COz-source projects failed to 

14 Reddy, S., Econamine FO Plus Technology for C02 Capture at Coal-fired Power 

Plants (August 2008). 

15 Advanced Resources International, U.S. Oil production potential from accelerated 

deployment of carbon capture and storage (2010) (Available at http://www.advres.comlpdf/v4ARI%20CCS-C02-EOR %20whitepaper%20FINAL %204-2-I O.pdO. 

13 
55 

materialize (due to several factors including low gas prices and withdrawal of state 

support) the extension would have connected these Midwest anthropogenic 

sources to fields in Mississippi, Louisiana, and Texas. Advanced Resources Inc. has 

estimated that three 800 mile-long pipelines could result in the storage of30 years 

of Ohio River Valley EGU coal plant C02.16 

There are half a million miles of natural gas and hazardous liquids pipelines 

rights-of-way, of which some routes might also provide rights-of-way for the 

build-out of C02 pipeline network. Elliott and Celia (2012)17 have analyzed the 

storage resources in the proximity of the largest U.S. C02 sources in the U.S. - they 

report that large sources emitting 2.2 Gigatons of C02 are located within 20 miles 

of a saline reservoir. 

Geologic Storage 

Decades of experience in enhanced oil recovery (EOR), wastewater injection, and 

natural gas storage, combined with very large geologic C02 storage capacities in the 

U.S., provide confidence that long term CO2 storage is both available and a best 

system of emissions reductions (BSER).18 While commercial-scale deep saline C02 

injection and storage experience is more limited, deep geologic injections and 

storage of wastewater, natural gas and for enhanced oil recovery (EOR) are 

commonplace in the U.S. C02 injection technology is grounded in a half- century of 

oil industry C02 management expertise. Moreover, natural gas companies 

routinely use deep geologic storage for natural gas reserves at over 400 sites in the 

U.S. injecting and storing natural gas in saline aquifers, depleted natural gas 

reservoirs and salt deposits. Including geologic wastewater injections, billions of 

tons of fluids are injected each year in the U.S.19 Capacities for deep geological 

storage of C02 amount to hundreds, if not thousands of years, of present day C02 

emissions rates. The U.S. Department of Energy's North American Carbon Storage 

Atlas (NACSA) released in 2012 estimates that there are approximately 500 years 

16 Kuuskraa, V., Advanced Resources International, Challenges of implementing largescale C02 enhanced oil recovery with carbon capture and storage (201 0) (Available at 

http://web.mit.edu/mitei/docs/reports/eor-csslkuuskraa.pdf). 

17 Elliot T.R. and Celia M.A., Potential restrictions for C02 sequestration sites due to 

shale and tight gas productioni, 46 Environmental Science and Technology, 4223-4227 

(2012). 

18 Benson, S., Monitoring carbon dioxide sequestration in deep geological formations for 

inventory verification and carbon credits, Society of Petroleum Engineers SPE paper 

102833 (2006) (Available at 

http://www.energy.utah.gov/govemmentldocs/forum/dec2006/spe 1 0283 3 .pdf). 

19 Wilson, E. et al., Regulating the ultimate sink: managing the risks of C02 storage, 37 

Environmental Sci. & Tech 3476-3483 (2003). 

14 
56 

of storage capacity for C02 emissions in North America.2o Geologic formations that 

can accept C02 are widespread in the U.S., particularly in states that are rich in coal 

reserves. This means that where power plants are built close to coal resources, 

they will also be proximal to deep geologic storage resources. Furthermore, 

substantial capacity and transportation and injection infrastructure are currently 

available in EOR fields in the parts of the Rocky Mountains, Midwest, Southeast and 

parts of California. Cooperative research in the western U.S. is wisely evaluating 

development of storage resources near existing C02 pipelines. 

Seismicity 

An MIT report from April 2012 assessed the availability of geologic storage in the 

U.S., taking into account both geology and the fluid mechanics of injected C02, 

concluded that CCS is a geologically viable climate change mitigation option and that 

CCS can playa "major role" within the portfolio of climate change mitigation options 

even when taking into account pressure limitations21. MIT's model-based 

assessment of storage capacity for C02 captured from the power sector serves to' 

counterbalance some of the broad, poorly supported assertions concerning pore 

pressure-based limitations and related seismic risk oflarge scale CCS made by 

Zobrak and Gorelick in their June 2012 piece. Such pressure limitations were also 

identified as a potential- but unknown - risk factor for induced seismicity in the 

National Academy of Science's June 2012 Report entitled "Induced Seismicity 

Potential in Energy Technologies". The MIT Report's analysis demonstrates that 

ample storage capacities are available for current and future power sector C02 

emissions, even taking into account the purported pore pressure limitations. 

Unlike Zobrak and Gorelick's commentary, which based its analysis solely on the 

Illinois basin, the MIT Report's analysis is based on storage supply curves for 11 

sedimentary basins across the U.S., utilizing a model that accounts for C02 migration 

and trapping physics during the injection and storage process. Exh. Supp-2 at 5186. 

The MIT Report estimates that pressure-limited storage capacity for existing and 

future fossil fuel-fired power plants (including coal and natural gas) in the eleven 

identified basins would be adequate to stabilize C02 production from power 

generation for a century or more. This will continue to be true even if fossil fueled 

energy production continues to increase at current rates. Moreover, and 

20 Press Release: "Energy Department Announced New Mapping Initiative to 

Advance North American Carbon Storage Efforts" (May 12012) (Available at 

http://energy.gov larticles lenergy- department-announces-new-mapping-jnitiatjyeadyance-north-american-carbon-storage. The 2012 North American Carbon 

Storage Atlas is available at: 

http://www.netl.doe.goy/technologies I carbon seq IrefshelflNACSA20 12.pdf. 

21 Szulczewslki, M., et aI., Lifetime of Carbon Capture and Storage as a Climate-Change 

Technology, PROCEEDINGS OF THE NATIONAL ACADEMY OF SCIENCES Vol. 109, No. 14, at 

5185-89 (April 3, 2012). 

15 
57 

· significantly, the eleven basins identified in the MIT report do not make up the 

entirety of potential saline storage basins in the U.S. Because the MIT Report 

describes only the sequestration potential capacity in those eleven U.S. basins, it 

underestimates U.S. COz storage potential, as it does not take into account either the 

capacity available in offshore geologic formations or from next generation EaR 

projects. 

Storage Regulations 

A national regulatory framework now exists to support a determination that CCS is 

the best system of emissions reduction for any industry using that technology, and 

that CCS will be deployed in an environmentally protective manner. In 2010, EPA 

established a well class specifically designed for the geologic sequestration of COz 

under the Federal Underground Injection Control program (mC). Federal 

Requirements Under the Underground Injection Control (UlC) Program for Carbon 

Dioxide (C02) Geologic Sequestration (GS) Wells, 75 Fed. Reg. 77,230 (December 10, 

2010). These wells, deemed "Class VI" wells, are designed to ensure that injected 

C02 remains in a specified area and that COz is properly monitored. EPA has also 

issued multiple guidance documents for Class VI wells that cover a variety of topics 

including, monitoring and testing, site characterization, area of review evaluation 

and corrective action, well construction, and financial responsibility.22 

C02 sequestration may also concurrently occur in enhanced oil recovery (EaR) 

operations. mc Class II injection permits are required for injections of COz for EaR, 

and a process is available to obtain Class VI permit coverage for full-scale 

sequestration after oil production operations cease. See 40 C.F.R. §144.19 (2012). 

Furthermore, under the U.S. Tax Code, 26 U.S.c. §45Q(d)(2), tax credits are 

available for those owners or operators who successfully sequester COz from 

atmospheric release. 

Therefore, facilities that utilize CCS must do so within a regulatory framework 

that ensures the C02 is properly accounted for, and has been isolated from 

atmospheric release, as well as that sequestration is occurring in a way protective 

of underground sources of drinking water. Where operators opt to conduct 

geologic sequestration of COz, as a part of or after conclusion of EaR operations, 

monitoring and reporting occurs pursuant to EPA's Greenhouse Gas Reporting 

rule under Subpart RR, 40 C.F.R. §98.440 et seq. (2012) (Geologic Sequestration of 

Carbon Dioxide). 

The SDWA mc Class VI and CAA Subpart RR rules, taken together, provide 

protection of underground sources of drinking water (USDW) and an accounting 

2Z See EPA, Geologic Sequestration Guidance Documents (available at 

http://water.epa.gov /type /groundwater /uic/class6 /gsguidedoc.cfm) 

16 
58 

mechanism for measuring and crediting a source with the amount of C02 that is 

sequestered from atmospheric release. 

17 
59 

Kurt Waltzer is the Managing Director for the Clean Air Task Force. He is 

responsible for ensuring that CATF has the capabilities it needs to carry out its 

vision and mission, and that these capabilities are deployed with consistent 

excellence. In this role, he oversees and supports organizational management 

and administrative activities, as well as the ongoing development and 

implementation of CATF's strategy and development of new efforts. 

In addition to management responsibilities Kurt also spends a dedicated portion 

of his efforts focused on the goals and strategies of CATF' Fossil Transition 

Program. He bas been a long-time advocate for advanced fossil and CCUS in the 

environmental NGO community and has been working to promote it over the 

last 12 years within the US and globally. Kurt has led the development of 

incentive policies for CCUS that have been included in federal legislative 

proposals. He's also helped develop a powerful informal network of companies 

and experts on advanced fossil and CCUS, and helped facilitate private sector 

collaborations in this space. 

Kurt has authored and co-authored several reports and articles and managed 

economic analyses on climate technology and air pollution. He's presented at 

and participated in several CCSICCUS technical and policy working groups, and 

testified before legislative committees and regulatory agencies. 

Prior to CATF, Kurt worked for the Pew Center on Global Climate Change in the 

area of state-based clean energy business development policy, coordinated a 

campaign of Midwestern ENGOs focused on the reduction of coal power plant 

pollution for the Izaak Walton League of America, and led the clean energy 

program for the Ohio Environmental Council from 1997 to 2002. He has served 

on the Keystone Energy Board and the Technical Advisory Committee for the 

Ohio Coal Development Office. He has a Masters in Business Administration from 

the University of Michigan and holds B.S. degrees in both Economics and Biology 

from the Ohio State University. 

18 Tremont St., Suite 530 1 Boston, MA 021081 www.catf.us 1617.624.0234 
60 

Chairman STEWART. Thank you, Mr. Waltzer. 

Our final witness then is Mr. Roger Martella, Partner of Sidley 

Austin Environmental Practice Group. He rejoined Sidley Austin 

LLP after serving as General Counsel of the United States Environmental Protection Agency, concluding ten years of litigation and 

handling complex environmental and natural resource matters at 

the Department of Justice and EPA. Mr. Martella served as EPA’s 

Chief Legal Advisor, supervising an office of 350 attorneys and 

staff in Washington and 10 regional offices. Mr. Martella, welcome. 

TESTIMONY OF MR. ROGER MARTELLA, JR., 

PARTNER, ENVIRONMENTAL PRACTICE GROUP, 

SIDLEY AUSTIN 

Mr. MARTELLA. Thank you, Chairman Stewart, Chairman 

Lummis, Ranking Member Bonamici and Ranking Member 

Swalwell for the opportunity. I am honored to be before you today 

with my distinguished witnesses, speakers as well. 

I am going to try to very briefly discuss the intersection of how 

these technical issues connect with the legal framework and try not 

to give you an entire legal dissertation on this but just hit the high 

points, and I will be happy to answer any questions you have. 

Very briefly, the whole reason we are here arises out of a 2007 

decision called Massachusetts versus the EPA by the Supreme 

Court, and in that decision, the Supreme Court said that EPA had 

to consider greenhouse gases alongside the other air pollutants in 

the Clean Air Act. I was general counsel at the time when the decision came down and was tasked with working with the EPA lawyers, most of whom are still there, and other talented lawyers in 

the Federal Government on coming up with a full range of legal options on how to implement the mandate in the Supreme Court’s decision, and one of the things we looked at very closely, which was 

in a 2008 document released by EPA at the time, is the New 

Source Performance Standard program. If you look at, you know, 

the limited tools EPA has under the existing Clean Air Act to address greenhouse gases for stationary sources, the New Source Performance Standard program clearly stands out. It is the most flexible of the provisions. It has a history of driving environmental results. It considers cost-benefit considerations, and of course as we 

have talked about today, I think as everyone is familiar with, Congress directed EPA to focus on standards that were adequately 

demonstrated. 

So it is pretty obvious if you look at the 2008 document and work 

that has been done since that the highlight, the focus of attention 

on addressing greenhouse gases under the Clean Air Act has been 

on the New Source Performance Standard program when it comes 

to stationary sources, and so my critique is not with that as a general proposition, my critique is how EPA specifically proposed to go 

about this in September based on some of the technical concerns 

you are hearing today, and I am just going to again focus on the 

two words that matter the most for today’s discussion, the words 

‘‘adequately demonstrated.’’ 

There is a maxim the law that when Congress uses specific 

words, it has to mean something, that you have to actually pay attention to the specific words that Congress provides in the statute, 
61 

and I recognize that that is never necessarily a black-and-white 

thing, that everything is a continuum and even something such as 

‘‘adequately demonstrated’’ does not lock anyone into any one interpretation but a continuum of interpretations unless you otherwise 

say that we shall do something or have to do something. So the 

question here is, where on the continuum does EPA’s approach fall, 

and it is my position, it is my opinion that given the technical expertise of the folks here and other people that I have spoken to, 

that this does fall past the end points of what is considered adequately demonstrated, the notion of requiring a technology is adequately demonstrated that is not currently in operation by EPA’s 

own record where EPA has said there is not a single facility in 

commercial operation today. About 18 months ago in April 2012 in 

the predecessor proposal they said that this technology was not 

likely to be adequately demonstrated for another ten years, that 

even if we look back on the last 30 months of EPA’s experience in 

granting permits for greenhouse gas emissions across the country, 

that it has actually rebuffed arguments by certain groups that CCS 

is currently adequately demonstrated. It came as a surprise to me, 

and I think it is past the continuum for them to say back in September that currently carbon capture and sequestration is within 

the realm of options they can consider in saying something is adequately demonstrated. 

Now, having said that, there has been some conversation already 

today about what is the precedent of this and what is the effect of 

this, does this really affect anyone, and I think the concern as a 

whole is from the precedential perspective for a few reasons. First 

of all, the result of this rule, if this rule is finalized as it exists, 

and I think it is fair to say that no coal-fired power plant could be 

built in the United States unless they could really demonstrated 

carbon capture and sequestration of the magnitude EPA requires, 

and the experts to my side here, some of them seem to think that 

is not possible. So the precedent of that is basically that this rule 

would have the effect of preventing an entire source of energy from 

being used in new facilities in the future, and so I think one of the 

questions that comes up is, is that within the legal authority of the 

Clean Air Act? Can the Environmental Protection Agency—did the 

Congress intend for EPA to have that kind of authority to say we 

are going to basically phase out this type of energy going into the 

future. And while I recognize there is not an apples-to-apples comparison in terms of how this rule could impact existing sources or 

even sources in other sectors, I think it also has to be understood 

that there is no doubt that everyone is going to be looking to this 

rule as the baseline for how EPA will approach existing sources 

and how they might approach other sectors. I don’t think they are 

going to start with a clean drawing board but they are going to be 

looking to other approaches here, even if it is not carbon capture 

and sequestration. So I think there is little debate that this will 

have precedent on how they are going to approach other issues, 

others types of facilities. 

So thank you for that, and I look forward to answering any questions you might have. 

[The prepared statement of Mr. Martella follows:] 
62 

EPNs New Source Perfonnance Standard for Electric Generating Utilities: 

Dissecting the Legal Rationale for a Policy Driving Rule 

Roger R. Martella, Jr. 

Sidley Austin LLP 

Chainnan Stewart, Chainnan Lummis, and Ranking Members Swalwell and 

Bonamici, thank you for providing me the opportunity and the honor to appear 

before you today. 

The subject of today's hearing is critically important because it addresses both the 

technical and legal basis for what I believe is the most important and impactful 

regulation of the Obama Administration's Environmental Protection Agency: The 

New Source Perfonnance Standard for Greenhouse Gases from Electric Generating 

Units (hereinafter, the EGU NSPS). I commend the Subcommittee for addressing 

this issue at a key time, and look forward to assisting your ongoing efforts. 

We should be exceedingly proud that in the more than 40 years since Congress 

enacted the Clean Air Act, the United States simultaneously has promoted the 

healthiest skies and the strongest economy in the world. Congress in the Clean Air 

Act provided EPA specific mechanisms and tools to achieve the policy and science 

based goals the Agency deems necessary to fulfill its environmental mandate, but 

within the context of a specific and strict legal framework that the law's provisions 

delicately articulate. As EPA proceeds to address climate change using a law that 

was enacted without consideration for the unique and fundamentally distinct 

circumstances of greenhouse gas (GHG) emissions, these existing legal authorities 

are being put to new tests. While, as a general proposition, I do not take issue with 

EP Ns authority under the New Source Perfonnance Standard program to address 

GHG emissions under appropriate circumstances, the Agency's chosen path in the 

proposed EGU NSPS, by EP Ns own admissions, surpasses the bounds of its legal 

authority into the realm of arbitrariness and capriciousness. Congress, in enacting 

the Clean Air Act, and Section 111 in particular, strictly limited the Agency's 

authority to control air emissions from stacks and did not authorize EPA to do 

what it proposes to do here and phase out an entire source of energy in the United 

States. 

By way of background, I am both a lifelong environmentalist and a career 

environmental lawyer. I am very proud to have spent the majority of my career in 

public service, as a trial attorney in the Justice Department's Environment Division, 

as the General Counsel of the United States Environmental Protection Agency, and 
63 

as a judicial law clerk on the Tenth Circuit Court of Appeals. In my current 

capacity as a private practitioner, I am privileged to work with a plethora of 

stakeholders including private companies and trade associations, environmental 

organizations, and the government, to develop creative solutions that advance 

environmental protection while also enabling the United States to retain economic 

competitiveness in a trade sensitive, global environment where very few 

economies provide even the faintest glimmer of our own environmental controls 

and public process protections. 

In both my government and private careers, I am very proud of the opportunities I 

have had to participate in and advance environmental rule of law initiatives, 

working to help develop the enactment of environmental and public participation 

laws in growing economies. In particular, I am proud to serve as the co-chair of the 

International Bar Association's Climate Change Justice and Human Rights Task 

Force and vice-chair of the American Bar Association's Sustainable Development 

Task Force. Last year I was honored to have served as one of five American Bar 

Association delegates to the United Nations at the Rio+20 sustainable development 

conference in Brazil, and this year was one of five ABA delegates to the World 

Justice Forum on environmental and climate change justice issues. 

During my tenure as EPA General Counsel, the Supreme Court decided the 

landmark case Massachusetts v. EPA. In brief, the 5-4 decision compelled EPA to 

consider the regulation of greenhouse gases alongside other''air pollutants'under the 

Clean Air Act. Shortly after the decision, President Bush and the White House 

tasked me to oversee the development of legal options and authority for 

promUlgating the first-ever national GHG controls in the United States under the 

Clean Air Act. Working with the talented group oflawyers in EPA's Office of 

General Counsel and other federal agencies, I formulated a full range of legal 

options, along with associated pro and con considerations. 

As part of this assessment, I came to appreciate certain advantages of utilizing 

Section 111 of the Clean Air Act--ile New Source Performance Standards provisiOflover the various options available to address GHGs from stationary sources. When 

applied appropriately, NSPS can be the most effective tool for driving 

environmental results and emission reductions while considering the costs and 

benefits on those subject to such controls, the economy, energy security, and, 

ultimately, consumers. In fact, I advised that if EPA were compelled to regulate 

GHGs from utilities, NSPS should be the preferred mechanism to pursue among 

the existing Clean Air Act options given its flexibility, its history of realizing 

2 
64 

environmental results, and the statutory mandate to consider demonstrated 

technology and weigh costs and benefits ofthe promulgated standards. 

Thus, given my history, experience, and perspective regarding Section Ill, it is 

with regret that I offer my opinion that the NSPS EGU proposal EPA released in 

September steps beyond the legal bounds of the authority Congress established in 

the Clean Air Act. 

As other witnesses have testified today, the approach EPA proposed in the EGU 

NSPS raises numerous technical and policy concerns for coal and pet coke fired 

EGUs. In setting a performance standard of 1,100 pounds ofC02/MWh, the 

proposed NSPS relies on two technical assumptions: (1) that the single bestperforming Integrated Gasification Combined Cycle (IGCC) facility in the nation 

is the representative baseline for the coal and pet coke EGU industry as a whole; 

and (2) that carbon capture and storage is'adequately demonstrated'technology 

today. Relying upon these technical assumptions, EPA's proposed NSPS 

establishes the 1,100 pounds C02/MWh performance standard, a standard which 

no commercial coal or pet coke facility in the United States if not anywhere in the 

world can come close to meeting. Thus, as a policy ramification, the proposed 

NSPS has the practical effect of being as much an energy regulation as an 

environmental regulation given its impact of phasing out any new coal or pet coke 

facilities from being built in the United States. 

I defer to today's witnesses to address the technical and policy ramifications of this 

proposal, and instead focus on several key legal deficiencies based strictly on the 

record upon which EPA relies in the Rule. (The EGU NSPS raises numerous legal 

questions beyond the scope of this testimony, but given the focus of to day's hearing 

I am focusing specifically on the legal ramifications of the technology questions 

that are at issue today.) 

Lefs start with the language in the Clean Air Act itself. The opening provision of 

Section III defines a"standard of performance'as 

a standard for emissions of air pollutants which reflects the degree of 

emission limitation achievable through the application of the best system of 

emission reduction which (taking into account the cost of achieving such 

reduction and any nonair quality health and environmental impact and 

energy requirements) the Administrator determines has been adequately 

demonstrated. (emphasis added) 

3 
65 

Although the intersection of this text with EP Ns proposal raises scores of legal 

questions and issues, for today's purposes my focus entirely is on two simple 

words: "adequately demonstrated:' Although lawyers frequently deserve a 

reputation of making simple things more complicated than they need to be, I will 

resist that temptation today. "Adequately demonstrated'simply means what it says, 

and there is no need to go further to understand the fundamental and fatal flaw in 

EP Ns proposal. 

First, to base an emissions standard for all coal facilities on lGee technology runs 

counter to a long standing EPA precedent that EPA cannot require facilities to 

'h:rlefme the source:' In other words, EPA itself long and consistently has 

recognized that it is not the Agency's role to dictate or switch the type of facility 

and energy source any given project is to utilize, but instead to identifY the best 

system of emissions reductions for the type of source that is proposed by the 

project developer. IGee units, which use combustion turbines, have significantly 

different designs than coal-fired boilers. Thus, EPA departed at the outset from 

established past precedent in utilizing a baseline that mandates the type of source 

facilties are required to build. 

Second, and the primary focus oftoday's hearing, EPA clearly erred in requiring 

ees under Section 111 given that, by the Agency's own admissions, the 

technology is not"adequately demonstrated;' To be clear, EPA itself in the proposal 

concedes that no coal fired boiler has ever been in commercial operation with ees or achieved the proposed limit. Simply stated, EPA in the record does not point to 

a single operating facility in the United States-trin the worlMhat is currently 

utilizing the technology that it says is "adequately demonstrated;' It similarly fails to 

point to any commercial source that even comes close to meeting the standard that 

it requires as"adequately demonstrated;' Importantly, EPNs prior proposed rule 

from April 2012 did not project ees to be adequately demonstrated for another 10 

years. This proposed rule claims that ees is currently demonstrated, but provides 

no explanation of why EPA changed its outlook so dramatically in less than 18 

months. Finally, beyond the record of this specific rulemaking, EPNs proposed 

standard also is entirely inconsistent with the Agency's last 30 months of issuing 

GHG pennits for new facilities under the Prevention of Significant Deterioration 

program. 

To address these legal inconsistencies, EPA provides an extensive legal 

justification for utilizing NSPS to develop'~volutionary'new technologies. I do not 

dispute that one element of many environmental standards is a technology-driving 

consideration, even if such technology comes with a significant cost for the 

4 
66 

regulated community, and that such standards legitimately can serve dual purposes 

simultaneously of driving emissions reductions while promoting the development 

of important new technologies. However, even when EPA is allowed to promote 

technology driving standards to some extent, Section III does not delegate carte 

blanche authority to simply mandate new technologies that do not satisfy the 

statutory mandate of "adequately demonstrated:' Those two words are explicit, 

intentional and cannot be disregarded. It is not necessary to look any further than 

EP Ns record in the proposed NSPS to conclude that the technologies EPA would 

require are not"adequately demonstrated'today, and thus violate the letter and the 

law of Section 111. A lengthy and complex legal justification in and of itself 

cannot compensate for a disregard of the plain language of the text of the statute, 

and EP Ns legal advocacy cannot fix a conclusion that is arbitrary and capricious 

under the Act. 

Finally, beyond the legal ramifications of this proposal on new EGDs, it is critical 

to anticipate and appreciate the potential precedent of this Rule on other types of 

facilities. First, once EPA finalizes this rule, certain groups are likely to argue that 

this standard"sets the floof'for so-called Best Available Control Technology 

(BACT) standards for facilities that are required to obtain a pre-construction permit 

under the Prevention of Significant Deterioration (PSD) program. Thus, this 

standard has the potential to cascade to other sources not directly regulated by the 

NSPS and where IGCC and CCS bear even less relevance. 

Second, EPA has committed to regulating GHG emissions from existing EGUs no 

later than June, 2016. If EPA were to apply a similar legal interpretation to 

existing facilities of requiring retrofits of technology that is not adequately 

demonstrated, existing EGDs may be required to fuel switch given that 

Administrator Gina McCarthy has recognized that CCS is not an available retrofit 

technology for existing sources. Such decisions will be unpractical and 

uneconomic for many existing facilities, leading to shut downs, reliability 

concerns, and cost increases. Notably, there is a very strong legal argument that 

EPA has authority to avoid the regulation of existing sources under the NSPS 

program in the first instance and thus avoid triggering the ramifications of 

imposing an energy efficiency standard on the nation's existing utility fleet. This 

argument-hat EPA is precluded under Section lll(d) from regulating existing 

sources that are subject to Section 112's controls for Hazardous Air Pol1utant5--i> the 

straightforward reading of the text of the Clean Air Act and would enable EPA to 

address GHG emissions from new sources while regulating other emissions from 

existing sources pursuant to established programs such as the PSD permitting 

system and National Emissions Standards for Hazardous Air Pollutants. 

5 
67 

Third, it is critically important to consider the impact of the EGU NSPS on other 

NSPS source categories. EPA has signaled-ifnot committed--1h1t it plans to regulate 

the GHG emissions of other source categories through NSPS. However, such 

other source categori~ch largely represent the nation's manufacturing sectorsare fundamentally distinct from EGUs. First, EPA must make separate and distinct 

'b:ldangerment'determinations for each source category and decide, under Section 

Ill, whether the emissions from a specific source category pose a''significant' 

contribution to endangerment. Second, unlike utilities, the processes employed by 

most manufacturing source categories are unique and distinct for each facility, 

prohibiting across the board regulation of energy use or efficiency. Third, most 

other source categories are trade exposed, meaning that the impact of GHG 

regulations on a particular source category. could merely lead to such industry 

being located to other areas of the world that are less energy efficiency, resulting in 

net increases in GHG emissions globally. For these reasons, EPA should clarify 

that nothing it does regarding utilities shall serve as precedent for other source 

categories that are fundamentally distinct. 

Thank you for the opportunity to share my views on this important topic. I would 

be happy to answer any questions. 

6 
68 

ROGER MARTELLA is a partner in the Environmental Practice Group at Sidley Austin llP. He 

rejoined Sidley Austin llP after serving as the General Counsel of the United States 

Environmental Protection Agency, concluding 10 years of litigating and handling complex 

environmental and natural resource matters at the Department of Justice and EPA. 

Mr. Martella's practice focuses on three primary areas. First, Mr. Martella advises companies on 

developing strategic approaches to achieve their goals in light of rapidly developing demands to 

address climate change, promote sustainability, and utilize clean energy. Second, Mr. Martella 

handles a broad range of environmental and natural resource litigation and mediation. Third, 

Mr. Martella advises multinational companies on compliance with environmental laws in the 

United States, China, the European Union, and other nations. 

Mr. Martella counsels approximately 40 of the world's leading conventional and renewable 

energy, industrial, transportation, agricultural, forestry, and technology companies on bet-thecompany environmental issues, regulatory matters, and litigation including transitioning to an 

era of legal controls addressing greenhouse gas emissions, increasingly stringent pollutant 

controls, alternative and clean energy, hydraulic fracturing, and sustainability both in the United 

States and abroad. 

The 2013 edition ofThe International Who's Who of Business lawyers lists Mr. Martella as one 

of the ten leading environmental lawyers in the world. The 2013 edition of Chambers includes 

Mr. Martella among its top-tier Washington, DC's environmental and national Climate Change 

lawyers and Chambers Global recognizes Mr. Martella as one of the top Climate Change lawyers 

globally. 

Mr. Martella graduated from Vanderbilt law School, where he was Editor in Chief of the 

Vanderbilt law Review, and Cornell University, where he studied environmental science. 

Following law school, he clerked for the Hon. David M. Ebel of the Tenth Circuit Court of 

Appeals. 
69 

Chairman STEWART. Thank you, Mr. Martella. 

To all of the witnesses, thank you for your testimony. I would 

like to remind Members that Committee rules limit the questioning 

to five minutes, and the chair at this point will open up the round 

of questions, and the chair recognizes himself for five minutes. 

Mr. Martella and Mr. McConnell, I would like to come back to 

some comments that both of you have made. Mr. Martella, you said 

something I think a little more graciously than I would have in the 

sense of the meaning of words. I think that this all started a few 

years ago perhaps when we heard that famous phrase, ‘‘It depends 

on what the meaning of the word is is.’’ Redefining words away 

from their original and their obvious intent opens up just a Pandora’s Box of craziness. Who knows where it will end, and who 

knows what the outcome eventually is going to be, which is the 

main point of this hearing. This isn’t about climate change. This 

hearing isn’t about the government shutdown and effects of that. 

It is not even about the costs of implementing this rule. This is 

about—and by the way, I have enormous concerns with the costs 

of implementing this rule, but we are not there yet. This is about 

one thing and one thing only: is the EPA being honest in their 

claim that a certain procedure has been adequately demonstrated. 

And in that, it is not adequately modeled, it is not adequately hypothesized, it is not adequately wished for. Is it adequately demonstrated? And demonstrated in the real world and demonstrated 

in a way that could be replicated somewhere else and in fact replicated in a lot of different places because it is going to have to be 

in order for it to be implemented like that. 

So with that, Mr. Secretary, I would like to come to you for just 

a minute. Let me ask first just some background. When did you 

leave your position at DOE? 

Hon. MCCONNELL. February this past year. 

Chairman STEWART. And how long did you work for the current 

Administration? 

Hon. MCCONNELL. Two years. 

Chairman STEWART. Okay. And I am sure that was a great experience for you, working for the Administration, and being here 

today, I suppose, you and I had a chance to have a short conversation before the hearing, and I recognize it may be somewhat uncomfortable for you in the fact that you have taken a position that 

is contrary to the current Administration. 

Hon. MCCONNELL. Oh, I don’t find it difficult at all. It is a truth 

that we are pursuing here, and the commercial viability and technical demonstration is all about what we were doing and continue 

to do with a pretty sizable Federal funding of the R&D that is 

going on. Now, it seems to me to be a little difficult to balance the 

fact that if something is already technically demonstrated and commercial available, why we would continue to fund R&D in that regard, it is a bit of a conundrum and it is puzzling to me. 

Chairman STEWART. Well, I appreciate that. That is a great 

point. 

To any of the witnesses, are any of you aware of any commercialscale power plant in the United States that is using CCS right 

now, anywhere in the United States? 
70 

Mr. WALTZER. Mr. Chairman, Plant Berry at First Southern 

Company supplies CCS on their units, a 25-megawatt project, and 

they are capturing about 100, 150,000 tons per year. 

Chairman STEWART. Okay, and 25-megawatt, is that a small- or 

a large-scale power plant? 

Mr. WALTZER. It is a slipstream project from the power plant. 

Chairman STEWART. So it is a very small production of power 

that is generated from there relatively speaking? 

Mr. WALTZER. From that unit, yes. 

Chairman STEWART. And that is really one of the primary concerns we have, and that is, the demonstrated scalability. You know, 

I was a pilot for a long time. I was the type of pilot at one point 

where we few test flights, and I am telling you, you can’t take 

something and say it works here on this scale and then increase 

that scale by many factors and just assume that it is going to work 

exactly the same way; it won’t, which is again one of our primary 

concerns here. 

Dr. Bajura, you mentioned that as well, the scaling up of technology. I would be interested in your thoughts on that and your 

concerns about trying to apply something that is as unique and 

complicated as it is and just assume—and if I could, and then I will 

allow you to answer this. Quoting from the EPA’s own findings 

from just several year ago, a typical power plant, ‘‘there is considerable uncertainty,’’that is their word, ‘‘considerable uncertainty associated with capacities at volumes necessary.’’ Doctor, do you have 

comments on that? 

Dr. BAJURA. Yes. We often test technologies from test tube size 

in a laboratory to pilot plant sized to commercial size. The comment you made earlier about the size of plants, we have put in 

place 12 plants in the last six years. The average size is one 

gigawatt. That is 1,000 megawatts. We don’t do that casually. We 

do it by building up, and the reason we do that is, we learn things 

as we go from one size to another, the integration being the very 

important part. 

Chairman STEWART. Thank you. And again, I think the point 

there is stated in one fashion or another by the EPA themselves, 

that there is enormous concerns with the scalability on this, and 

with that, my time is expired. 

We now turn to the Ranking Member, Ms. Bonamici. 

Ms. BONAMICI. Thank you very much, Mr. Chairman, and thank 

you all for your testimony. 

Mr. Waltzer, I wanted to talk a little bit with you about the different standards that we have been hearing about today. We have 

heard commercially available, technically ready, but the EPA really 

does look at whether the technology is adequately demonstrated, 

which of course is different in legal terms. Do you agree with that? 

Mr. WALTZER. Absolutely. The Clean Air Act very clearly allows 

EPA to consider how the technology applies and other related industries, and I think in some areas there is a bit of a gray area 

relating to your earlier question, Mr. Chairman. So for example, 

Dakota Gasification is an excellent example of a project which is 

a very large scale, captures 2 million tons of CO2 per year and 

sends it up a pipeline to Saskatchewan for EOR and sequestration. 

The methane that comes out of that coal gasification project is de-
71 

livered in the pipeline to power plants. It is very similar to a power 

plant that was proposed by Tanaska, which would have simply 

taken that same industrial configuration and put the power plant 

closer to that methane, the coal-to-methane project. So from a practical perspective, it is not—the Dakota Gasification plant, I believe, 

clearly demonstrates that one could develop a power plant today 

with commercial guarantees with CCS. In fact, even though Kemper does have commercial guarantees, I think the Dakota Gasification plant clearly demonstrates that CCS at a power plant configuration is in operation today. 

Ms. BONAMICI. Thank you. I am going to follow up on that a bit. 

If finalized, the rule would require that all new coal plants meet 

an emission rate between 1,050 and 1,100 points of CO2 per megawatt-hour. So that is an approximate 40 percent reduction below 

uncontrolled emission levels, as I understand it. 

Mr. WALTZER. That is right. 

Ms. BONAMICI. But in addition, the rule allows for up to eight 

years to meet the standard. Can you discuss how that provision 

was considered in EPA’s determination of feasibility and cost? 

Mr. WALTZER. Sure. That provision is, from our perspective, one 

of the key aspects that makes this rule— the design of this rule 

very smart and speaks to the technical feasibility of being able to 

comply with the rule. With that eight-year provision, that allows 

a project developer to do two things. First, it allows them to have 

flexibility as their building their first, second, third or nth-of-a-kind 

project. It also allows the developer market flexibility to be able to 

take advantage of operating the plant in the early years without 

CCS and adding CCS later, which might provide financial value. In 

fact, it is that second component which allows, as our cost analysis 

shows, for a project to be able to comply with that standard and 

have the cost of electricity at that coal unit be 13 percent above the 

baseline cost of electricity for an uncontrolled coal unit. 

Ms. BONAMICI. Thank you. I have another question I want to get 

in. So there was a project that American Electric Power was doing. 

Their chairman in 2011, Michael Morris, said that ‘‘As a regulated 

utility, it is impossible to gain regulatory approval to recover our 

share of the cost for validating and deploying the technology without Federal requirements to reduce greenhouse gas emissions already in place. The uncertainty also makes it difficult to attract 

partners to help fund industry share.’’ So I wanted you to address 

briefly the—unless we require carbon emission limits on new coal 

power plants, does the technology stand as much of a chance of 

wider deployment, and why? 

Mr. WALTZER. Well, I do agree with that, but let me address one 

important aspect of what you just raised. I would urge the Committee to consider that in fact this rule is good for the coal industry, and let me explain that counterintuitive view. First, the rule 

provides both certainty and flexibility for new coal plants regarding 

CO2 emissions. If you don’t have that certainty, you are not going 

to be able to finance new coal plants. No financing, no plants. It 

is basically that simple. Second, the rule does something that 

might have been hard to imagine 30 years ago. For the first time, 

new coal plants and new gas plants are going to have the same 

emissions profile. That is important for coal’s long-term sustain-
72 

ability. And third, gas prices are so low that no one is building new 

coal, and that is true without CCS, but this rule helps catalyze 

technology advancements so that when fuel prices are more advantageous, coal is even better positioned within the market. 

Ms. BONAMICI. Thank you, and I see my time is expired. Thank 

you, Mr. Chairman. 

Chairman STEWART. Yes, Ms. Bonamici. And Mr. Waltzer, you almost by yourself require that we come back to a second round of 

questioning because I can’t wait to engage you with your comments 

there about this is good for the coal industry. 

With that, then we turn to the chairwoman of the Subcommittee 

on Energy, Ms. Lummis. 

Chairwoman LUMMIS. Thank you, Mr. Chairman. 

Secretary McConnell, does it make any sense to you that EPA is 

concluding that CCS is adequately demonstrated or proven when 

the DOE modeling assumes carbon capture technology is unproven 

at commercial scales? 

Hon. MCCONNELL. No, it doesn’t make any sense to me, and in 

fact, in 2010, a roadmap was put forth that with demonstration 

projects and the development of the fossil program would produce 

a commercially ready, technically deployable CCS value proposition 

for the marketplace by 2020, and the expectations were that the 

demonstration projects, the knowledge, the understanding and the 

learnings that would be accomplished through all of that would 

produce something that would be marketplace-ready by 2020. And 

declaring it ready now, I don’t see as something that makes any 

sense to me, no. 

Chairwoman LUMMIS. Mr. Waltzer, you mentioned this eight 

year period. Is that what Mr. McConnell is referencing? Should I 

be drawing a connection between the eight years that you mentioned and Mr. McConnell’s statement about the year 2020 applicability? 

Mr. WALTZER. Madam Chairman, from our perspective, just a 

quick reference. The original proposal actually had a ten-year 

delay. That was in the revision that was made eight years because 

that comports with the eight-year review period that relates to 

New Source Performance Standards. So I think that is really what 

is the—what is driving the eight-year review or flexibility provision 

within this rule. 

Chairwoman LUMMIS. Okay. So they are very different. I am trying to compare apples to oranges here. 

Mr. WALTZER. Right. 

Chairwoman LUMMIS. That is helpful. So if the technology is 

ready today, why the eight years again? 

Mr. WALTZER. From our perspective, we think it is valuable because we want to see projects built, and we think that kind of flexibility encourages projects. It reduces their costs. It provides them 

flexibility as they are developing pioneer projects. We like to say 

we want to avoid pioneer penalties. We want early-adopter rewards, and this, I think, is in vein with that concept. 

Chairwoman LUMMIS. Okay. So it is a pioneer situation? 

Mr. WALTZER. For any project that—well, there are multiple pioneer situations. For example—— 
73 

Chairwoman LUMMIS. But how does the word, your use of the 

word ‘‘pioneer’’ comport with the EPA’s definition of ‘‘adequately 

demonstrated’’? 

Mr. WALTZER. Well, ‘‘adequately demonstrated’’ as I mentioned 

before can be related to—or can refer to related industries. So, for 

example, I would consider—even though we have a fully commercial-scale gasification project at Dakota Gasification that is taking 

CO2 and sending it up to Alberta—excuse me, Saskatchewan. 

Locadia proposed a substitute natural gas program in Indiana, 

which is very similar. And we were supportive of that project because even though it wasn’t a power project, it would have created 

a pipeline from the Midwest to the Gulf Coast. I would consider 

them a pioneer even though that technology is commercial. 

Chairwoman LUMMIS. I think you said CCS is being used today 

on natural gas units? 

Mr. WALTZER. CCS—well, CCS has been used on natural gas 

units for power plants. 

Chairwoman LUMMIS. Okay. So why not require this rule be applied to gas? Why is it just applied to coal? 

Mr. WALTZER. We are actively supporting CCS on natural gas 

projects. So, for example, Summit Power has a—— 

Chairwoman LUMMIS. So why did the EPA just require it for 

coal? 

Mr. WALTZER. Well, from our perspective, and I will speak from 

our perspective, we see—we don’t see this rule as the last step; we 

see it as the first step. So—— 

Chairwoman LUMMIS. Oh, okay. That is helpful. 

Mr. WALTZER. For the eight year review, we would—— 

Chairwoman LUMMIS. Dr. Bajura—excuse me because I have one 

more question. Dr. Bajura, the Interagency Task Force on CCS 

identified five barriers to commercial deployment of CCS. What has 

changed in the two years since their conclusion? 

Dr. BAJURA. We have done some experiments to demonstrate 

storage at larger scale but we haven’t done any integration to show 

how we could put that together with a power plant nor have we 

addressed the issue of long-term liability: who owns the CO2 for 50 

years, who is going to take the responsibility for certifying that the 

technology was correct when it was put in the ground. 

Chairwoman LUMMIS. I want to thank all of our panelists. I hate 

to interrupt but my time is expired. Thank you all for being here. 

I yield back, Mr. Chairman. 

Chairman STEWART. Thank you, Madam Chairwoman. 

The chair now recognizes Mr. Swalwell. 

Mr. SWALWELL. Thank you, Mr. Chairman, and actually, if we 

could put slide number one back up there, and Mr. Waltzer, good 

morning, thank you to you and all of our witnesses for being here. 

Slide one, I held it up earlier, and it will be on the screen in a moment, depicts about 600 coal plants across the country. Are you familiar with this map and these plants, and would you agree, Mr. 

Waltzer, that the proposed regulations that the EPA have put out 

will not affect a single plant that is on that map? 

Mr. WALTZER. Absolutely. Even before this rule was contemplated and even before gas prices went through the floor, there 

was no new coal plant that was proposed without CCS. Any new 
74 

coal plant today that has been seriously proposed will meet the 

new coal plant standard. For existing units, this rule doesn’t apply 

so it is not going to have any effect on them. 

Mr. SWALWELL. And Mr. Waltzer, how many jobs at existing coal 

plants will be lost because of these regulations for future plants? 

Mr. WALTZER. There will be no—I think it is simple logic that if 

the rule does not apply to existing units, it will not affect jobs at 

existing jobs, so no jobs. 

Mr. SWALWELL. And Mr. McConnell, would you agree that these 

regulations will not affect a single job at a currently existing plant? 

Hon. MCCONNELL. No, I wouldn’t. 

Mr. SWALWELL. Okay. Would you agree—so it is your position 

that if I have a job today at a coal plant that is already in existence, I am at risk of losing my job at that plant because of rules 

for plants that have not been built? 

Hon. MCCONNELL. I think if we focus the argument strictly on 

one particular pollutant criteria, we could build an argument 

around it but it is much more complex than that. It is the future 

uncertainty of rulings. It is the combination of NOX, SOX, sun particulates, mercury, all of the criteria pollutants and the landscape 

associated with that uncertainty going forward. You see a tremendous amount of retirements going on across the country today, 

some 50 gigawatts of retirement. 

Mr. SWALWELL. But Mr. McConnell, the 600 plants that are in 

existence, you agree, these rules do not directly affect those plants? 

Hon. MCCONNELL. No, I don’t. Again, as I go back to the interconnection of all the rulings and the future uncertainty of it, that 

has a multiplying effect to the future of all of those coal plants. 

Mr. SWALWELL. But you can’t give me an accurate number as to 

how many jobs are going to be lost at a current plant because of 

regulations for future plants, can you? 

Hon. MCCONNELL. No, I am not able to provide that kind of information, no, sir. Again, it is all part of the future that you or I 

can’t predict. 

Mr. SWALWELL. And you would agree, though, that 120,000 jobs 

lost in 16 days during a government shutdown, that is probably 

greater than the amount of jobs we can say will be lost at existing 

plants? 

Hon. MCCONNELL. I am not in a position to comment on that. 

Mr. SWALWELL. I would hope, though, Mr. McConnell, that you 

could comment on something I think you and I may agree upon, 

which is that sequestration has affected our ability to make necessary investments in technology when it comes to carbon capture, 

use and storage technologies. Would you agree that that is not 

helping us learn more about what that technology could do? 

Hon. MCCONNELL. What I could agree on was that when I took 

the job in 2010, and we projected for the next ten years that we 

would stay at a certain level of funding for fossil energy, to move 

forward and to achieve a commercially demonstrated technology by 

2020, and then seeing the fossil budget cut year over year with the 

Administrator’s requests going down while the overall Department 

of Energy goes up, that made it very difficult to achieve those targets, and makes it all the more difficult to understand how we can 
75 

get demonstrated technology in place any earlier than 2020 certainly. 

Mr. SWALWELL. Thank you, Mr. McConnell. 

And Mr. Waltzer, can you just go into detail for us about the current competition between the coal and natural gas industries and 

whether that competition is at least a partial reason, if not the primary reason, for the retirement and lack of construction of new 

coal plants across the country? And then can you just let us know 

what would the cost of doing nothing be? Suppose we threw out 

these regulations and just did nothing, what would the cost to the 

environment and economy be? 

Mr. WALTZER. So here is what I would say. Project developers 

today are building natural gas plants instead of coal plants, primarily because of where gas prices are. That is what is happening 

in the market. In terms of existing units, gas prices had gotten so 

low that we for the first time ever had seen coal power switch over 

to natural gas, which many of us thought would ever happen, but 

that is starting to come back. So as gas prices are going up, we are 

starting to see coal—existing unit coal generation come back on the 

system. But because of where gas prices are, we don’t foresee, or 

at least looking at the market, the market tells us there are no 

plans for developing new coal projects because of where gas prices 

are today. 

Mr. SWALWELL. Thank you, and Mr. Chairman, I yield back the 

balance of my time. 

Chairman STEWART. Thank you, Mr. Swalwell. You know, regarding your question about existing power plants and will they be 

affected, I think Mr. Waltzer, you answered that question in the 

previous round, and that is when you said you view this as just the 

beginning, and I think that is many of the fears that so many of 

us have. 

With that, to the Vice Chairman, Mr. Bridenstine. 

Mr. BRIDENSTINE. Well, thank you, Mr. Chairman. I can tell you 

there are two coal-fired power plants in Oklahoma that are being 

shuttered because of EPA regulations, and I can also tell you that 

my constituents are facing 25 percent increases in their prices because of it, and these coal-fired power plants have, like, 30 years 

left in their useful lives and we are shuttering them because of 

these regulations. 

I would like to talk to Mr. Waltzer. You mentioned early-adopter 

rewards. Can you talk about that for just one second? 

Mr. WALTZER. Sure. We would like to see—from our perspective, 

we want to see CCS move forward and we would like to see a suite 

of policies that help both deploy the technology and drop its costs 

rapidly. 

Mr. BRIDENSTINE. Is the Kemper project one of those projects 

where you have seen early-adopter rewards? 

Mr. WALTZER. Well, in some respects, Kemper has received incentives, Federal incentives, to move forward. So in that context, 

it has gotten—— 

Mr. BRIDENSTINE. I would like to read you an article from the 

Wall Street Journal, and this is just a few weeks ago, Monday, October 14th, as a matter of fact. Mississippi Power’s 186,000 customers who live in one of the poorest regions of the country are 
76 

reeling at double-digit rate increases, and even Mississippi Power’s 

parent, Atlanta-based Southern Company, has said Kemper 

shouldn’t be used as a nationwide model. Do you agree with that? 

Mr. WALTZER. I believe that the cost overruns associated with 

Kemper are not related to CCS. It is related to the fact that there 

are commercializing a new gasification technology, and so from 

that perspective, I believe Kemper could be a model for integrating 

CCS onto power systems. 

Mr. BRIDENSTINE. It is interesting you should say that. They said 

that their cost overruns are from labor costs, steel pipe, concrete, 

other materials, and certainly if it wasn’t for CCS, a lot of these 

materials wouldn’t be required. Is that correct? And labor. 

Mr. WALTZER. I think most of the labor costs and piping that you 

are referring to really is based on the fact that they are effectively 

developing a refinery technology, which is not what power companies are used to doing. 

Mr. BRIDENSTINE. So these costs, do you know how they are affecting not just—I mean, we are talking about some of the poorest 

people in America being affected by this. They spend a good portion 

of their budgets more as a percentage of their income on their electric bills, and their electric bills are going up. Do you have sympathy or empathy for them? 

Mr. WALTZER. I think that it is important to make sure that anytime we are moving technology forward, that we try to have the 

least amount of impact on the people who can least afford it. I 

think that is true in the United States and I think that is true 

globally. That is why we are supporting not just these performance 

standards but incentives at the Federal level that will help reduce 

the costs—— 

Mr. BRIDENSTINE. Real quick, I want to talk about these incentives. I am a Navy pilot and I flew in Meridian, Mississippi. I lived 

there for a period of time. I can tell you this, Meridian, Mississippi, 

just south of Kemper County, is not a wealthy part of the country. 

Mr. Newburn Atkinson, a gentleman, says that his Lucas Road art 

and jewelry gallery hasn’t recovered from the recession. ‘‘I am already on a shoestring budget and this economy,‘‘ the 66-year-old 

says, ‘‘and this may be the deciding factor in me staying open.’’ So 

here we have people saying that power plants are not being shuttered; in fact, they are. We have people saying that this is actually 

an early-adopter rewards program, which it isn’t. It is punishing 

people. It is punishing the poor people. It is also punishing the investors, which prevents investment in further technologies like 

this, and then you talk about incentives. Let us talk about incentives. 

We have a chart—do we still have that chart, the Department of 

Energy chart about incentives for R&D for different areas? Do we 

have that chart? Well, while we are waiting for the chart to come 

up, I will share with you what is on this chart. On this chart, you 

have incentives for natural gas and liquid petroleum on the left. It 

is almost nothing. It is 64 cents per megawatt-hour. Nuclear is 

$3.14 per megawatt-hour. Wind, $56 per megawatt-hour. And then 

solar on the far right, if the chart were big enough, it would go 

through the roof. For wind, it’s $775 per megawatt-hour, or 64 

cents for gas. Now, do you think it would be a good idea to maybe 
77 

shift some of those incentives from wind and solar maybe over to 

the gas and fossil fuel side? 

Mr. WALTZER. We think we should have more incentives on the 

fossil fuel side, absolutely. 

Mr. BRIDENSTINE. But you don’t think it should be taken from— 

you know, it is 1,400 times more on solar energy. Do you think that 

that might be a good place to start? 

Mr. WALTZER. We are not—here is what I can say what we support. We support, as I mentioned before, the National EOR Initiative, which is focusing on a production tax credit for CO2-enhanced 

oil recovery from coal plants, gas plants, industrial sources, and 

what is really unique and interesting about that proposal is that 

because you are generating petroleum through EOR in the United 

States, you are also displacing foreign-oil production. That potentially could add new revenue to the U.S. Treasury, and so that is 

a really unique and interesting opportunity, and we think we 

should pursue that. 

Mr. BRIDENSTINE. I am out of time, Chairman. It is your mic. 

Chairman BRIDENSTINE. Thank you. I am going to return time 

now to Mr. Takano. 

Mr. TAKANO. Thank you, Mr. Chairman. 

Improving air quality and reducing greenhouse emissions is a 

matter that is vitally important to my constituents in Riverside 

County, which is located in southern California. I represent an 

area that has some of the worst air quality in the Nation. I remember days growing up when we weren’t allowed to play outside on 

the playgrounds during my elementary and high school days for 

physical education class because the air pollution was so bad. It is 

because of the Clean Air Act and the work by the EPA that my region has seen a tremendous improvement in air quality. In fact, a 

study by the EPA shows that by 2020, the benefits of the Clean Air 

Act will outweigh the costs by more than 30 to one. The Clean Air 

Act has helped improve public health, and by 2020 it is expected 

to prevent 17 million lost workdays. 

I appreciate hearing from our witnesses today about EPA’s latest 

effort to limit greenhouse gas emissions under the Clean Air Act. 

My first question is for Mr. Waltzer. Mr. Waltzer, do you know of 

any other nations that are investing in CCS technology? 

Mr. WALTZER. Yes, several. The United Kingdom, for example, 

has a competition for what they call a contract for differences to 

build at least two large-scale CCS projects. But probably the most 

interesting and notable is China. They are investing quite a bit in 

CCS. In fact, Huaneng Power, their largest power company, has developed their own CCS technology that they are currently doing a 

feasibility study with Duke Energy on one of the Gibson units in 

Indiana to examine how those costs of CCS in China, which they 

claim are fairly low, about $30 a ton, would equate in the United 

States. 

Mr. TAKANO. And can you tell me about the overall budget for 

R&D for all of these all-of-the-above technologies? I mean, I understood that chart presented by my colleague from Mississippi about 

the distribution of R&D investment but what has been the size of 

that budget over the last 3 or four years and has it been increasing 

or decreasing? 
78 

Mr. WALTZER. Well, the overall size of the DOE budget has been 

increasing but I would echo what Secretary McConnell said with 

respect to CCS. We believe that the DOE’s budget on CCS should 

be increased. 

Mr. TAKANO. Now, you used the word ‘‘pioneering’’ in your answer to my colleague from Wyoming. Would you say that the strategy of the Department or the EPA is really about birthing this 

technology, that when we say we have an adequately demonstrated 

technology that really the rule is designed to birth it? 

Mr. WALTZER. That has been a role that the Clean Air Act has 

played through several pollution control technologies, and we feel 

that this is a role it can play here. Just to clarify some earlier remarks I made, we do see this as the first step. We do think CCS 

ought to be applied on natural gas units and another opportunity 

to do that will be in the eight-year review as well as looking at best 

available control technology through individual permits after the 

New Source Performance Standards are finalized. So we do see this 

as the beginning of a process. We don’t necessarily anticipate that 

this is going to apply to existing units through any rules that are 

going to be put forward but we do hope and expect and we would 

advocate for in the future that this technology would be applied to 

natural gas. 

Mr. TAKANO. Now, real quickly, the Kemper plant is a coal gasification plant, but the existing coal plants, which will not be affected 

by this rule, are not attempting to gasify. They just strictly use the 

coal directly into the production of electricity. Is that correct? 

Mr. WALTZER. Right. Most existing units are coal combustion 

units. 

Mr. TAKANO. So when you talked about the increased costs at 

Kemper, it has to do with this newer attempt, this attempt to try 

to gasify the coal, but if coal plants in the future were to be 

straight combustion plants, you are contending that the CCS technology has been demonstrated in other areas and could work in the 

context of newer coal combustion plants? 

Mr. WALTZER. Well, actually, yes. In fact, the Boundary Dam 

plant is an interesting example because, in fact, it is a retrofit, but 

it is using the same technology that one would use if one were 

building a new coal combustion plant. Similarly, NRG in the 

United States is currently developing a retrofit, a CCS retrofit 

project, that could also apply to new coal combustion units. 

Mr. TAKANO. Thank you, Mr. Chairman. My time is up. 

Chairman STEWART. Thank you, Mr. Takano. 

Now Mr. Weber from Texas. 

Mr. WEBER. Thank you, Mr. Chairman. 

I think we are going to affect coal plants because as that technology gets so expensive, more plants won’t be built and older 

plants will retire, employees will lose their jobs, so that is a given. 

And look, I think it was Mr. Martella that said when Congress uses 

words, it means something. I think that was you that said that. Is 

that right, Mr. Martella? 

Mr. MARTELLA. Yes. 

Mr. WEBER. I appreciate that. It is kind of like, if you like your 

doctor, you can keep your doctor. If you like your insurance, you 

can keep your insurance. That is kind of what you are driving at, 
79 

I suspect, and I guess that oil sequestration is an okay word, or 

carbon sequestration is okay, but when you talk about budget sequestration, that is a bad word. So it is interesting that we see a 

lot of word games going on up here. 

Let me ask you, are any of you familiar with the Valero plant 

in Port Arthur, Texas, in my district that has a carbon sequestration facility? Mr. McConnell, are you aware of that plant? Do you 

know the cost that was involved? Do any of you all know the cost 

of that plant? Let me give it to you real quickly. The Valero project 

cost $431 million, okay? The Department of Energy, through the 

stimulus, or what I call the spend-from-us, kicked in $284 million. 

Now, that is 66 percent of the cost of that plant. Does that sound 

it is capable of being duplicated? Does the government have to 

spend 66 percent of these facilities and these plants? Does the taxpayer get to be on the hook? Does that sound like it’s capable of 

being duplicated? That is a rhetorical question. I will get back to 

you. 

Ed Holland, the CEO of Southern Energy, the owner of the plant 

built in Kemper, Mississippi, came and spoke to the House Energy 

Action Team, which I am a member of, about a month ago, and 

here is what he—let me tell you something about Southern Energy 

and the plant they are building. Four billion dollars. It creates 

12,000 direct and indirect jobs for construction, 1,000 direct and indirect permanent jobs. The project construction will create $75 million in state and local taxes, $30 million annually in state and local 

taxes. So this is a project that is extremely important and valuable 

to the community, and yet because of CCS, which Texas is a pioneer. One of you, I think it was you, Mr. Waltzer, or it might have 

been Mr. Martella that said there was already EOR underway. In 

other words, what you really said without knowing it was, industry 

was already on this. Industry was already on this without the mandate from the EPA because they will get it to work efficiently. They 

will make it work efficiently. 

Now, when Ed Holland from Southern Energy came and spoke 

to the House Energy Action Team, he said CCS is not capable of 

being duplicated. The cost overruns were enormous, and he attributed it to CCS. Now, to their credit, the company agreed to pick 

up all the cost overruns, and you don’t see that very often when 

the government mandates something. That is a rarity. But the cost 

overruns were attributed to CCS. He told us that in the House Energy Action Team. 

Now, with what you know about Valero’s costs, 66 percent picked 

up by the DOE, the taxpayers, and the cost overruns at Kemper, 

is there anyone on this panel that thinks that is really capable of 

being duplicated? Mr. McConnell, yes or no? 

Hon. MCCONNELL. Well, I believe that is the reality of where we 

are today because it is not technically demonstrated and commercially available. 

Mr. WEBER. Thank you. Dr. Bajura? 

Dr. BAJURA. I support Secretary McConnell’s comment. 

Mr. WEBER. What he said. Mr. Waltzer, what they said? 

Mr. WALTZER. Can you clarify? 
80 

Mr. WEBER. Do you think those two experiences demonstrate 

that CCS of that magnitude, on the scale that the EPA is mandating here, is capable of being duplicated? 

Mr. WALTZER. I think we have seen CCS on the scale of 7 million 

tons per year at projects like Valero. 

Mr. WEBER. Does the cost or the cost overruns not even come 

into the EPA’s—— 

Mr. WALTZER. That is a purely commercial project. 

Mr. WEBER. That is a purely commercial project, so when it 

comes, EPA is real big about attainment; we don’t want noxious 

gases and we want most of the country to be in attainment, but 

they don’t use the common sense of determining from a cost basis 

whether it is going to negatively impact industry and jobs. So 

would you agree with me then, Mr. Waltzer, that in that instance, 

EPA might themselves when it comes to common sense be in nonattainment? 

Mr. Martella, do you think that is duplicable? 

Mr. MARTELLA. I have to put my lawyer’s hat back on, and as 

a lawyer, you can only look at the record and what EPA itself relies 

upon in making these determinations, and I go back to my original 

opinion. Looking simply at things that they said in this record in 

the past 18 months or so, I think it is their own admissions that 

show none of these facilities are in commercial operation to the—— 

Mr. WEBER. Was that admission or emission? 

Mr. MARTELLA. Admission. 

Mr. WEBER. Okay. Well, they are putting out some emissions all 

right, the EPA is. But I appreciate that opinion, and I am overrun 

on my time. 

Chairman STEWART. Thank you. 

We now have Ms. Edwards. 

Ms. EDWARDS. Great. Thank you, Mr. Chairman, and to our 

Ranking Members as well for holding this hearing, and thanks to 

our witnesses. 

I just have a couple of questions I want to try to get to, but I 

want to point out that contrary to some suggestions that have been 

made here today, the President’s energy strategy in fact has embraced the all-of-the-above approach. He said that on many occasions, even when some of us didn’t want him to say all of the 

above. Indeed, the rulemaking envisions, I think, a 21st century 

approach to fossil fuel power plants with the goal of reducing CO2

emissions in new power plants, and I think it is important to point 

out the word ‘‘new.’’ In the Recovery Act, the President committed 

$1.4 billion to this technology, even in the face of some of us who 

questioned frankly the technology, but that being as it might, the 

EPA has come up with a rule. It has a specific responsibility, a particular responsibility to protect our health and environment, and 

while industry considerations are interesting, that is not the principle responsibility of the EPA. But I happen to think that we can 

do both, that we can both protect the environment and we can grow 

jobs and we can grow an energy strategy that really embraces all 

of those responsibilities. 

My question, first question, goes to Mr. McConnell. Something 

you said kind of caught my attention about the jobs question. Were 

you referring to a specific empirical study, university study, indus-
81 

try study, that points to the number of jobs that would be lost by 

applying standards to new power plants versus old? 

Hon. MCCONNELL. I can’t quote any specific study here, only that 

I have been exposed to a number of studies from several different 

sources. 

Ms. EDWARDS. If you can get back to us on that and give us the 

particular studies, because I am a data person and I like to see the 

data that backs up your conclusions that jobs would be lost by applying the rule to new power plants versus old ones, and I would 

like to see those numbers. 

And then my next question goes to Mr. Waltzer. I notice that in 

the industry, the oil and gas industry receives subsidies to the tune 

of about $7.5 billion a year. Exxon Mobil made $7.5 billion in profits in 2012, Occidental, $7.1 billion. The numbers are really huge. 

It seems to me that if we have an interest in doing what Mr. 

McConnell points out in his testimony is the need to add $100 million a year into demonstrating these projects and research and development that $100 million could come out of that $7.5 billion in 

subsidies that the industry receives, and so I wonder, Mr. Waltzer, 

if you could tell us what the additional needs you see in terms of 

investment in R&D and whether we have made the kind of investments we need to go into the commercial side with these coal 

plants and the new regulations? Because if, for example, we needed 

to find more money, perhaps my colleagues on the other side in 

this very constrained environment would be willing to remove 

those oil and gas subsidies so that we could put the money into 

demonstrating new technologies. 

Mr. WALTZER. Thank you. Let me first go back to what we think 

is the most important objective. We think that CCS needs to be deployed globally and it needs to be affordable. So we need to move 

the technology forward as quickly as possible. So that brings us 

back to with respect to the oil industry, enhanced oil recovery as 

an opportunity in the United States. We could potentially have 100 

gigawatts of coal plants, about a third of our coal plants, supplying 

CO2 for EOR that would produce domestically produced oil if we 

met the technical potential for EOR in this country. We believe 

that a self-financing tax incentive is a very smart and effective way 

to move that technology forward. 

What is interesting about that number, 100 gigawatts, is, if you 

look with the history of scrubbers and other technologies, that—you 

can significantly push the cost down the cost curve of that scale. 

It is also going to bring new technologies into the market. So in 

terms of research and development, two interesting technologies, 

just an example. One is called chemical looping, which would dramatically increase the efficiency in coal plants and dramatically reduce the cost of CCS. Another would be advanced natural gas turbines. There is at least one company that has a design that would 

significantly drop the cost of CCS to the point they think they can 

compete in the market today. So it is that sort of mix of performance standards and incentives that could pull those new technologies into the market while getting the learning curve moving 

forward, and that is our vision for how we think we move this technology in the United States and how we think—and the value that 

that is going to have globally. 
82 

Ms. EDWARDS. Thank you, and my time is expired, and so I 

would really love to see us move to a point where we are making 

investments through our tax code that are about new technologies 

and not just supporting an old industry that is making record profits. Thank you. 

Chairman STEWART. Thank you, Ms. Edwards. 

We now turn to the former full Chairman, Mr. Hall. 

Mr. HALL. I thank you, Mr. Chairman, and I really do think if 

we are having this hearing and working together, and if I understood your purpose, it is a little bit different to the five minute dissertation that Mr. Waltzer just gave us. It is not about gigawatts 

or anything else that he wants to decide but I think yours is about 

honesty and whether or not the EPA has been honest with this 

Committee and honest with the people. That is the first thing I 

say. 

I also admire Mr. McConnell, who chose truth as his purpose and 

his pursuit, and he is here with us today, and I want to point out 

that we did have hearings from the EPA during the time of my 

chairmanship. I think, Mr. Rohrabacher, we had them two or three 

times before us, and each time they testified for days and went all 

over the country looking for someone that would testify that 

fracking was ruining the drinking water, and if you are looking for 

honesty you can check them on that because either Mr. Rohrabacher or I asked the four who were administrative witnesses that 

came here, each of them testifying to the dangers of that, and the 

liberal press talking about the dangers of it. We asked this question in closing: can you tell us anywhere in the United States 

where fracking has ruined one glass of drinking water. Each of the 

Administration witnesses said no, all four of them. That is a 

record. You don’t have to have somebody come in here and testify 

to that again. It is a record. They themselves said that. So they are 

not being honest with us, and I think if we get a President that 

will appoint a secretary of some of his administrations that will follow the law, why, we will take a good look at some of their testimony when they come before us and testify under oath, and they 

were reminded that they were under oath, that they were operating from the best science. 

Let me get to something a little more. This hearing sheds light 

on the technological basis for the EPA’s conclusion that CCS has 

been ‘‘adequately demonstrate’’ in its proposal that CCS should be 

required for new coal-burning plants. Once again, the testimony 

has shown that the EPA’s proposed mandate reflects flawed judgment again. I might ask you, Mr. McConnell, if you would like to 

expand on that. 

Hon. MCCONNELL. Well, just to be brief, when something is mandated and determined to be technically demonstrated, commercially 

available and it isn’t, that makes it impossible for industry to make 

an investment, and by virtue of that, it will eliminate the ability 

to build new coal generation in this country. And maybe more importantly, as we think about a global word that the energy is going 

to double over the next 50 years, to get that technology to other 

places in the world is incredibly important because this is a global 

issue, not just a U.S. issue. 
83 

Mr. HALL. And I thank Chairman Lummis, who wished the EPA 

could be here and be here and testify again for you all to hear. I 

don’t know how much time I have left, Mr. Chairman, or I have 

run out of time—— 

Chairman STEWART. You have got about a minute and a half. 

Mr. HALL. All right, sir. Mr. McConnell, we in Texas are very 

proud to be leaders. Mr. Weber got onto that, and I certainly agree 

with his approach. I like the way he identified some of the President’s promises. But the Texas Clean Energy project is a ‘‘now 

gen.’’ It is integrated classification combined cycle facility that will 

incorporate CCS as a commercially clean coal power plant, and it 

is my understanding, and I may be wrong, that this project received a $450 million award in the 2010 from the Department of 

Energy’s Clean Coal Power Initiative and received a final air quality permit from the Texas Commission on Environmental Quality 

in 2010. My question, I guess, once again, is to you, Mr. McConnell. 

Has this project begun? 

Hon. MCCONNELL. No, sir. There has been no ground broken and 

no construction. 

Mr. HALL. What are some of the challenges associated with it? 

Hon. MCCONNELL. The commercial viability as well as the concerns about the demonstrated technology have made it incredibly 

challenging to enable commercial realization, and that has delayed 

the start of that plant and construction for a considerable amount 

of time. 

Mr. HALL. And my last question. What about the status of other 

plants, CCS projects around the country? How far along in construction are they? 

Hon. MCCONNELL. Outside of the Kemper plant that has been 

mentioned several times, none of them are operational or in construction, and every one of them require government subsidies at 

this point because of the technology readiness and commercial 

availability. 

Mr. HALL. Once again, I thank you, and Mr. Chairman, I thank 

you very much for having this hearing based on seeking honesty 

from people who come before us to testify. Thank you. I yield back. 

Chairman STEWART. Thank you, Mr. Chairman. 

We now turn to Mr. Massie. 

Mr. MASSIE. Thank you, Mr. Chairman. 

I have just a quick question for all of the witnesses. For given 

kilowatt-hour or gigawatt-hour production plant, if we had a typical state-of-the-art coal-fired plant and we had the same plant but 

hypothetically with CCS technology, and I say hypothetically because it doesn’t exist yet, the two plants producing the same 

amount of energy, one has CCS and one does not. For each of the 

witnesses, which one burns more coal? Mr. McConnell? 

Hon. MCCONNELL. To produce the same amount of electricity, the 

one with the CCS facilities obviously because of the parasitic load. 

Mr. MASSIE. Dr. Bajura? 

Dr. BAJURA. I concur with the Secretary. 

Mr. MASSIE. The one with CCS burns more coal? 

Dr. BAJURA. Yes. 

Mr. MASSIE. Mr. Waltzer? 

Mr. WALTZER. Yes, I agree. 
84 

Mr. MASSIE. What do you agree with? 

Mr. WALTZER. The one with CCS burns more coal. 

Mr. MASSIE. And Mr. Martella? 

Mr. MARTELLA. I agree. 

Mr. MASSIE. So we are all in agreement that CCS technology 

makes a coal plant less efficient. Do all the witnesses agree with 

that? 

Hon. MCCONNELL. Yes. 

Mr. MASSIE. So I think that is important to start out there. Now, 

the coal companies—and let me tell you why I am motivated to ask 

these questions. I am from Kentucky. We are very proud of our 

electric generation in Kentucky. I don’t have any coal mines in my 

district yet we have two electric arc furnaces. One produces stainless steel, one produces steel. Kentucky is a big producer of aluminum. And so this is not about coal for me per se, this is about 

affordable domestic energy, and this is a very serious step when we 

increase the cost of domestic energy. 

Mr. Waltzer, how much more costly per kilowatt-hour would it 

be to produce electricity with CCS? 

Mr. WALTZER. Our study that we submitted in testimony indicated that to comply with this rule, a new coal plant today would 

be about $100 per megawatt-hour, and the—— 

Mr. MASSIE. On a percentage basis, what would it be? How much 

higher to produce? 

Mr. WALTZER. Well, and that was without CCS, and then the one 

with CCS would be 113, so it’s 13 percent higher. 

Mr. MASSIE. You are saying 13 percent. We had a witness just 

about a month ago from the DOE say it was about 50 percent higher, and so is that because it burns more coal? Is that one of the 

reasons? 

Mr. WALTZER. So yes, and I can explain the difference between 

those—— 

Mr. MASSIE. That is all right. I just wanted to check. And how 

much more coal does it burn to do CCS? 

Mr. WALTZER. Well, you—I would have to go back—— 

Mr. MASSIE. At the 40 percent level, the Administration would 

receive reduction, correct? 

Mr. WALTZER. Depending on if it is 13 percent or 50 percent, 

which number you are looking at, the amount of coal you have to 

burn is proportional to the percentage of energy penalty that you 

are paying. 

Mr. MASSIE. So what is the number to achieve the 40 percent reduction? 

Mr. WALTZER. I would have to go back and do the math but it 

is—it could be—I don’t know. I don’t want to speculate. I would 

have to go back and do the math. 

Mr. MASSIE. So the coal-fired generation plants in my district 

have done a tremendous job of decreasing sulfur emissions. Particulate, mercury, all of these things have gone down by probably a 

couple orders of magnitude in the last 3 decades. But it still remains a fact, does it not, that those emissions are proportional to 

the amount of coal burned? 

Mr. WALTZER. If I understand your question correctly, is there an 

energy penalty on those pollution controls? Absolutely. 
85 

Mr. MASSIE. What I am saying is, when you burn more coal, do 

you emit more sulfur for any given plants? 

Mr. WALTZER. It depends on the pollution control. 

Mr. MASSIE. Let me ask that question to Mr. McConnell. For a 

given pollution control on a plant, if you burn more coal, does it 

emit more sulfur? 

Hon. MCCONNELL. Yes, and it would require more handling and 

more treatment to process that sulfur, yes. 

Mr. MASSIE. So all things being equal, the effect of implementing 

CCS technologies is, we are going to burn more coal, and with the 

same emissions controls on mercury, particulate, sulfur, NOX, we 

are going to be admitting more of those, given the Administration’s 

goals? 

Mr. WALTZER. That is not necessarily correct. In order to—— 

Mr. MASSIE. But given the same technology for all of those 

things, it looks to me like it would be the same. Let me also ask 

you—I want to move on. I have 26 seconds. Will we have to mine 

more coal to produce the same amount of power? 

Mr. WALTZER. Yes. 

Mr. MASSIE. So all of the externalities that the Administration 

associates with mining coal would be increased with CCS? 

Mr. WALTZER. Potentially. 

Mr. MASSIE. Mr. McConnell, would you like to comment on that? 

Hon. MCCONNELL. I might suggest there may not be any coal 

mined at all because in fact, the plants will shut down and there 

won’t be any need for coal. 

Mr. MASSIE. That is my concern. We have a plant in Kentucky 

that is shutting down. It is going to affect 139,000 consumers of 

electricity in my district, so I think it is a very important point to 

make, that CCS is not without costs to the environment. Thank 

you. 

Chairman STEWART. Thank you, Mr. Massey. We now turn to the 

gentleman from North Dakota, Mr. Cramer. 

Mr. CRAMER. Thank you, Mr. Chairman, and thanks, members of 

the panel, for being here. It is hard almost to know where to begin. 

I have heard so many things this morning. But I am going to start 

with addressing from the North Dakota perspective this issue of 

whether or not New Source Performance Standards for new plants 

affects jobs in the existing plants, and let me assure you, it does 

because it is a further reflection of an attitude that has been pervasive by this Administration that tells anybody interested in fossil 

fuel development, we are going to punish you as much as we can, 

and so if you are considering building a new plant or retrofitting 

an old plant, the odds are against you, and it is not like it has been 

a hidden agenda. It has been a pretty far-out-there agenda. 

I appreciate as well—I am going to use this opportunity to put 

a few things into the record—that Mr. Waltzer has referenced several times the Dakota gas syn fuels plant at Beulah, North Dakota. 

I had the opportunity as an energy regulator for ten years not only 

to oversee electric rates but coal mining and pipeline development, 

and I sited the CO2 pipeline, much of it, that goes to Saskatchewan, and we are very proud of that project. The company that 

owns it, Basin Electric Power Cooperative, which is one of the largest G&T cooperatives in the country, also owns a lot of electric gen-
86 

eration, coal combustion generation, right near Beulah, and they 

engage with their own money in a demonstration project, 50 percent funded by Basin Electric’s members and 50 percent funded by 

the State of North Dakota through a tax on coal, and concluded 

after the feed study that it was in fact not demonstrated to be economical to do a carbon capture and sequestration project at this 

time, and this is in a community right on the edge of the Balkan 

where there is a lot of commercial application for CO2 should it enhance oil recovery. Obviously, all the incentives are there, and yet 

even at that, they concluded by their study that it was in fact not 

feasible to do it. So I want to put into the record, Mr. Chairman, 

with your permission and the permission of the Committee, a number of documents referencing this feed study by Basin Electric, if 

that is acceptable. 

And then I have a question for the panel because I think there 

is some premise for this. When we talk about this adequately demonstrated standard and other standards in previous Clean Air Act 

rules, whether it is SOX, NOX, mercury, that have applied certain 

standards, has there been a different or is there a benchmark or 

some historical lesson we can learn from previous rules and the 

availability of technology at that time versus what we are facing 

today? Is that a fair characterization for a reasonable question, Mr. 

McConnell, and would you be able to answer? 

Hon. MCCONNELL. I think there is an interesting model to look 

back into the 1970s when we were all concerned about SOX, NOX, 

mercury and suspended particulate. The government and industry 

formed a successful partnership together, not at odds with each 

other but partnered with each other, to develop technology to reduce those criteria pollutants by 90 percent over the next 40 years 

while we increase the amount of coal-generated power in this country by 200 percent, and that is through the miracle of technology. 

And in fact, I would hope that as we look to the future, we don’t 

get simply bounded by what we know today in terms of performance and capabilities but we are mindful of the fact that the investment for the future is really where we will be and will need to be, 

and I certainly hope that rulings such as this don’t promote a partnership between government and industry. They promote an adversarial circumstances and tends to block out an opportunity to advance coal, not promote it. 

Mr. CRAMER. Doctor, would you agree? 

Dr. BAJURA. I have concerns about the scale that we are talking 

about. I don’t think the earlier technologies were as expensive as 

what we are discussing here, the earlier commentary about an energy penalty of 30 percent. It costs a lot of money when you are 

talking about a billion dollars per plant in excessive coal use. I 

agree with the Secretary. We need to find a way to move forward 

if we are going to solve this problem, and I think government support is essential. 

Mr. CRAMER. With just the few seconds I have, Mr. Waltzer, if 

you could just answer this. You made reference to making coal cost 

more, and I am going to paraphrase it. You are going to have to 

straighten it out for me. But you are saying that this actually benefits the coal-generated electricity by positioning it well for when 
87 

gas prices rise. Could you elaborate a little bit on that, how making 

it cost more positions it better should gas prices rise? 

Mr. WALTZER. So let me be clear. I don’t know what gas prices 

are going to do. They may go up, they may go down, but if we take 

this first step to begin the process of deploying CCS technology and 

pushing it further down the cost curve, that will benefit coal in the 

future. 

Mr. CRAMER. I see. I am out of time. Thank you, Mr. Chairman. 

Mr. WEBER. [Presiding] Thank you, Mr. Cramer. 

Mr. CRAMER. If I could, Mr. Chairman, I don’t think it has been 

ruled on, my request to place into the record these documents from 

Basin Electric. 

Mr. WEBER. Without objection. 

Mr. CRAMER. Thank you. 

[The information appears in Appendix II] 

Mr. WEBER. We are going to get our act together up here Dana. 

We just don’t know when, but the gentleman from California is recognized for five minutes. 

Mr. ROHRABACHER. Thank you very much. I have been running 

back and forth between hearings today. As usual, they schedule 

two of the most important hearings that I am interested in at exactly the same time, so I am sorry if I ask something that is repetitive that had been asked earlier. 

I would like to ask Mr. Martella, you had mentioned earlier in 

your opening statement that there was a court decision, Massachusetts, that the Supreme Court decided that the EPA has to consider 

or may consider CO2. You said ‘‘has to consider.’’ Does it say that 

they have to consider the CO2 or just may? 

Mr. MARTELLA. The way I interpreted the decision is, they have 

to consider greenhouse gases but they do not have to regulate 

them. The court made it clear, it was not forcing EPA to regulate 

greenhouse gases but it did have to consider—— 

Mr. ROHRABACHER. That is really an important distinction, and 

certainly, the Court did not mandate that they take steps to take 

the CO2 out of energy production, did they, or did they say that has 

to be considered but they didn’t say they have to do it? Is that 

right? 

Mr. MARTELLA. You are absolutely right. It is an important distinction. The Court said the EPA can’t ignore the consideration of 

greenhouse gases but the Court also explicitly said we are not telling EPA it must regulate greenhouse gases, just that it has to look 

at—— 

Mr. ROHRABACHER. So this is not a mandate by the Court. That 

is something we have to understand. What we are talking about is 

a policy that has been determined that this is the direction that the 

Executive Branch wants to go because that is what they have determined is consistent with their policy goals, not necessarily with 

what the Court is saying, not in contrast to the Court but not in 

direction mandated by the Court. 

Carbon sequestration—now, I know you have had this question 

a number of times so I am assuming that you all agree that the 

CCS costs a lot more than if you didn’t have to do that. Is that correct? I mean, everybody agrees to that. And let me note, our colleague, Ms. Edwards, who I deeply respect, from Maryland—I wish 
88 

she was here now—talked about the EPA’s responsibility for public 

health and environment. Well, most of the people who support this 

idea that we are going to do something about the CO2 and sequestration are thinking that it is being done, it is a pollutant and they 

are doing this in the name of protecting health. Now, am I correct 

that CO2 is not a threat to public health? Does the panel agree 

with that? CO2 does not affect human beings in the process of producing electricity. Is that correct? Is there some disagreement on 

that? I have been through many panels on this now. You would be 

the first one. 

Mr. WALTZER. So CO2 is not toxic but the temperature increases 

associated with greenhouse gases—— 

Mr. ROHRABACHER. That is a different matter, okay? So CO2 is 

not toxic. It is not a pollutant. But we are going to spend a lot more 

money on it because we have the global warming theory that basically CO2 will affect the climate of the planet. But most of the people and the public who are looking for more. They are looking at 

expenses now, especially when we are in this deficit. They are actually operating under the thought that what is happening with sequestration, etc., is being done to protect their health. Well, that 

just isn’t the case. That is not the case what we have just heard. 

It is based on a world climate theory, not on a personal health concept, that we have to protect people’s health. 

Let me just note that what we have just heard with the talk 

from Mr. Massey is that not only is this whole sequestration not 

being done in order to protect public health, but by his questioning, 

he made it clear, and from what your answers were, that it is actually detrimental to the public health because you are increasing the 

level, the amount of sulfur, mercury and other particulates, etc. 

that are going into the air because now you are actually—— 

Mr. WEBER. Will the gentleman yield? 

Mr. ROHRABACHER. Yes, I certainly will. 

Mr. WEBER. And I will give you some extra time. Unless the end 

goal is to do away with the coal industry. I yield back. 

Mr. ROHRABACHER. All right. Well, I think that sometimes people 

are not totally upfront about what their end goals are, but we have 

to look at the policies they are advocating today, but I would say 

that what we have heard at this hearing today indicates that the 

Administration is rushing forward full steam ahead on this CO2 sequestration as part of an energy production guide states in a way 

that will actually damage public health but is consistent with their 

goal of trying to have a policy that affects the climate of the entire 

world, which I might add, is a very questionable theory and is getting more skeptics every day on that theory. 

So thank you very much, Mr. Chairman. 

Mr. WEBER. Thank you. 

And I thank the witnesses for being here today, and that concludes—— 

Ms. BONAMICI. Mr. Chairman, if I may? Thank you very much 

for yielding for just a moment. There were some documents that 

were introduced today at the hearing that we did not see before, 

staff was not given ahead of time, and I would like to request that 

all staff remind Members that it is helpful to get those ahead of 

time so that we can raise appropriate objections, if any. So I just 
89 

wanted to put that reminder on the record, that it is important for 

us to see the documents ahead of time rather than for the first 

time at a hearing. Thank you very much. 

Mr. WEBER. Thank you, Ms. Bonamici. I appreciate that. 

And with that, this hearing is concluded. 

[Whereupon, at 12:07 p.m., the Subcommittees were adjourned.] 

(91) 

Appendix I 

ANSWERS TO POST-HEARING QUESTIONS
92 

ANSWERS TO POST-HEARING QUESTIONS

Responses by The Honorable Charles McConnell 
93 

2) EPA claims it can mandate CCS because the "components" have been demonstrated 

at facilitie.~ other than power plants. Yet, just two years ago, EPA co-authored a 

report that concluded, "Since the C02 capture capacities used in current industrial 

processes are generally much smaller than the capacity required for the purposes of 

GHG emissions mitigation at a typical power plant, there is considerable 

uncertainty associated with capacities at volumes necessary for commercial 

deployment." Which EPA is right - the one that concluded there is substantial 

uncertainty concerning CCS at power plants, or the one that is now mandating CCS 

at power plants? 

Two years ago, the EPA got it right when they made the statement about the uncertainty 

of commercial deployment. There is absolutely no question that there is considerable 

concern with mandating CCS technology a technology that is not employed at scale 

anywhere in the world. To mandate its use with any level of assurance that the 

technology is ready for commercial deployment is ludicrous. 

3) What is the difference between regulations that incentivize carbon reductions and 

regulations that mandate CCS? Does the latter push coal technology beyond where 

companies can feasibly use it? 

There is a huge ditIerence in approach between regulations incentivizing and mandating 

CCS. The latter is punitive. Mandating CCS assumes the technology is demonstrable and 

ready, but it is not. Mandating a standard that requires the use of a technology that is not 

commercially viable makes it impossible for industry to choose that source as an option. 

In fact, such a mandate requires industry to choose another means of producing power. It 

is environmental manipulation of the marketplace that takes prot of our energy mix off 

the table, which is not healthy for energy security or an energy portfolio that is fixed on 

"All of the Above." 

Currently, many believe that natural gas can replace coal as a cheap, clean source of 

power production in this country. Historically, natural gas prices have fluctuated, and 

they will continue to do so in the future. The power industry is not choosing to use 

natural gas as a source because it is cheap. They understand the expected price 

fluctuations. Industry is choosing natural gas because it cannot chose coal due to this 

type of regulation. 

On the other hand, regulations that incentivize carbon reduction will drive technology 

choices and commercial pathways to better performance. Those regulations will push 
94 

industry to achieve more creative processes and projects that will benefit the marketplace 

and environment, giving us more options for cheap, clean power production. 

4) EPA's cost-benefit analysis that accompanied this proposed rule stated that these 

standards "will result in negligible C02 emission changes, energy impacts, (and) 

quantified benefits ••• " President Obama's executive order on regulations requires 

that for any regulation, the benefits must justify the cost. In light of the absence of 

benefits associated with this proposal, do these new standards meet the President's 

cost-benefit requirement? 

No. 

5) Are there any states or districts in this country in which using carbon capture and 

sequestration for the purpose of enhanced oil recovery is not feasible? 

Yes. There are geology issues that will either allow certain areas to be receptive to EaR 

or exclude certain areas from EaR use. CCS is not a solution that can be universally 

applied, nor should it be thought of as such. In the same manner that solar, wind, and 

nuclear energy sources are not a suitable fit for all 50 states, neither is EaR. However, it 

is an important component ofa real All of the Above strategy. We need to ensure that 

there are suitable regional options for best choices in power production and supply of 

market across the country. No technologies or sources are the answer for all 50 states 

including CCS. For instance, EaR will not work in the geology of the Northeastern 

United States. Similarly, hydro is not a viable choice for Florida. But solar might work 

there, when it will not work in Maine. Giving up pieces of our country's energy portfolio 

narrows options and forces our country into less attractive long-term cost and energy 

security choices. 

6) In your testimony you referenced the complicated series of interrelated EPA rules 

and regulations currently being enforced, promUlgated or contemplated. What 

specifically were you referring to, and what is the risk these actions may pose to 

coal-fired plants? 

INSERT EPA REGULATORY TIMELINE CHART 

The attached diagram illustrates my point. The mix ofmles (in place, being 

promulgated, or contemplated for regional, national and adjacent state areas related to 
95 

NOx, SOx, Mercury, particulate, C02, and ash, among others) places an extreme burden 

for industry to plan for or calculate risk for new coal-fired power plants. This burden 

pushes them to pursue other technologies and will lead to an end of coal as a source for 

power in this country. 

Questions from Representative Neugebauer: 

1) In July, I asked Mr. Chris Smith, the Acting Assistance Secretary of Fossil Energy 

at the Department of Energy, about the timeline for the development of CCS 

technology. At that time, he could not give me a set timeline for when this 

technology would be truly ready for commercial use. Numerous states have 

determined that CCS is not economically or technically feasible for power plants, 

and the EPA itself stopped short of saying CCS was adequately demonstrated in 

April of 2012. What has changed substantively in CCS development in the last year 

and a half? 

The only thing that has changed substantively in the last few years is this 

Administration's willingness to abide by its own plan for the development and 

deployment of CCS technology. The Administration is cutting its internal budget for the 

programs outlined in the 2010 CCS R&D Roadmap. But the technical steps laid-out in 

the Roadmap necessary for the development of scalable CCS technology have not 

changed. The 2010 Roadmap called for a ten-year funding and development program 

with demonstration plants utilizing today's technology. The Roadmap planned for 

second generation technology to be deployed beginning in 2020. In 2025/2030, third 

generation/transformational techno 10 gy would further drive cost down and make it 

commercially viable. To achieve the targets envisioned for technology deployment, 

specific research and development funding requirements must be met, but the R&D 

budget supporting this work has been cut by 40 percent. This underfunding threatens our 

ability to achieve adequately demonstrated CCS technology - which the Administration's 

plan, if perfectly implemented, expects would not occur before 2020. The EPA 

apparently failed to read the 2010 Roadmap before issuing its NSPS proposed rule, and it 

certainly did not take into account the underfunding of federal R&D efforts, which will 

only further delay our ability to achieve the 2020 goal. 
N02 NAAQS 

Un classifiable! 

Attainment 

FinallB MACT 

Reproposed N02 NAAQS: 

GHG NSPS States Begin 

for New Installation of 

502 NAAQS Sources New Monitors 

I CAIR/CSAPR I 

Final GHG Performance 

Standard for 

Initial NA MATS Effluent Guidelines 

Review 

316(b) Compliance 

No later than 8 years 

after Final Rule 

MATS Compliance 

(April 2015) 

2013 PM-2.S 

NAAQS 

Possible CAIR 

Replacement 

Proposal, 

Supreme Court Designations 

CSAPR 

• 18 MACT 

Compliance Replacement 

(Existing Rule 

Sources) MATS Compliance 

(l-Yr Extension) 

I MAc:T/Hg/HAPS I 

S02 N

Attain

[iiHGjC
97 

Responses by Dr. Richard Bajura 

U.S. HOUSE OF REPRESENTATIVES 

COMMITTEE ON SCIENCE, SPACE, AND TECHNOLOGY 

Subcommittee on Environment 

Subcommittee on Energy 

Hearing Questions for the Record 

The Honorable Chris Stewart 

EPA Power Plant Regulations: Is the Technology Ready? 

Dr. Bajura 

1. Dr. Bajura, help me better understand what you mean by "Scaling up technology?" What 

are the challenges in moving from a demonstration to full-scale commercial applications? 

2. The EPA contends that use ofthe "component pieces" of CCS in various applications 

means the technology is adequately demonstrated for power plants. Can a technology 

system be considered adequately demonstrated and commercially available if the entire 

system has never been used at commercial operating scale before? 

3. EPA cites three studies in the "literature" section ofthe new standard's "technical 

feasibility" discussion of CCS. Yet, EPA leaves out that one of those studies concludes 

that "there is truth to the often heard assertion that CCS has never been demonstrated at 

the scale of a large commercial power plant," another assumes carbon capture is 

"unproven technology" and the other - which EPA co-drafted, no less - says that carbon 

capture has "not been demonstrated at a scale necessary to establish confidence for power 

plant application." Does EPA accurately portray the science on CCS when it cherrypicks from studies in this manner? 

4. In your opinion, is CCS technology today directly comparable to the technological 

development of scrubbers in 1980 when their use was first mandated by EPA by rule? 

5. Has EPA ever adopted an emission standard that depends on ancillary activities that are 

not part of the normal operation of an emission source? 

Responses 

Question 1: Scale-up ofTechnology 

In advancing a technology based on a constructed facility from its initial formulation to 

commercial deployment, much experimentation must be done. The first such experiments are usually 

done in a small laboratory apparatus to validate that the base hypothesis about the operation ofthe 

technology is sound. A laboratory reactor for testing a chemical reaction, for example, may be in a 

confined space with a volume of a pint of fluid. A commercial reactor may operate in a facility where 

the volume of the reactor space is five hundred barrels or more. The pint-sized reactor may cost $10; 

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98 

the five hundred barrel reactor may cost a billion dollars. Before building the billion dollar reactor, the 

process is usually demonstrated in facilities of varying sizes from pints to quarts to gallons to barrels to 

hundreds of barrels in size. The process of proceeding from a small reactor to a commercial reactor by 

building test systems of larger and larger sizes is called scaling. 

Testing the process in a reactor of each of the sizes discussed above is a demonstration of sorts. 

The larger the scale, the more other factors come into play. For example, how would the plant owner 

manage the waste generated daily from a large scale process compared to small amount generated over 

the testing ofthe smaller system? What kind of safety precautions need to be taken when a large vessel 

is exposed to high pressure requiring a large wall thickness versus a small vessel at low pressure where a 

thin wall tube is sufficient protection? What are the economics ofthe large scale system compared to 

competing technologies? In some cases, the performance of the full scale system may be reduced 

compared to the smaller versions due to the extra complexities that come into play for larger systems. 

Proceeding from a small scale to a demonstration scale (usually one-third or smaller in size than 

the commercial version) involves taking into account factors that are non-existent or can be handled by 

over-building a small scale system but become large factors regarding weight, safety, or economics in a 

larger system. In the end, ifthe commercial system cannot demonstrate that it will operate 

economically, that it will meet performance guarantees, and will meet environmental regulations, such 

a system will not achieve commercial status. 

Question 2: Component Testing versus System Testing 

As discussed above, the larger the scale of a device, the more complex the system becomes. 

Many components in industrial systems were designed and tested for particular applications. These 

components operate effectively in the environment for which they were designed. 

However, if a component is placed into another system operating with different inputs to the 

device and different output requirements, the device may not operate to the specifications required for 

the overall process. The performance of all components in a system must be effectively integrated into 

the overall system in order to assure an overall acceptable system performance. An effective design 

must have not only acceptable performance from each component, but acceptable performance of the 

overall system. 

When a technology has not been demonstrated to perform effectively under the conditions 

required of a commercial system, it is difficult to find fabricators who will guarantee performance since 

the fabricator will pay the buyer each day over the lifetime of the unit for extra costs to the owner for 

performance metrics that were not met. If a fabricator will not build the device due to uncertainty in 

performance, it can be said that the technology is not yet developed to a commercial scale. 

Question 3: Data Used by EPA in Setting Standards 

I have not studied all the reports reviewed by EPA nor the general literature in the area of 

carbon capture for CCS applications. Often times studies appear to be similar in nature, but on 

inspection of all the parameters tested, there may be small differences in design or operating conditions 

which can change the performance of a system as discussed with respect to Question 2 above. It is 

N:\HEARINGS\ENVIRONMENT\l13th First Session\10.29.13 NSPS\Responses QFRs\Bajura 

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99 

necessary to carefully review the conditions under which a technology has been tested or demonstrated 

to be able to accurately predict its performance in a different application. 

Question 4: Status of CCS Technology Compared with Scrubber Technology 

Engineering studies have been performed on devices that are called First-of-a-Kind systems 

versus Nth-of-a Kind Systems, where N is a number much larger than one. These studies show that as 

one constructs newer and newer versions of a technology device, lessons are learned about the basic 

operation, or the construction schedule, or the material properties needed, such that it is possible to 

reduce costs and improve performance over time. With investments in carbon capture technology and 

larger scale demonstrations, the performance of carbon capture technologies currently available will 

improve and costs will be reduced. These effects were shown to be the case for scrubber technology 

development and deployment. 

When technology is mandated by rule, as in the case of regulations by EPA, it is important that 

sufficient time be given to develop technology with the required performance and that the performance 

goals be set at realistic levels given the time frames required to prove out technologies developed to 

meet the standards promulgated by the rule. The pathway to commercialization of CCS technologies 

should follow a similar pathway as was noted for the development of technologies for criteria 

pollutants. However, the time frame for development of CCS technologies is likely to be longer given 

the complexity of the process in needing both capture and storage technologies to be developed at 

large scales. These factors are reasons why I consider the state of development of CCS technologies to 

be behind the corresponding state of development of technologies such as scrubbers for sulfur or for 

other criteria pollutants at the time similar legislation was enacted mandating control of the given 

effluent emitted. 

Question 5: EPA Standards 

I am not sufficiently familiar with EPA's procedures for setting standards to provide a response 

to this question. 

Richard Bajura 

February 18, 2014 

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100 

U.S. HOUSE OF REPRESENTATIVES 

COMMITTEE ON SCIENCE, SPACE, AND TECHNOLOGY 

Subcommittee on Environment 

Subcommittee on Energy 

Hearing Questions for the Record 

The Honorable Randy Neugebauer 

EPA Power Plant Regulations: Is the Technology Ready? 

Dr. Bajura 

1. In July, I asked Mr. Chris Smith, the Acting Assistant Secretary of Fossil Energy at the 

Department of Energy about the timeline for the development of CCS technology. At that 

time, he could not give me a set time line for when this technology would be truly ready for 

commercial use. Numerous states have determined that CCS is not economically or 

technically feasible for power plants, and the EPA itself stopped short of saying CCS was 

adequately demonstrated in April of2012. What has changed substantively in CCS 

development in the last year and a halt? 

Responses 

Question I: Changes in CCS Technology Development 

I consider there to be two important technology developments that factor into the use of 

the term "CCS", meaning carbon capture and storage. Carbon capture occurs at the power plant. 

Storage is usually done in an underground reservoir. These two aspects, capture and storage, 

employ two different technology approaches and are coupled in that once the C02 is captured, it 

must be stored. The coupling is usually considered to be a pipeline that takes the C02 from the 

source to the sink. 

Carbon capture technology is well developed in the chemical engineering field. In the 

production of chemicals, it is sometimes necessary to remove C02 from the process stream. 

Hence, C02 removal technologies were developed by the chemicals industry. While the cost of 

these technologies is high, the value of the product manufactured is high enough that the capture 

cost can be recovered in the selling price. In the case of carbon capture in a power plant, the 

current technologies (e.g., amines or chilled ammonia processes) that are available can remove 

C02, but the cost of operating systems is high and the resulting selling price of electricity is 

greatly increased. Recently, DOE Office of Fossil Energy personnel testified that capture costs 

could be as high as $90 per ton of C02 captured and that the cost of electricity for such plants 

N:\HEARINGS\ENVIRONMENT\1l3th First Session\lO.29.13 NSPS\Responses QFRs\Bajura 

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101 

could be almost doubled. Electricity produced using these technologies is not cost competitive 

with electricity produced by, say, natural gas without carbon capture. Hence, while the 

technology is available to capture C02, the cost is so prohibitive that systems based on these 

technologies will not be used commercially. Since commercial deployment for a technology is 

based on its effectiveness at performing the required task and its cost competitiveness compared 

to other processes, many states have determined that this part of the CCS requirement is not 

economically feasible. 

Over the past several years, new technology pathways to capture C02 have been 

proposed. One way to improve capture technologies is to improve cycles. Recent studies have 

shown that processes such as ultra-supercritical pressure coal power systems, oxygen-fueled 

combustion systems, and chemical looping systems offer promise to reduce the cost of capture 

compared to existing technologies. Additional research is needed for these technologies to 

validate their effectiveness in the commercial market. Other advanced cycles are also being 

studied which may result in even greater performance of the capture component of fossil fuel 

power generation. These new technologies have emerged in the past two years as having 

promise and worthy offurther investigation. However, development ofthe technologies for 

commercial application is complicated by the absence of federal funding to do demonstration 

projects and the uncertainty of future construction of coal power plants in the face of the 

proposed NSPS rule for new coal plants. Hence, developing a time line for deployment is a 

difficult task. 

Turning to the issue of storage in the parlance of CCS, it is necessary to demonstrate that 

carbon can be injected into underground saline reservoirs, for example, in a manner that will not 

be detrimental to the environment in the near term and in the long term. Such research programs 

have not been conducted and evaluated for applications such as would be applicable to a large 

(600 megawatts) power plant operating over a long period corresponding to the typical lifetime 

of the plant. Injecting carbon underground is not cost effective - it costs money to do and there 

is no apparent benefit. Some offsets in cost can be obtained by injecting C02 into oil reservoirs 

for enhanced oil recovery operations. But the costs of recovered oil do not offset the operational 

costs of capturing the C02 at the power plant. We need additional work to prove out the safety 

and performance of underground reservoirs to gain acceptance by the general public while 

demonstrating the effectiveness of injection schemes. Proving out schemes for injection that 

need to be tested over a large number of years to demonstrate permanent, safe storage is not a 

program that can be completed in several months. Hence, time lines for deployment of 

commercial storage technologies is also difficult to predict. 

Our nation needs a steady, robust program of technology development both for carbon 

capture and storage to prove out these new technologies. By supporting a strong program of 

research, we can develop cost-effective technologies for both capture and storage and then be 

able to confidently predict times for deployment of advanced technologies. I recommend 

continued support for coal based research programs to ensure that coal remains in the national 

energy mix since it is a highly abundant energy resource. 

R. Bajura 

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102 

Responses by Mr. Kurt Waltzer 

U.S. HOUSE OF REPRESENTATIVES 

COMMITTEE ON SCIENCE, SPACE, AND TECHNOLOGY 

Subcommittee on Environment 

Subcommittee on Energy 

Hearing Questions for the Record 

The Honorable Randy Neugebauer 

EPA Power Plant Regulations: Is the Technology Ready? 

Mr. Waltzer 

I. In July, I asked Mr. Chris Smith, the Acting Assistant Secretary of Fossil Energy at the 

Department of Energy about the timeline for the development of CCS technology. At that time, 

he could not give me a set timeline for when this technology would be truly ready for commercial 

use. Numerous states have determined that CCS is not economically or technically feasible for 

power plants and the EPA itself stopped short of saying CCS was adequately demonstrated in 

April 012012. What has changed substantively in CCS development in the last year and a half' 

Response: 

We maintain that CCS is an adequately demonstrated technology today. As noted earlier in my 

written testimony, this is based on a long history of the technology and its components: 

• Large, integrated CCS projects began in the United States in the 1970 and 

1980s at industrial facilities where C02 was sold for enhanced oil recovery (EOR). Some of 

these projects capture and store I million tons C02 per year,S million tons C02 per year, and 

7 million tons of C02 per year.' From its beginning in industrial facilities, CCS has migrated 

to power plants where it can reduce C02 emissions by greater than 90%. 

'In early 2012 there were 127 U.S. C02 EOR projects with approximately 7,100 C02 

injection wells and 10,500 producing wells. According to the National Petroleum Council, 

approximately 3 billion cubic feet per day of C02 (57 Mt/yr) of newly purchased C02 are 

presently injected for tertiary EOR producing 286,000 barrels of oil per day (105 million 

barrels per year 

• Nearly 1 billion tons of C02 have been stored underground in U.S. oil fields from EOR 

operations over the last 40 years. In its 2013 National Assessment of Geologic Carbon 

Dioxide Storage Resources, the U.S. Geological Survey assessed the technically accessible 

geologic carbon storage resources in 36 sedimentary basins in the onshore and beneath state 

waters of the United States. The assessment only inventoried geologic formations below 

3,000 feet with adequate porosity and permeability to accept commercial volumes of C02. 

The assessment estimates that there are approximately 3,000 Gt of subsurface storage 

I These include Val Verde natural gas processing plant, Enid Fertilizer project, Shute Creek natural gas processing 

plant, Great Plains Synfuels plant, Century natural gas processing plant 
103 

capacity. This represents more than 500 times the 2011 annual 5.5 Gt of energy-related C02 

emissions in the U.S. today. In addition, DOE estimates that 500 to 7,500 Gt of C02 could be 

sequestered in all U.S. olTshore formations on the outer continental shelf 

• There are presently approximately 4000 miles of C02 pipeline connecting naturally mined 

and anthropogenic sources of C02 with enhanced oil recovery projects. 

• Pre-combustion capture technology has been commercially available since the 1950s and 

I 960s. Two ofthe main technology options, Selexol and Rectisol, have over 100 plant 

applications each across the world. 

• Post combustion capture has been successfully applied to exhaust gases from both natural 

gas and coal plants, with commercial guarantees offered Irom several vendors. 

An adequate demonstration of the technology is different from the issue of whether or not a 

technology will be used absent regulatory or statutory requirements or incentives. For example, 

power companies will not add sulfur dioxide scrubbers unless they are required to do so, or it makes 

economic sense based on the sulfur dioxide cap and trade system. 

In some cases, such as the addition ofCCS at Southern's Kemper plant in Mississippi, the integration 

ofCCS in the development ofa new generation project and the use of enhanced oil recovery helped 

move the project forward. But even in states that clearly have a vested interest in CCS technology, a 

lack of clear regulatory limits creates deployment barriers. For example, in 2011, the West Virginia 

Public Service Commission considered AEP's request for rate-payers to cover AEP's portion (50%) 

ofthe cost associated with the 250 MW scale CCS retrofit project - with the remaining portion 

covered by a grant from the Department of Energy's Clean Coal Power Initiative. Unlike Kemper, the 

project was not integrated into a new power project, nor did it include EOR as a storage opportunity. 

Nonetheless, the Commission did not reject the project outright, nor did it find that the project was not 

feasible based on economics or technology status. Instead, the 

PSC stated: 

And, 

"We are concerned about the future of CCS and the enormous potential that it might hold for 

West Virginia and our natural resources." 

" ... as the CCS project is operating at a nominal1evel and is in fact sequestering some of the 

C02 from the Mountaineer Plant, we are willing to allow a proportionate share of those 

expenses to be included in operating expenses in this case. To be fair, as discussed above, we 

believe that this operating cost also needs to be shared among all AEP operating companies."~ 

Thus the WV PSC recognized the importance ofCCS and on that basis offered to cover a portion of the 

costs requested for recovery by AEP, but in AEP's view, that was not enough to make the project viable. 

A lack of regulatory certainty created a barrier for the PSC agreeing to cover the full costs. As AEP stated 

at the time: 

~ Public Service Commission of West Virginia, Case No. to-0699-E-42T, March30, 2011. 
104 

"as a regulated utility, it is impossible to gain regulatory approval to recover our share of the costs 

for validating and deploying the technology without federal requirements to reduce greenhouse 

gas emissions already in place. ,,3 

While lack of regulatory certainty is a current barrier to CCS technology, it is encouraging to note that 

two CCS power propjets (Kemper, and SaskPower's Boundry Dam project) and one large-scale industrial 

project (Shell's Quest project in Alberta) are slated to finish construction and come on line in the Spring 

012014. That CCS activity, just in the last year and half, is an example of an application ofa technology 

based on a long history of industrial activity. Greater regulatory certainty is important for further 

technology deployment. Finalizing EPA's proposed New Source Performance Standards is a crucial and 

necessary step towards creating this certainty. 

I will be pleased to provide any additional information or clarifications that you need, if any. 

3 "American Electric P(mcr Puts $668 Million plan on hold", Charleston Daily Mail. July 15,2011. 
105 

Responses by Mr. Roger Martella 

Honorable Chris Stewart 

SIDLEY AUSTIN LLP 

1501 K STREET, N.W. 

WASHINGTON, D.C. 20005 

(202) 736 BOOO 

(202) 736 6711 FAX 

rmartella@std!ey.com 

(202) 736 8097 

January 26, 2014 

Chainnan, Subcommittee on Environment 

Honorable Cynthia Lummis 

Chairman, Subcommittee on Energy 

Committee on Science, Space, and Technology 

2321 Rayburn House Office Building 

Washington, DC 20515-6301 

BEIJING 

BRUSSELS 

CHICAGO 

DALLAS 

FRANKFURT 

GENEVA 

HONG KONG 

HOUSTON 

LONDON 

FOUNDED 1B66 

LOS ANGELES 

NEW YORK 

PALO ALTO 

SAN FRANCISCO 

SHANGHAI 

SINGAPORE 

SYDNEY 

TOKYO 

WASHINGTON, D.C 

Re: Re: Response to Questions for the Record, "Hearing on EPA Power Plant 

Regulations: Is the Technology Ready?" 

Dear Chainnan Stewart and Chairman Lummis: 

Thank you again for the honor to appear before your subcommittee to provide my views 

regarding the Environmental Protection Agency's New Source Perfonnance Standards for 

Electric Generating Units. As I testified, I believe EPA's proposal raises significant legal and 

technical issues, and I commend the Subcommittee for addressing this issue at a critical time and 

look forward to assisting your ongoing efforts. 

My responses to your questions for the record are below. 

In your opinion, is CCS tecbnology today directly comparable to tbe tecbnological 

development of scrubbers in 1980 wben tbeir use was first mandated by EPA by rule? 

Has EPA ever adopted an emission standard tbat depends on ancillary activities tbat 

are not part of tbe normal operation of an emission source? 

In short, the requirement in the proposed new source perfonnance standard mandating carbon 

capture and sequestration (CCS) is unprecedented from both technological and legal 

perspectives. In the preamble, EPA itself acknowledges that CCS has not been demonstrated or 

operated at any commercial facility, regardless of scale. At the same time, EPA flatly contradicts 

itself by concluding this technology is "adequately demonstrated" for purposes of satisfying the 

legal standard in Section 111(b). Simply stated, both things cannot be true. While EPA fairly 

points out that case law over the years has added context to the meaning of "adequately 

demonstrated" technology under Section 111 (b), it is arbitrary and capricious to interpret either 

Sidley Austin LLP is a Umlted !isbilitf psrtne~hip practicing in affiliation with clher Sidley Austin partnerships 
106 

SID'LEYi 

Honorable Chris Stewart 

January 26, 2014 

Page 2 

the provision or the case law in such an extreme way to require technology that has not been put 

to use in any demonstrated scenario (and that EPA acknowledges has never been commercially 

demonstrated), let alone require it on a commercial scale of the magnitude anticipated by the 

proposed Rule. The analogy to scrubbers is inapposite. At the time EPA mandated scrubbers, 

the technology had been proven and was in commercial use at the scale required by the rule, 

even if not widely deployed. The situation with CCS stands in sharp contrast to that scenario, 

with EPA itself conceding not a single electric generating unit is operating in the United States 

that deploys CCS. There is thus no sound legal basis to conclude that CCS is "adequately 

demonstrated" within the meaning of Section III (b). 

States are required to incorporate new source performance standards into their 

state environmental permits. Therefore, do you believe states would have standing 

to challenge these NSPS in courts once it is finalized? 

States through public announcements and letters to EPA already have announced that the 

proposed rule will cause severe harm to their economies, citizens, businesses, and energy 

reliability if finalized. Certain states have identified impacts to utilities directly, which would 

increase the cost and jeopardize the reliability of energy, to the suppliers, providers, and 

transporters of coal and petroleum coke, and to industrial and residential consumers of 

electricity. Indeed, recently the state of Nebraska cited harm from the proposed rule itself in 

bringing the first challenge to the revised NSPS in federal court. These harms are sufficient to 

establish standing under Article III of the United States Constitution. In addition, the Supreme 

Court has held that states have "special solicitude" in establishing standing, which should further 

cement states' ability to satisfy the standing requirements in challenging the NSPS. 

What are the implications ofthis new definition ofthe "Best System of Emission 

Reduction" (BSER)? Might it be used in other rules? 

As described above, EPA's determination that a technology that is not commercially viable is 

nonetheless "adequately demonstrated" itself is unprecedented under the language ofthe Act, 

applicable case law, and past EPA practice. At the same time, this approach could have 

precedential impact beyond EGUs in several ways. First, as described below, the extraordinary 

stringency of these standards may set precedent for EPA's approach to guidelines for existing 

sources under Section III (d), meaning that EPA could use a similar technology forcing approach 

to existing facilities. Second, it is anticipated that EPA will begin developing GHG standards 

under NSPS for other industrial and manufacturing sectors in the near future. EPA likely will 

rely on the approach it adopted for EGUs in establishing analogous standards for other 

sectors. Third, beyond greenhouse gases, EPA's unprecedented technology forcing approach 

could be cited in other NSPS for other types of pollutants as well, mandating a wide range of 

technologies under Section III that are not commercially demonstrated today. 
107 

SIDiEYI 

Honorable Chris Stewart 

January 26, 2014 

Page 3 

Given the current state ofthe technology, if EPA identifies CCS as BESR for coalfired EGUs, what would prevent EPA from finding that CCS is BESR for natural 

gas plants? 

As the question points out, in the proposed NSPS, EPA identifies CCS as the Best System of 

Emissions Reduction (BSER) for coal facilities but not natural gas facilities. In recent months, 

certain groups have identified campaigns targeting new gas facilities from being constructed, 

despite their significant favorable greenhouse gas profile compared to coal. It would not be 

surprising--if not anticipated--that groups opposed to natural gas will make precisely this 

argument that EPA should require the same CCS technology for gas facilities that it does for 

coal. Thus it will be critical for EPA in the final rule to establish a firm record foundation for 

why it affirmatively believes that CCS should not be required for gas facilities. 

EPA is under a consent decree to also issue NSPS on greenhouse gases for refineries 

in the near future. Do you think there will be an impact from this rule's definition 

of BESR? How might this affect the standards for refineries or for other 

manufactures? Do you think the new definition gives standing to companies in the 

oil and gas sector, so that they may challenge this rule? How about entities already 

under a NSPS like hospitals, grain elevators, and manufacturers? Could those 

entities have standing to challenge the GHG NSPS? 

There are very few things that EPA does in a given rulemaking that do not flow over to and 

create precedent for other sectors and regulations. Thus, as pointed out by many of the 

manufacturing and industrial trade associations, there is significant concern that EPA's approach 

in this utility rule will create precedent for other sectors. Indeed, certain groups already are 

challenging PSD permits issued by EPA and other permitting agencies on the grounds that they 

do not incorporate CCS as BACT. There are numerous distinctions between how GHGs can be 

controlled from utilities and other sectors, as well as the ramifications of such regulations for 

energy intensive, trade sensitive industries, that must be considered and documented in this 

rulemaking to avoid this rule from spilling over into other sectors. EPA in the record should 

make it clear why proposed controls on utility GHGs have no precedential impact on other 

sectors for the reasons identified by these groups in their comments. Finally, there is no debate 

that other sectors will be impacted and harmed by this rule, including those that produce and 

transport coal and petroleum coke and those industries that rely on affordable and reliable 

energy. These industries, should they decide to challenge the NSPS, should be in a position to 

demonstrate these harms in establishing standing. 

Can you explain the relationship between this rule and EPA's upcoming standards 

for existing sources? As you know, states have primacy in implementing standards 

for existing sources. Can you explain what this rule might mean for the Clean Air 

Act's cooperative federalist approach to establishing performance standards for 

existing power plants under Section 111 of the Act? 
108 

Honorable Chris Stewart 

January 26, 2014 

Page 4 

The relationship between Section III (b) and III (d) is largely unchartered waters. EPA has 

issued Section I 11 (d) guidelines for existing sources on only a handful of occasions. Both the 

Act and the limited precedent demonstrate that states are to have primacy in implementing the 

existing source standards in their states. First, the Act explicitly provides that states are the 

regulatory agencies that implement the III (d) guidelines for impacted sources in their states and 

that states shall have sufficient flexibility in doing so. Second, unlike Section III (b) standards 

for new sources, Section 111(d) requirements are guidelines, and not exacting standards, and thus 

EPA itself should have significant flexibility to offer states a toolbox of options in satisfying 

Section 111(d) as opposed to a one size fits all mandate. Third, it is also implicit-if not 

explicit-in Section III (d) that states should have sufficient time to implement the Section 

111(d) requirements once EPA issues its guidelines. Here, under the schedule announced by the 

Administration, the states will have one year to develop their Section III (d) approach upon the 

release of the EPA guidelines in June 2015. That time likely will be inadequate for many if not 

most states, and these deadlines themselves could frustrate cooperative federalism if EPA decides 

to implement the guidelines directly if a state cannot meet the limited one year window. Finally, 

although not directly presented by the question, I would point out there is significant legal doubt 

that EPA has any authority to impose Section III (d) standards for existing utilities. The plain 

text of the Clean Air Act says that EPA lacks authority to impose Section I 11 (d) standards for 

existing sources when those sources are subject to a Section 112 National Emission Standard for 

Hazardous Air Pollutants (NESHAP). Because EGUs are subject to the Utility NESHAP under 

Section 112, EPA lacks authority to impose Section I 11 (d) standards on them at the same time. 

Has EPA resolved potential issues regarding the classification of compressed carbon 

dioxide as an acid gas under both Superfund and the Resource Conservation and 

Recovery Act? 

Your question highlights one ofthe fundamental flaws in EPA's analysis for concluding that CCS 

should be required for new facilities as the "best system of emissions reduction." In the 

preamble to the proposed rule, EPA focuses exclusively on the technical feasibility of CCS 

without any discussion of regulatory, economic, and pragmatic roadblocks to deploying the 

technology on a broader scale. For example, as your question points out, there are significant 

unresolved issues regarding the regulatory and legal authority to inject carbon under national, 

state, and local laws. Similarly, EPA's analysis presumes that there are sufficient geological 

formations in proximity to new sources where CCS can be deployed. A "system of emissions 

reduction" means exactly that and requires the system and infrastructure to be in place for the 

required technology to be deployed. EPA should ensure that before it mandates new standards it 

considers not only the technological feasibility, but also the full suite and system of regulatory, 

economic, and pragmatic considerations that apply. 

Response to Honorable Randy Neugebauer 
109 

Honorable Chris Stewart 

January 26, 2014 

Page 5 

In July, I asked Mr. Chris Smith, the Acting Assistant Secretary of Fossil Energy at 

the Department of Energy about the timeline for the development of CCS 

technology. At that time, he could not give me a set timeline for when this 

technology would be truly ready for commercial use. Numerous states have 

determined that CCS is not economically or technically feasible for power plants, 

and the EPA itself stopped short of saying CCS was adequately demonstrated in 

April of 2012. What has changed substantively in CCS development in the last year 

and half? 

Your question fairly points out the flat inconsistency between EPA's conclusion in April of2012 

that CCS is not adequately demonstrated for purposes of Section 111 (b) and its proposal in 

September of2013 that CCS can be considered BSER for these same sources. EPA does not 

explain in the record the sharp change in its position over such a short period of time. This 

inconsistency and lack of rationale for the change in the record suggests that the change was one 

more based on a policy rationale to require CCS as opposed to any dramatic evolution in 

technology over this time frame. 

*** 

I hope these questions are helpful in your efforts to continue to promote fairness, transparency, 

and public participation in settlements and consent decrees. I would be honored to offer any 

additional assistance to you and the Subcommittee. 

Sincerely, 

Roger R. Martella, Jr. 

(111) 

Appendix II 

ADDITIONAL MATERIAL FOR THE RECORD
112 

SUBMITTED BY REPRESENTATIVE KEVIN CRAMER

asin Electric IMSbcCl1 the first to lry manytechnologics. 

Just til ink of the cooperative's Wfy first power plant, 

Lel.md Olds Station. \Vhen itwcntonhncin 1966, it 

COJl;1$ t1 fud source ... \ ntl th roughout its-lifetime, it has been 

the pnwing ground for using and dcyeloping lignite. 

\10re recently, lhc cooperalivc"\vas the first to use GE's 

t,:'1-'1S i OO'~\ simple cycle g"s turbine at the C'1roton Crcneration 

Station in South Dakok. 

Basin Electric stalfpridc$ itsdfin finding the best technology 

ayailablc. Howc\,('r, Hoi n'ery technology makes it past the 

first t~has('s{)f$tudy I-Inc's a look at some ofthe(oop<;r~1tive's 

Lessons learned from calbon capture projecl 

While the «.nbc-a capturt: proJect at Antelope VaHey Station ·won't 

be gningin10 demonstration phase at this time, benefit h8S(Ome 

in tht' form ofinfonnation -, the rirst detailed 3!lalysis of (arhon 

cartu rc from a cnal-based pO'wcr plant in the region. 

Basin Electric's dircctors.zkddcd in December thataproposeJ 

dcmonstr<1tio:t proJC(t 10 capture emissIon,<; of carbon dioxide 

(C( )2) at the i\ntdopc Valley Station near Beulah, ND, will 

remain on hold until !hccG)T1omicviauilityofsuch aventure 

11115 decision \V;}$ made hasedon many factors including the 

presented elt tllt.' 11c(,111bcrbo<lnlmeeting. Tht' FEED study, 

\vhleh bq(<1H in Fehruary 2010, focused on capturing a portion 

(about 23 percent) ofthe CO2 ftom one ofthe Antelope Valley 

Station's t\\\) units. The FEED study, coupled ,vith an assessm<:'nt 

of lhc adJitlol1s ncccS\;aryal the plant, financing and sequestrati-tm 

l'{lSis j ndkakd a oCI110nMr,ltio!1-scak project could cost as much 

,\$ $500 millioH. 

Hon Harper, Basin f]cctric CEO and general manager, i::; satisfid 

with Ibed1'lxt "The fEED study accomplished its purpose 

(Jptme pro,ic'd trorn a Wt1vcntion;;\l coal··based power plant 

12 Basin Today basineleclric.com 

has been conducted," llcsays, "'We now knO\v thcrequircd 

infrastr:Jcturc, the cost, and the integration and operational 

challenges that will be required to continue devdoping a 

carbon capture technology. In the current t:'(;onomk dim:ate, 

we ,w:, postponing further im-cstmcnis for the time being, but 

regard it as important technology to consider for the [utun.\" 

Harper says Basin Elcctrkhas been working on this project 

time, human resources dnd capital to come to thisdcdsion 

poinL In addition to theuwrall cost of the project, other 

factors atfectingthc Jedsioll included: 

... 1 he market for the sale of CO2 tDr enhanced oil recovery 

(E<)R) is.sti!t devdoping in this region. \VithoutEOR, 

adciitional.costs (or (lireet geologic sequestration ·would 

need tobcinduded. 

,. Thcunccrtaint y of environmental legislation, 

.. Lack of a long-term energy strategy for the country. 

Based on the FEED study, Basin Electric analyzed the 

te<,~hnicd, opemtional, regulatory a.nd t1n:mdal risks for 

installing carbon capture technology at a conventional coa!~ 

based power plan L "It's imperative that a revenue stream, 

such as EOR, be available to make a project like this viable," 

I-L.uper says. "\V hik a strong potential exists II)! CO2 sales 

[Dr EOR, they have Hut yctdeveJoped and there's lloccrtainty 

thcy'lldevdop in thenCJf futurt'." 

111e FEED stmlyvl'as comluctedin conjunction with 

HTC Pmenergy, Regina, Saskatchewan, Canada, and 

Doosan Power Systems, Crrrwley, United Kingdom. 

I ITe ha~ designed ~l proprietary Co,;: capture tedmology, 

supported by Doosan, thatisdesigncJ to capture 90 percent 

of the incoming CO2 from the exhaust gases produced hy one 

of the Antelope ValleyStation units. 

1hCCDstofthe FEEDstudTwas $6.2 million; about half 

($2.7 million) of the study was funded by a grant from the 

?\Torth Dakota Industrial Cnmmission. The remainderwa.s 

tunded by Basin. Electric 
113 

"\",lub the information in hand, "\,\'C knmv\\"hat the impacts of the 

costs and the operational challenges of a project like this will have 

on OIIf consumers "lnd how they\voulJ be aftixtcd i f a fu ll·scalc 

implemel1tation of this capture technology were to be employed. 

"Basin Electric isn't ;,villing to place the burden of developing CO.? 

capture technology on its rural electric members," Harper says. 

Ew:n though the pn)jed is on h!Jld for now,} larper says 

Basin Elcdric\dH continue to work with the Energy and 

Environmental Research Center in (;rand forks and the Plains 

CO2 Reduction P;1rtnership to research CO2 storage tedmoi<"gy. 

Bacteria and coal 

For more than 25ycars, an "ent:>rgypark" near the Laramie 

River Station, 'Vheatland, 'NY, hasn't had a permanent tenant. 

By the end 0[2011, that may change. At a recent boardmcctillg, 

Basin Electric's directors granted permission to Oris Energy, 

Centennial, CO, to build a demonstration project there. 

According to Doug Roth.:., mechanicalJperformance consulting 

engineer for BJsin Electric, Ciris Energyplans to build a project 

toJelnonstratc coal gJsificatiOil witll a process similar to what 

naturally occurs to produce coal bed mt'thane. Theyintend to USE' 

<l-ehemical to Jissoive the coal, and tht.'11 bacteria to Jigest it and 

Rothe says Oris 15 funding and building the project 

simply facilitating the demonstration plant byproviding a 

location, coal supply and water supply, all at an appropriate cost 

toCiris,"he says. "They'll use up to five tons of coal a day, anJ will 

likely Oareanr ga.") prouLK'c(1111L'yhavc tested the tcchnologyat a 

lab in (~oloraJo.'" 

TIle E'll£'th'Ypark, m"lned by the Missouri Basin Pmver Project, 

features a ,,;''arm water pipdine and ·va.nlt, owned by the !OWll of 

\Vhcatland, \lIlY, \vherewarmed water (rom !-heplant's cooling 

towers can bestored and used bya tenilntif necded.1heconcept 

of an energy park is to USJ2 a byproduct from the p()'vler plant - in 

this case, warm "\\'ater - for ot her purposes such as the 

Ciris project. 

Rothe says the Ciris project is intended to be an inexpensive 

way to CO!1vcrt coal to a fud with a lower carhon footprint. 

"Bpmrkingwith Oris, vIL"illcJm about the technology and 

wiiI havean opportunity to 1,vork \\dth thcrn on a commercial 

vmturcin [he future should the technology prove out." 

wraps up 

Thcproject's goaL Find a way to storc"'ivindcnergythrough 

dynamic schcdulillg. Large amounts of dectridty Cln't 

feasibly be stored in batteries because the batteries WGuld 

he too hig and expensive. 

lbe \Vind<to-lIydrogcn project, located onemije south of 

:\liuot, ND, at North Dakota State University's Central Research 

Extension Center, was a demonstration project in partnership 

with the us. Department of Energy to explore~toringcncrgy 

from wind projects in the form ofhydrogcn. Theprojcctus.cclan 

electrolyzer to prouuce hyJ.rogen. An elrctrolyzer separates the 

hydrogen and oxygen (OBtained in water. Software and controls 

"\verc developed to select any of Basin Electric's wind projects 

and then dynamiGilly schedule the dcctrolyzer's production 

of hydrogen in dircctproportlon of the output from that wind 

project 1 he hydrogen .,vas stored and used as transportation 

fud in three pickups adapted to usc hydrogen. 

Randy Bush, formerly Basin Electric's distributed resource 

coordinator,'" says a major goal ">I,'as to create the program anJ 

protocols to dynamically schedule electriCity from the wind 

turbines to the dectroiyzcr. [1e says the project's goals have been 

an:omplished and research completed. The DOE accepted the 

projcct'stinal report in ]UI1{, 2009. 

"Dynamic sdll..'JuHng allowed the electrolyzer to draw electric 

energy from the grid as it \-vas produced by the wind turbines. 

lheeiectrolyzer\<\'as being ramped up and Juwn as dictated by 

the wind generation output," Bush says. 

The DOE awarded Basin Electric just under $15 million in 

grants fortheprojcct. 

January February 2011 13 
114 

SUBMITTED BY REPRESENTATIVE KEVIN CRAMER

DAVID B. McKINLEY. P.E. 

1ST DrSTAICT, WeST VI'I.GlNII\ 

412 CANNON HOUSE OFFiCE BUILDING 

WASHINGTON, DC 10515 

TEL (202) 225--4172 

FAX; {2\.12) 225-7564 

vllww.mckil1!eY,,'lOuse.gov 

CO,CHAlfI,' 

CGNGRESSIONAL ARTHRITIS CAUCWS 

CO,CHAIR, 

CONGRESSION'Al YOl TI-1 CHAtlENG€ CAUCUS 

CO-CHAIR, 

HIGH PERFORMANCE BUILDINGS CAUCUS 

October 23, 2013 

l!Congtc~~ of tbc Wnttcb ~tatc~ 

fi)OU!lC of l\cprt!lcntatlbc!I 

The Honorable Gina McCarthy 

Adminis\rator 

U.S. Environmental Protection Agency 

1200 Pennsylvania Avenue, N.W. 

Washington, D.C. 20460 

Dear Administrator McCarthy: 

COMM1TIEE ON ENERGY AND COMMERCE 

SU6COMMITTf.!: ON 

ENERGV AND POWER 

SUBCOMMITTEE ON 

COMMERCE, MANUFACTUnlNG AND 

TAADE 

5UOCW"~"1ITTH. ON 

t:NVlflONMENT AND ThE ECONO~W 

We are troubled by the EPA's announcement on September 30, 2013 entitled "EPA to Hold Public 

Listening Sessions on Reducing Carbon Pollution from Existing Power Plants." While hosting eleven 

public listening sessions held across the country in order to solicit feedback from the public is 

important, your plan leaves out those most impacted by the regulation by seeking input !!!!.II in major 

urban areas. 

While the proposed regulations on new and existing power plants may not be burdensome to cities 

such as Boston, San Francisco, Washington, D.C., or New York City, it will have significant impacts 

on businesses and families in rural areas. Already, one-fifth of our nation's coal plants, 204 facilities 

across 25 states, closed between 2009 and 2012. These closed and existing plants are!!!!! located in 

areas you are holding these listening sessions. In all fairness, residents and businesses in rural areas 

deserve to be heard just as much. 

The EPA must hear from Americans on Main Street in rural America not downtown San Francisco 

or Washington, D.C. If the EPA really wants to learn the impact this regulation will have on mayors, 

store clerks, senior citizens, blue-collar Americans and others, you must hold these sessions in 

locations that produce coal and coal-fired electricity. We highly recommend that you and your 

colleagues take a step out of the Beltway and visit the places that make America great; the places 

your regulations continue to devastate by shuttering plants and killing jobs. These people need your 

help and want their views to be heard. Please add rural American communities in which coal and gas 

are a part of their economies to your locations for listening sessions. 

Thank you for your attention to this matter, and we look forward to your thoughts. 

Sincerely, 

PRINTED ON RECYCLED PAPER 
115 

Qtongre.s.s of tl,e lltniteb ~tate.s 

lIIiInsljillgtDII, !lim 20515 

Member of Congress 

..-:Robert 

~~M£) AdeJ:holt,,----

./ Member of Congress 

~ Member, of Congress 

AIb.~~ Marsha Blackburn (jl~ Member of Congress 

~~ Member of Congress 

Member of Congress 

~~k-~ Michael Turner 

Member of Congress 

Louie 

4Z~ Gohmert 

Member of Congress 

Member of Congress 

PFUNT£O ON RECYCLED f'APER 
116 

(!Longrenn of tITe 1tnitell §tuten 

mllsilil1gwu. mm 20515 

J~n 

Member of Congress 

Steve ~~ Stivers 

Member of Congress 

~ Kristi Noem 

Member of Congress 

~*11-1MJ. Member of Congress 

ru~t!~idJR.r~ Member of Congress 

k~gY2·~ Member of Congress 

~~ 

PRINTED ON RECYCLED PAPER 

Tom Cotton 

Member of Congress 
117 

atougregg of tlfe Build. ~tattg 

ma5~il1!:1tnl1. Bm 2D515 

~~tfIA Member of Congress 

David Schweikert 

Member of Congress 

Member of Congress 

AattSalmon 

Member 

~ of Congress 

-

PAINTED ON RECYCLED PAPER 

&~ ...... 

evin Cramer 

Member of Congress 

Bob Gibbs 

Member of Congress 

~~ Member of Congress 

Paul 

~a~ Gosar 

Member of Congress 

Todd 

~~ Rokita 

Member of Congress 
118 

SUBMITTED BY THE HONORABLE CHARLES MCCONNELL

September 2011 

preQ?red for: 

American Coalition for Clean Coa! Electricity 
119 

Project Team 

David Harrison, Jr., Ph.D. 

Andrew Foss 

James Johndrow 

Eugene Meehan 

Bernard Reddy, Ph.D. 

Anne Smith, Ph.D. 

Copyright © 20 II National Economic Research Associates, Inc. All rights 

reserved. This report was commissioned by the American Coalition for Clean Coal 

Electricity. It reflects the research, opinions and conclusions of its authors and does 

not necessarily reflect those of National Economic Research Associates, Inc. 

(NERA) or any of its clients. 

Public information and industry and statistical data are from sources we deem to be 

reliable; however, we make no representation as to the accuracy or completeness of 

such information and have accepted the information without further verification. 

The findings contained in this report may contain predictions based on current data 

and historical trends. Any such predictions are subject to inherent risks and 

uncertainties. In particular, actual results could be impacted by future events that 

cannot be predicted or controlled, including, without limitation, changes in business 

strategies, changes in market and industry conditions, and changes in law or 

regulations. NERA accepts no responsibility for actual results or future events. 

The opinions expressed in this report are valid only for the purpose stated herein 

and as of the date of this report. No responsibility is taken for changes in market 

conditions or laws and regulations, and no obligation is assumed to revise this 

report to reflect changes, events or conditions, which occur subsequent to the date 

hereof. This report is intended to read as a whole. Separation or alteration of any 

section or page is forbidden and would invalidate the report. 

This report does not represent investment advice nor does it provide an opinion 

regarding the fairness of any transaction to any and all parties. There are no third 

party beneficiaries with respect to this report, and NERA does not accept any 

liability to any third party. In particular, NERA shall not have any liability to any 

third party in respect of the contents ofthis report or any actions taken or decisions 

made as a consequence of the results, advice or recommendations set forth herein. 

NERA Economic Consulting 

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Tel: +1 617 927 4500 

Fax: +1 617 927 4501 

www.nera corn 
120 

Contents 

Executive Summary ................................................................................................................ E-l 

A. Background ................................................................................................................. E-l 

B. Objectives and Methodology of This Study ................................................................. E-2 

C. Results of This Study .................................................................................................. E-3 

I. Introduction ............................................................................................................................. 1 

A. Background ..................................................................................................................... I 

B. Objectives of This Report ................................................................................................ 2 

C. Outline of This Report ..................................................................................................... 3 

II. Overview of Methodologies and Policies ................................................................................ 4 

A. Modeling Framework ...................................................................................................... 4 

B. Overview of Policies Modeled ......................................................................................... 6 

III. Study Results ........................................................................................................................ 9 

A. Coal Unit Retirements ..................................................................................................... 9 

B. Electricity and Energy Market Impacts .......................................................................... 10 

C. Economic Impacts ......................................................................................................... 14 

IV. References .......................................................................................................................... 17 

Appendix A: Compliance Measures and Cost Estimates 

Appendix B: Coal Unit Retirement Model 

Appendix C: Energy Market Modeling 

Appendix D: Macroeconomic Modeling 

NERA Economic Consulting 
121 

Executive Summary 

Executive Summary 

This report evaluates the potential energy and economic impacts of four major environmental 

regulations that would affect the electricity sector. The regulations include two major air 

emission policies-the Cross-State Air Pollution Rule (CSAPR) and regulation of mercury and 

other hazardous emissions (Utility MACT)-as well as policies to regulate coal combustion 

residuals (CCR) under the Resource Conservation and Recovery Act and to regulate cooling 

water intake under Section 316(b) of the Clean Water Act. We focus on the potential near- and 

medium-term (2012-2020) implications for electricity and other energy prices and for national 

economic impacts. This methodology is designed to complement analyses of individual 

regulations, including assessments of their social benefits and costs. 

A. Background 

Environmental legislation provides the mandate for the development of individual regulations. 

The U.S. Environmental Protection Agency (EPA)-sometimes in conjunction with state 

environmental agencies--develops regulations to implement these Congressional directives. 

EPA typically proposes a single regulation and provides information on its individual social 

costs and benefits (and other impacts), with previously-promulgated regulations being included 

in the baseline and the implications of other potential future regulations not considered. 

In addition to analyses of individual regulations and their social costs and benefits, however, 

there are other impacts of environmental regulations that are of interest to policy makers but that 

are not necessarily included in regulatory analyses. Interest in "green jobs" has provided one 

additional focus. Some studies have noted that environmental mandates will increase 

employment in pollution control and clean technology sectors (see, e.g., Ceres 2010). Other 

commentators, however, have noted that these results ignore the jobs lost in the rest ofthe 

economy due to other impacts ofthe regulations, including increased electricity and other energy 

prices (see, e.g., Montgomery 2011). 

There also has been a concern that focusing on individual regulations neglects the cumulative 

effects of multiple environmental regulations. Since these initiatives tend to increase future costs 

for coal-fired power plants, many studies have assessed the potential for regulations to lead to 

increases in coal unit retirements-since owners of some coal-fired power plants will choose to 

retire their units rather than install expensive control equipment-and some ofthese studies have 

assessed the possibility of impacts on electric system reliability.! Projections for a continuation 

of the recent trend of low electricity prices---<lriven by low natural gas prices-tend to increase 

pressures for coal unit retirements. Coal unit retirements and compliance costs for units that do 

not retire in tum can lead to increases in electricity and natural gas prices and decreases in coal 

prices. These changes in energy market conditions can lead to changes in output and 

employment. 

See Bipartisan Policy Center (2011), Brattle Group (2010), Charles River Associates (20 lOb), Edison Electric 

Institute (2011), ICF International (2010), MJ. Bradley & Associates and Analysis Group (2011), and Nocth 

American Electric Reliability Corporation (2010). 

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Executive Summary 

B. Objectives and Methodology of This Study 

This study develops a set of models to evaluate the potential effects of various environmental 

regulations on energy markets and economic activity. This methodology thus complements those 

that have been developed to estimate the costs and benefits-and other impacts--{)f individual 

regulations. 

Specifically, this report develops estimates of the effects over the period from 2012 to 2020 of 

the four environmental regulations-the two air emission regulations as well as CCR and Section 

316(b)-in three major areas: 

1. Coal unit retirements. These are estimates of the effects of potential costs on future coal unit 

retirements. As noted, we develop a probability distribution based upon the range of 

uncertain parameters. 

2. Electricity and other energy market impacts. These impacts include the potential effects on 

energy markets-including coal, natural gas, and electricity-as well as on overall 

compliance costs. 

3. Economic impacts. These effects include impacts on the U.S. economy, including 

employment, gross domestic product (GDP), and disposable personal income (i.e., personal 

income after taxes). 

The modeling framework begins with a set of detailed estimates ofthe likely compliance 

technologies-and their costs-associated with the individual regulations. These assessments are 

based upon the requirements of the individual regulations, including taking into account the 

potential flexibility provided under CSAPR? For the CCR and Section 316(b) regulations, we 

use EPA estimates of compliance costs for the various affected units. The result is a set of 

estimates ofthe potential technologies and costs to individual electricity generating units under 

the four policies. 

The next task is to estimate the effects of these projected costs on future retirements of coal-fired 

power plants. The retirement model we develop is a Monte Carlo uncertainty model designed to 

predict potential economic retirements based upon comparisons ofthe future costs of the coalfired unit in comparison to the costs of the likely new generation that would be added in the 

future. The model incorporates uncertainties in key parameters affecting this comparison, 

including control costs and electricity and fuel (notably natural gas) prices; the model also takes 

account of the feedback effects of coal unit retirements on electricity and fuel prices. 

The estimated coal unit retirements and the estimated compliance costs for non-retiring units are 

then input to the U.S. Department of Energy's National Energy Model System (NEMS) model, a 

well-established modeling framework used by the Energy Information Administration (EIA) to 

evaluate energy and environmental policies. To develop estimates of changes in employment and 

2 The implications of the emissions trading provisions of CSAPR for technology choices at individual units are 

developed through an initial run of the NEMS model (a model that is described in the text). 

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Executive Summary 

other economic impacts, the NEMS results are input to the Policy Insight Plus model developed 

by Regional Economic Models, Inc. (REMI PH), a model used extensively by numerous 

government agencies and private groups to assess the economic impacts of public and private 

policies. 

Although we have attempted to develop comprehensive assessments, the results should be 

viewed as subject to considerable uncertainties beyond those incorporated in the analyses. 

Projected coal unit retirements, for example, do not include the effects of other potential 

regulatory requirements-notably those related to greenhouse gases--and the impacts do not 

include potential effects of coal unit retirements on (or constraints related to) electricity system 

reliability. These omitted factors could lead to additional impacts beyond those estimated in this 

study. 

C. Results of This Study 

1. Coal Unit Retirements 

The potential costs ofthe four policies are estimated to lead to 39 gigawatts (OW) of prematurely 

retired capacity by 2015 among the current coal-fired power plants. This estimate represents 

additional retirements above those in the reference case (i.e., retirements predicted without the 

four regulations in place) and accounts for about 12 percent of the 2010 U.S. coal-fired 

electricity generating capacity.3 As noted, this estimate does not include the potential effects of 

other potential requirements--notably potential greenhouse gas emission regulations--or 

concerns related to detailed electricity system reliability. 

2. Energy Market Effects 

As noted, the energy market impacts ofthe various regulations were estimated using the National 

Energy Modeling System (NEMS) based on estimates of the coal units that retire and the 

compliance costs for units that do not retire. The NEMS output includes estimates of overall 

compliance costs for the electric sector as well as detailed impacts on energy markets. 

Table ES-J summarizes the potential costs for the electricity sector based on the level of coal 

retirements predicted in the retirement model. These costs include compliance costs for coal 

units that do not retire, capital costs for new capacity that would replace retiring coal units, and 

changes in fuel costs. Costs are projected to be approximately $21 billion (in 2010$) per year 

over the period from 2012 to 2020. The costs represent a total of$127 billion (present value in 

2010$ as ofJanuary 1,2011) over the period from 2012 to 2020. Capital costs for environmental 

controls and replacement capacity are about $104 billion.4 

3 This level of retirements is estimated in the retirement model and is not influenced by utility retirement 

announcements. 

4 Capital costs exceed the total for environmental controls and replacement capacity because of net reductions in 

operating and maintenance costs. 

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Table ES-1. Electricity Sector Costs, 2012-2020 (billion 2010S) 

Environmental Controls 

Replacement Capacity 

Fuel 

Total 

Annual Avg 

$15 

$2 

~ 

$21 

PV 

$89 

$11 

~ 

$127 

Executive Summary 

Note: Compliance costs from 2012 through 2020 are discounted to January 1,20 II using a real annual discount 

rate of 7 percent. 

Annual average costs are based on the present va lues and discounting. 

The cost of environmental controls includes net cost savings for operating and maintenance (O&M) 

expenses. 

Source: NERA calculations as explained in text 

The retirement of coal units and construction of replacement capacity affect electricity sector 

fuel consumption, fuel prices, and electricity prices. Table ES-2 summarizes the average 

potential energy market effects of the four regulations from 2012 to 2020. Appendix C provides 

information on the annual effects for 2012-2020, with effects that are both higher and lower than 

these average values. 

Table ES-2. Average Annual Energy Market Impacts, 2012-2020 

Coal Coal-Fired Coal Price at Gas-Fired Gas Price at Avg Retail 

Retirements Generation Minemouth Generation Hen!}': Hub Elec Price 

(GW) (million MWh) (2010$llon) (million MWh) (2010$IMMBlu) (2010$lMWh) 

Reference 

CSAPR+MACT+CCR+316(b) 42,2 1,699 $31,61 766 $4,95 $92,52 

Note: Coal retirements are cumulative from 2010 through 2020. 

Source: NERA calculations as explained in text 

Coal-fired generation is projected to decrease by an average of 11.1 percent over the period from 

2012 to 2020. The reduction in coal demand is projected to decrease coal prices by 5.7 percent 

on average. In contrast, the regulations are predicted to increase natural gas-fired generation by 

19.7 percent on average over the period and increase Henry Hub natural gas prices by 

10.7 percent on average. The increases in natural gas prices would lead to an estimated average 

increase in costs of about $8 billion per year for residential, commercial and industrial natural 

gas consumers, which translates into an increase of$52 billion over the 2012-2020 period 

(present value in 20 I 0$ as of 20 II discounted at 7 percent). Average U.S. retail electricity prices 

are projected to increase by an average of 6.5 percent over the period. Information on the annual 

energy market effects from 2012 to 2020 is provided in Appendix C. 

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Executive Summary 

3. Economic Impacts 

The potential economic impacts ofthe four policies were estimated using the REMI PI+ model. 

Table ES-3 summarizes the potential economic impacts. The table shows both the average 

annual changes over the period from 2012 to 2020 as well as the cumulative effects over the 

same time period. These net figures take into account jobs that would be created in some sectors 

as a result of spending on pollution controls (Le., "green jobs") as well as jobs lost due to higher 

electricity prices and other negative impacts. 

Table ES-3. U.S. Economic Impacts, 2012-2020 

Employment 

Gross Domestic Product 

Disposable Personal Income 

Disposable Personal Income per Household 

Note: All dollar values are in 2010$. 

Annual Average Cumulative 

-183,000 jobs -1.65 million job-years 

-$29 billion -$190 billion 

-$34 billion -$222 billion 

-$270 -$1,750 

The cumulative employment impact is an \U1discounted sum from 2012 to 2020; the cumulative GDP and 

disposable personal income impacts are present values as of January 1, 20 II using a real annual discount 

rate of 7 percent. 

Disposable personal income impacts per capita from REM! were converted to disposable personal income 

impacts per household based on a current average u.s. household size of2.58 people (Census 2011). 

Source: NERA calculations as explained in text 

Over the period from 2012 to 2020, about 183,000 jobs per year are predicted to be lost on net 

due to the effects of the four regulations. The cumulative effects mean that over the period from 

2012 to 2020, about 1.65 million job-years of employment would be lost. As noted, these net 

employment losses reflect net gains in some sectors and net losses in others. Of the 70 sectors in 

the REMI PI+ model, sectors that would gain jobs account for about 55,000 added jobs per year 

on average, and sectors that would lose jobs account for about 238,000 fewer jobs per year on 

average. On a cumulative basis over the period from 2012 to 2020, the sectors that would gain 

jobs represent about 499,000 job-years, and the sectors that would lose jobs represent about 

2,149,000 job-years. 

Table ES-3 also shows the potential near- to medium-term impacts on GDP and disposable 

personal income. U.S. GDP would be reduced by $29 billion each year on average over the 

period, with a cumulative loss from 2012 to 2020 of$190 billion (2010$). U.S. disposable 

personal income would be reduced by $34 billion each year on average over the period, with a 

cumulative loss from 2012 to 2020 of$222 billion (2010$). The average annual loss in 

disposable personal income per household is $270, with a cumulative present value loss of about 

$1,750 (2010$) over the period from 2012 to 2020. Annual economic impacts from 2012 to 2020 

are provided in Appendix D. 

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Introduction 

I. Introduction 

This report examines various effects of environmental regulations being developed by the U.S. 

Environmental Protection Agency (EPA) that affect the electric utility sector. We focus on the 

cumulative effects offour major environmental regulations on the energy sector and on 

economic activity, including employment and other measures. 

A. Background 

EPA has proposed major air emissions and other regulations in recent years. The two air 

regulations that are likely to have the greatest effect on the electric utility sector are the CrossState Air Pollution Rule (CSAPR) and the regulations of mercury and other hazardous air 

emissions under Section 112 of the Clean Air Act (Utility MACT). These two regulations are at 

different stages of development. CSAPR was promulgated as a final rule in August 2011 

(although there are some outstanding issues that EPA continues to review). Utility MACT was 

proposed in May 2011 and is expected to be made final in November 2011. 

In addition to these two major air emissions rules, electric utility plants face other potential 

environmental regulatory requirements that would require additional investments. EPA recently 

has proposed a regulation under Section 316(b) of the Clean Water Act that regulates cooling 

water intake structures from electric power plants (and other facilities) in order to reduce losses 

to fish and other aquatic organisms. In addition, EPA has proposed regulations under the 

Resource Conservation and Recovery Act that would change how some plants manage their solid 

waste streams (the ashes from the burned coal and the sludge from their flue gas desulfurization 

(POD) systems). Our assessments focus on the two air emission regulations and the 316(b) and 

CCR regulations; electricity generating units face environmental costs for other potential 

regulatory requirements-notably including those related to greenhouse gases--that are not 

included in our estimated impacts. 

The EPA has developed assessments of the potential impacts of these various regulations and 

proposed regulations in separate regulatory impact analyses (RIAs). These RIAs provide 

important information on the potential social costs and social benefits of the proposed 

regulations as well as their potential effects on the energy sector. The public comments provide 

other information on the potential effects ofthe individual rules. Information on individual 

regulations, however, is limited because it does not measure the cumulative effects of many 

potential regulatory requirements either on individual power plants or on energy markets. 

In the face ofthe limited infonnation provided by evaluating individual regulations, various 

studies have evaluated the combined effects of various EPA regulations. Most of the studies have 

evaluated impacts on potential retirements of coal-fired units and some studies have estimated 

potential implications for electricity system reliability. 5 These studies differ substantially in the 

, See Bipartisan Policy Center (2011), Brattle Group (2010), Charles River Associates (2010b), Edison Electric 

Institute (2011), ICF International (2010), M.l Bradley & Associates and Analysis Group (2011), and North 

American Electric Reliability Corporation (2010). Note that the ability of these national studies to evaluate 

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Introduction 

environmental regulations they evaluate and in the nature of their evaluations. The prospect of 

substantial expenditures for pollution controls results in additional projected coal unit 

retirements, as every prior study has found. 

The potential economic impacts of these rules-including their potential effects on employment 

and other measures of economic activity-have been less studied than their impacts on potential 

coal unit retirements, although some studies have considered potential economic impacts of 

some aspects of the regulations. For example, Ceres (2010) has developed estimates of the 

potential positive effects ofthe regulations on employment related to expenditures for emission 

controls. As various commentators have noted, however, this study did not provide information 

on the potential negative effects of higher electricity prices and other means of financing the 

added costs (see, e.g., Montgomery 2011). To our knowledge, no other study has estimated the 

cumulative economic impacts that include both the positive and negative effects of these four 

major regulations. 

B. Objectives of This Report 

The overall objective of this report is to provide estimates of the cumulative energy and 

economic effects of these four environmental regulations over the period from 2012 to 2020. 

That is, we consider the potential effects of these regulations on energy markets as well as on 

employment and other measures of economic activity. We have developed a modeling 

framework to estimate these various effects. We emphasize, however, that we have not 

developed estimates of the potential social benefits and social costs of these regulations and do 

not evaluate whether the individual regulations~r possible regulatory alternatives-would be 

desirable from a societal perspective. 

In particular, the assessments presented in this study include the following three major types of 

effects. 

1. Coal unit retirements. We consider the potential effects of regulatory requirements on coal 

unit retirement decisions based upon various key uncertainties, including the level offuture 

natural gas and coal prices as well as the level of compliance costs. We use the results from 

this modeling framework to develop potential ranges oftotal u.s. coal unit retirements. 

2. Energy market effects. We use information on predicted coal unit retirements as well as 

information on control costs for units that are not expected to retire to develop estimates of 

the potential effects of the policies on electricity and other energy markets. The results 

include estimates of the total compliance costs for the electricity sector due to the 

regulations, including control costs (capital as well as operation and maintenance), changes 

in fuel costs, and the costs of additional capacity added. 

3. Economic impacts. The economic impacts of the regulations-including effects on 

employment, gross domestic product (GDP), and disposable personal income (i.e., personal 

impacts on electricity system reliability is limited, since reliability impacts are likely to be sensitive to various 

system details (e.g., local transmission and voltage constraints) that are not included in the studies. 

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Introduction 

income after taxes)-are estimated by using the energy impacts in an economic impact 

model. 

There are substantial uncertainties involved in developing these estimates. As discussed below, 

the model we use to develop estimates of coal unit retirements incorporates key uncertainties. It 

is important to emphasize, however, that other uncertainties are not modeled-including the 

possibility that coal and other units will face potential regulations related to greenhouse gasesand thus the projections presented in this report should be viewed as estimates ofthe likely 

impacts of only the four policies evaluated. 

C. Outline of This Report 

The remainder of this report is organized as follows. Chapter II provides an overview of the 

methodologies that are used and the policies that are evaluated in the study. Chapter III presents 

the results of the analyses. The appendices provide details on the models, compliance 

assumptions, methodologies, and results. 

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Overview of Methodologies and Policies 

II. Overview of Methodologies and Policies 

This chapter provides summary information on the methodologies used to estimate the potential 

economic impacts of the four policies. We also provide overviews ofthe four environmental 

policies that are modeled. Additional details ofthe models, policies, and data are provided in the 

appendices. 

A. Modeling Framework 

The methodology used in this study is based upon a set oflinked models designed to assess the 

energy and economic impacts of environmental regulations affecting the electric utility sector. 

The empirical estimates of policy impacts are developed by comparing impacts under a baseline 

case (Le., a case without the policies in place) and impacts under the policy case. 

1. Overview of Modeling Framework 

The modeling framework consists of three principal elements: 

1. Retirement Model, which estimates whether coal units would be expected to retire based 

upon comparisons ofthe expected value of the future costs for the coal unit-including the 

likely potential costs of additional environmental controls-and the expected costs of an 

equivalent new natural gas combined cycle unit; 

2. National Energy Modeling System (NEMS) model developed by the U.S. Energy Information 

Administration (EIA), which we use to assess the likely effects of compliance costs and coal 

unit retirements on the energy markets; and 

3. Policy Insight Plus model developed by Regional Economic Models, Inc. (REM! PI+), which 

we use to develop estimates of the economic impacts of energy market effects. 

The following sections provide summaries ofthese elements. 

2. Coal Unit Retirement Model 

Power companies face the choice of retrofitting existing coal units to meet regulations or retiring 

them if the future costs do not justify continued operation in light of the likely costs of 

alternative sources to meet filture electricity demand. We developed a detailed model to evaluate 

whether existing coal units in the United States would be expected to retire taking into account 

the potential costs of retrofit (and other future costs) as well as uncertainties in energy prices and 

other factors. 

The retirement model is designed to mirror the decision by power companies on whether to 

retrofit coal-fired units with environmental controls or retire them and replace them with new 

capacity. A Monte Carlo formulation takes into account major uncertainties involved in this 

decision. 

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Overview of Methodologies and Policies 

The model begins with estimates ofthe potential additional costs related to environmental 

policies. The potential future costs for coal units are based upon EIA data on unit characteristics 

(including capacity, capacity factor, heat rate, O&M costs, coal type, and current environmental 

controls) and on EPA information on the potential costs ofthe various controls. The potential 

technologies and costs for each coal-fired unit also reflect the flexibility that CSAPR providesdue to the potential for emissions trading-as well as the fuel and electricity prices based upon a 

similar level ofretirements.6 The model thus takes account ofthe feedback effects of coal unit 

retirements on electricity and fuel prices. 

The model uses statistical techniques and EPA data to simulate hourly electricity prices in each 

region-as a function of natural gas prices, time of day, season, peak/off-peak, and other 

factors-and generation decisions by coal units and potential replacement capacity, with 

generation a function of price and marginal cost. Uncertain parameters include the costs of 

controls, fuel prices and electricity prices, and the costs of the likely replacement alternative (a 

new natural gas combined cycle unit), with interactions among the uncertain parameters included 

in the Monte Carlo formulation. 

Future coal unit costs are compared with the future costs of a new natural gas combined cycle 

unit by calculating the difference between the cost of the coal unit and the cost ofthe natural gas 

alternative in each ofthe 100 Monte Carlo draws. The unit is presumed to retire if the expected 

value ofthe cost difference is positive, i.e., on expectation, the coal unit would have greater 

future costs than a new natural gas combined cycle unit. Existing coal unit remaining lifetimes in 

these calculations are assumed to range between 10 and 20 years, depending upon unit age in 

2015, to reflect the likelihood that owners of older units will have a shorter time horizon for 

recovering the cost of additional controls. The formulation accounts for the costs of using system 

energy during hours when coal units and the potential replacement capacity would not run. 

3. NEMS Model 

The National Energy Modeling System (NEMS) is a computer-based, energy-economy modeling 

system of the U.S. through 2030. NEMS projects the production, imports, conversion, 

consumption, and prices of energy, subject to assumptions on macroeconomic and financial 

factors, world energy markets, resource availability and costs, behavioral and technological 

choice criteria, cost and performance characteristics of energy technologies, and demographics. 

NEMS was designed and implemented by the Energy Information Administration (EIA) ofthe 

U.S. Department of Energy (DOE). 

4. Regional Economic Models, Inc. Policy Insight Plus Model 

The Regional Economic Models, Inc. (REMI) Policy Insight Plus (PH) model produces 

estimates ofthe changes in employment, GDP, disposable personal income, and other 

macroeconomic variables due to changes in supply, demand, prices, and other types of inputs. 

Each version of the REMI PH model is custom-built for the regions of interest, which can range 

6 We develop the implications of emissions trading flexibility provided by CSAPR by running the NEMS model 

with the relevant caps. The technologies identified in this run for each unit are used in the retirement model. 

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Overview of Methodologies and Policies 

from counties to entire countries. The REMI PI+ model incorporates detailed and up-to-date 

macroeconomic data from the U.S. Bureau of Economic Analysis, the U.S. Bureau of Labor 

Statistics, the U.S. Census Bureau, and other public sources. The REMI PI+ model is widely 

used by federal, state, and local agencies, as we II as analysts in the private sector and academia, 

to estimate the effects of regulations, investments, closures, and other scenarios. 

B. Overview of Policies Modeled 

This section summarizes the four policies evaluated in this report, including the two air emission 

regulations (CSAPR and Utility MACT) as well as Section 316(b) and CCR. Appendix A 

provides details on how the reference case and the four policies are modeled, including 

information on the control cost assumptions that are used. 

1. Reference Case 

The version ofNEMS used for the model represents current legislation and environmental 

regulations as ofJanuary 31, 2011. The policies included in the reference case include state 

requirements for reduction of mercury emissions but not the Clean Air Mercury Rule, which was 

vacated and remanded by the D.C. Circuit Court ofthe U.S. Court of Appeals on February 8, 

2008. The reference case also includes the temporary reinstatement of the SOz and NOx cap-andtrade programs included in the Clean Air Interstate Rule (CAIR) as a result ofthe ruling issued 

by the United States Court of Appeals for the District of Columbia on December 23, 2008.7 

CAIR is included in the reference case through 2011. From 2012 onward, SOz and NOx caps 

revert to pre-CAIR levels. 

Proposed federal and state legislation, regulations, or standards-and sections oflegislation that 

have been enacted but require funds or implementing regulations that have not been provided or 

specified-are not reflected in the reference case. The excluded policies include the four policies 

evaluated in our study.8 

2. Cross-State Air Pollution Rule 

EPA promulgated CSAPR in August 2011, following a draft rule (Clean Air Transport Rule, or 

CATR) proposed in August 2010 as a replacement to CAIR. CSAPR requires 27 states to reduce 

power plant emissions of sulfur dioxide (SOz) and nitrogen oxides (NOx) from power plants in 

Eastern states in an effort to improve ozone and fine particulate air quality in other downwind 

states.9 Under CSAPR, EPA set new limits on S02 and NOx emissions for each state beginning 

in 2012. The limits tighten in some states in 2014. 

7 EPA finalized CAIR in 2005 but the rule was remanded to EPA by the D.C. Circuit Court of Appeals in 2008. 

The court decision required EPA to develop a different regulatory approach but to implement CAIR in the 

meantime. 

8 Note that we include CSAPRin our assessments although EPA finalized CSAPR in August 2011 (EPA 201Ia). 

9 In a separate but related regulatory action, EPA also issued a supplemental notice of proposed rulemaking to 

require six states to make summertime NOx reductions under the CSAPR ozone-season program. Finalizing this 

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Overview of Methodologies and Policies 

3. Utility MACT 

EPA proposed the Utility MACT rule in May 2011 to reduce emissions of mercury and other 

hazardous air pollutants (including other hazardous metals and acid gases) from coal- and oilfired power plants across the country. The rule would set emission rate standards for different 

types of coal- and oil-fired units based on maximum achievable control technology. The 

emission rate standards would apply to mercury, other non-mercury metallic hazardous air 

pollutants (using particulate matter as a proxy), and acid gases (using hydrogen chloride as a 

proxy). Covered power plants would have up to three years to comply with the rule, but 

permitting authorities could grant one-year extensions to power plants if they required additional 

time. 

4. Coal Combustion Residuals 

EPA issued a proposed rule on June 21, 2010 related to the regulation of coal combustion 

residuals (also referred to as coal combustion waste) under the Resource Conservation and 

Recovery Act (RCRA). The regulations apply to the management of coal combustion residuals 

generated by steam electric power plants (i.e., electric utilities and independent power producers) 

that are disposed of in landfills and surface impoundments. 

EP A co-proposed two approaches to the regulation of coal combustion waste. The first would 

regulate residuals under Subtitle C ofRCRA as a "special waste." The second would regulate 

residuals under Subtitle D as a non-hazardous waste. Our assessments are based on the potential 

costs to individual units of regulating coal combustion residuals under Subtitle D. 

5. Clean Water Act Section 31S(b) 

On April 20, 2011, EPA proposed cooling water intake requirements for existing power plants 

and other industrial facilities under Section 316(b) of the Clean Water Act. These facilities 

withdraw water and in the process, fish and other aquatic organisms are lost if they become 

trapped against intake screens ("impingement") or pulled into the cooling system 

("entrainment"). Various technologies reduce impingement and entrainment losses, including 

the retrofit of plants with cooling towers to provide closed-cycle cooling. 

EPA evaluated four alternatives for setting Section 316(b) standards, with Option I identified as 

its preferred option. Option 1 would require that existing plants withdrawing water above a 

proposed 2 million gallon per day threshold reduce the impingement mortality by meeting 

various national standards (EPA 2011b, pp. 22203-22204). In contrast, entrainment controls 

would be set on the basis of site-specific requirements. Under EPA's proposal, permit writers 

will be required to consider converting the condenser cooling system from once-through cooling 

to closed-cycle cooling through the use of cooling towers, which reduces net flow and thus 

entrainment losses (albeit at substantial cost and often undesirable environmental side-effects). 

EPA estimated the cost of installing cooling towers under Option 1 at the 46 fossil units with the 

supplemental program would bring the total number of covered states under the CSAPR to 28. EPA reports that 

it is proposing to finalize this proposal by late full 2011. 

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Overview of Methodologies and Policies 

largest cooling water withdrawals from tidal waters. Our assessments are based on the potential 

costs to individual units of the Option 1 alternative. 

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Study Results 

III. Study Results 

This chapter summarizes the study results for our analyses of the cumulative energy and 

economic impacts of the four environmental policies. The results are grouped into three 

categories: (I) coal unit retirements; (2) energy market effects; and (3) economic impacts. 

Additional details are provided in the appendices. 

A. Coal Unit Retirements 

1. National Results 

The potential costs of the four policies are estimated to lead to 39 gigawatts (OW) of prematurely 

retired capacity among the current coal-fired power plants. This figure represents additional 

retirements above those in the reference case (i.e., retirements predicted without the four 

regulations in place) and accounts for about 12 percent of the 2010 U.S. coal-fll'ed electricity 

generating capacity. As noted, this estimate does not include the potential effects of other 

potential requirements-notably potential greenhouse gas emission regulations--or concerns 

related to detailed electricity system reliability. 

We developed an assessment ofthe potential range of possible retirements using the information 

from the 100 individual draws from the retirement model. We calculated the retirements in each 

ofthe draws as a sensitivity analysis, assuming that a unit would retire if its future costs were 

greater that the future costs ofthe natural gas unit in those circumstances. The range of 

retirements was from 17 OW to 79 OW in these 100 cases. This range is roughly consistent with 

sensitivity results from other studies, although the other studies do not use the same assumptions 

and methodology.lo 

2. Uncertainties Regarding Estimated Retirements 

The range of potential retirements provides an indication of the substantial uncertainty 

surrounding potential retirements due to uncertainties in future natural gas prices, control costs 

and other factors influencing individual retirement decisions. There are, however, some factors 

that are not included in the retirement model. The retirement model does not account for the 

possibility that adjustments could occur if the local effects of retirements were severe (e.g., likely 

to impair electricity system reliability). These adjustments would tend to reduce the actual level 

of retirements below those predicted by our model, which is based upon economic calculations, 

although the potential impacts on electricity prices could be greater than estimated assuming 

units are allowed to retire. 

In addition, the model does not fuctor into the calculation of expected future costs the potential 

costs and other impacts associated with greenhouse gas regulations. Even without the prospect of 

]0 ErA, for example, reports a range of retirements for the two air emissions regulations from 4.7 GWto 63.8 GW 

(net of reference case retirements) depending upon the level of future natural gas prices as well as the likely time 

horizon for amortizing compliance capital costs (EIA 2011, p. 50). 

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Study Results 

specific regulatory requirements, owners of coal-fired power plants are likely to reflect the 

prospect of potential greenhouse gas regulations in their decisions on whether to incur large 

compliance expenditures or retire their units. Our estimates do not take into account these 

effects, which would lead to greater coal unit retirements. 

3. Regional Results 

The expected coal unit retirements differ substantially among electricity regions. Table I shows 

the potential coal unit retirements by North American Electric Reliability Corporation (NERC) 

regionY The table also shows the percentage of2010 coal capacity in each region that is 

predicted to retire by 2015 and each region's share of total U.S. retirements. Note that most 

retirements are in the Mid-Atlantic and Great Lakes and Southeast regions. These results are 

consistent with the results of other studies (e.g., Brattle Group 2010). 

Table 1. Regional Retirement Estimates 

2010 Coal Retirements % of Regional % of Total 

Capaci~ !GW) (GW) 2010 Coal Cap Retirements 

U.S. Total 318.1 39.1 12% 100% 

NERC Regions 

NPCC Northeast 5.7 1.3 22% 3% 

RFC Mid-Atlantic and Great Lakes 107.8 14.5 13% 37% 

SERC Southeast 98.5 18.0 18% 46% 

FRCC Florida 10.3 0.1 1% 0% 

MRO Upper Midwest 28.8 1.9 6% 5% 

SPP Oklahoma and Kansas 19.0 1.6 9% 4% 

ERCOT Texas 18.2 0.6 3% 1% 

WECC West 29.8 1.2 4% 3% 

Source: NERA calculations as explained in text 

B. Electricity and Energy Market Impacts 

As described in the previous section, we used NEMS to estimate net changes in coal-fired 

generation, natural gas-fired generation, fuel prices, and electricity prices as a result of coal unit 

retirements and environmental controls due to the four policies. 

1. National Results 

Table 2 summarizes the potential costs for the electricity sector based on the level of coal 

retirements predicted in the retirement model. These costs include compliance costs for coal 

units that do not retire, capital costs for new capacity that would replace retiring coal units, and 

changes in fuel costs. Costs are projected to be approximately $21 billion (in 2010$) per year 

over the period from 2012 to 2020. The costs represent a total of$127 billion (present value in 

II NEMS provides information for 22 regions; we have aggregated the results into the eight major NERC regions. 

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20 I 0$ as of January 1,2011) over the period from 2012 to 2020. Capital costs for environmental 

controls and replacement capacity are approximately $104 billion. 12 

Table 2. Electricity Sector Costs, 2012-2020 (billion 2010$) 

Environmental Controls 

Replacement Capacity 

Fuel 

Total 

Annual Avg 

$15 

$2 

i2 

$21 

PV 

$89 

$11 

~ 

$127 

Note: Compliance costs ITom 2012 through 2020 are discounted to January t, 2011 using a real annual discount 

rate of7 percent. 

Annual average costs are based on the present values and discounting. 

The cost of environmental controls includes cost savings for operating and maintenance (O&M) 

expenses. 

Source: NERA calculations as explained in text 

Table 3 summarizes the average effects of the four policies at the national level over the period 

from 2012 to 2020. (Detailed annual impacts are provided in Appendix C, with effects that are 

both higher and lower than thesc average values.) 

Table 3. Ave"age Annual Energy Market Impacts, 20\2-2020 

Coal Coal-Fired Coal Price at Gas-Fired Gas Price at Avg Retail 

Retirements Generation Minemouth Generation Henry Hub Elec Price 

(GW) (million MWh) (2010$/lon) (million MWh) (2010$/MMBlu) (2010$lMWh) 

Reference 

CSAPR+MACT +CCR+316(b) 

Note: Coal retirements are cumulative from 2010 through 2020. 

Source: NERA calc.ulations as explained in text 

The potential impacts of the four policies on energy markets are substantial. 

Coal-fired generation is predicted to decrease substantially, by an average of 11.1 percent 

relative to average reference case levels over the 2012-2020 period. 

In contrast, natural gas-fired generation is predicted to increase substantially, by an average 

of 19.7 percent relative to average reference case levels over the same period. 

12 Capital costs exceed the total for environmental controls and replacement capacity because of net reductions in 

operating and maintenance costs. 

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Study Results 

Average coal prices are predicted to decline, reflecting the reduction in coal-fired generation. 

Coal prices decline an average of5.7 percent relative to average reference case levels over 

the same period. 

Average natural gas prices are predicted to increase, reflecting the increased demand for gasfired generation. Henry Hub natural gas prices increase an average of 10.7 percent relative to 

average reference case levels over the 2012-2020 period. These prices increases would 

increase costs by about $8 billion per year for residential, commercial, and industrial 

customers (and a total of about $52 billion as a present value as of January 1,2011 over the 

period). 

Average retail electricity prices are predicted to increase an average of 6.5 percent over the 

same period. 

It is useful to put these predicted impacts into perspective. For example, the predicted effect of 

the four policies on Henry Hub natural gas prices is $0.48IMMBtu. By way of context, the EIA 

reduced its forecast of future Henry Hub natural gas prices by approximately $21MMBtu from 

AEO 2009 to AEO 2011. 

2. Uncertainties Regarding Energy Market Impacts 

The projected energy market impacts due to the four environmental policies are significant. The 

impacts arise both because of substantial compliance costs-that lead a substantial number of 

coal-fired units to retire and force other coal units to incur substantial retrofit costs in order to 

comply-and because of the market reactions to these initial impacts. 

The impacts depend upon many factors, including the baseline conditions-including projected 

future natural gas prices-as well as the details ofthe market reactions to the policy changes that 

are embedded in the NEMS model. The baseline also includes assumptions on the nature of 

future regulatory requirements. As noted above, we modified the baseline in NEMS to evaluate 

the impacts of these air emission policies relative to the absence of similar S02 and NOx policies 

(no CAIR from 2012 onward); EPA made the same assumption in its recent analysis ofCSAPR. 

We have included state mercury requirements in the baseline, which tend to decrease the impacts 

relative to a baseline without the state requirements. 

The electricity market impacts also depend upon a host of specific elements of the electricity 

systems in various regions. Some of these elements are included in the assessments, such as the 

nature of the state regulatory regime. The NEMS results, however, do not include considerations 

related to highly location-specific factors such as transmission security and the time constraints 

on retiring units, particularly relatively large units (ICF 2011). 

3. Regional Results 

NEMS provides energy price results for various regions, including 22 electricity price regions. 

The electricity price impacts ofthe four policies differ by region depending upon many factors 

including the following: 

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reliance on coal-fIred generation under baseline conditions; 

coal unit retirements; 

need for replacement capacity; 

type of replacement capacity that NEMS builds; 

retrofits for coal units that continue to operate as well as the costs of those retrofits; 

capacity factors for coal units; 

regional fuel prices; 

interregional electricity trade; and 

regulatory regime. 

Table 4 provides estimates of the percentage increases in retail electricity rates in the 22 NEMS 

electricity regions due to the four policies. As with the prior results, these figures are based upon 

the average percentage changes over the period from 2012 to 2020. (Detailed annual impacts are 

provided in Appendix C, with effects that are both higher and lower than these average values.) 

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Study Results 

Table 4. Average Electricity Price Impacts, 2012-2020 

2010$/MWh % 

US Average +$5.65 +6.5% 

NEMS Regions 

NEWE New England +$2.93 +2.2% 

NYCW NYC +$6.97 +4.2% 

NYU NY Long Island +$13.00 +8.0% 

NYUP NY Upstate +$6.39 +5.6% 

RFCE Mid-Atlantic +$10.38 +10.7% 

SRVC VA & Carolinas +$4.05 +5.1% 

SRSE Southeast +$6.94 +8.2% 

FRCC Florida +$4.10 +3.9% 

RFCM LowerMI +$7.63 +9.6% 

RFCW OH, IN, &WV +$7.01 +8.6% 

SRCE KY&TN +$8.36 +13.5% 

MROE WI & UpperMI +$6.96 +9.2% 

MROW Upper Midwest +$5.39 +7.8% 

SRGW South IL & East MO +$6.73 +11.1% 

SPNO KS & West MO +$6.42 +8.0% 

SRDA AR, LA, & West MS +$5.16 +7.2% 

SPSO Oklahoma +$8.75 +12.6% 

ERCT Texas +$5.34 +6.9% 

RMPA CO & EastWY +$1.40 +1.5% 

NWPP Northwest +$0.04 +0.1% 

AZNM AZ&NM +$1.40 +1.6% 

CAMX California +$2.25 +1.6% 

Source: NERA calculations as explained in text 

C. Economic Impacts 

As noted, we used the REMI PI+ model to estimate the potential near- and medium-term 

economic impacts of the four policies based upon the energy market impacts estimated in 

NEMS. 

1. Results 

Table 5 summarizes the effects ofthe four policies on various economic impact measures, 

including impacts on employment, GDP, and disposable personal income. The table includes 

information on the average annual changes over the period from 2012 to 2020 as well as the 

cumulative effects over the period (detailed annual impacts are provided in the appendices). 

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Table 5. U.S. Economic Impacts, 2012-2020 

Employment 

Gross Domestic Product 

Disposable Personal Income 

Disposable Personal Income per Household 

Note: All dollar values are in 2010$. 

Annual Average 

-183,000 jobs 

-$29 billion 

-$34 billion 

-$270 

Study Results 

Cumulative 

-1 .65 million job-years 

-$190 billion 

-$222 billion 

-$1,750 

The cumulative employment impact is an undiscounted sum from 2012 to 2020; the cumulative GDP and 

disposable personal income impacts are present values as of January 1,2011 using a real annual discount 

rate of 7 percent. 

Disposable personal income impacts per capita from REM! were converted to disposable personal income 

impacts per households based on a current average U.S. household size of2.58 people (Census 2011). 

Source: NERA calculations as explained in text 

Over the period from 2012 to 2020, about 183,000 jobs per year are predicted to be lost on net 

due to the effects of the four regulations. The cumulative effects mean that over the period from 

2012 to 2020, about 1.65 million job-years of employment would be lost. U.S. GDP would be 

reduced by $29 billion each year on average over this period, with a cumulative loss from 2012 

to 2020 of $190 billion (20 I 0$). U.S. disposable personal income would be reduced by 

$34 billion each year on average over this period, with a cumulative loss from 2012 to 2020 of 

$222 billion (2010$). The average annual loss in disposable personal income per household is 

$270, with a cumulative loss of$I,750 (2010$). 

The four policies would lead to different net employment impacts on different sectors. Of the 70 

sectors in the REMI PI+ model, sectors that would gain jobs account for about 55,000 added jobs 

per year on average, and sectors that would lose jobs account for about 238,000 fewer jobs per 

year on average. On a cumulative basis over the period from 2012 to 2020, the sectors that would 

gain jobs represent about 499,000 job-years, and the sectors that would lose jobs represent about 

2,149,000 job-years. 

2. Uncertainties Regarding Economic Impacts 

The estimated economic impacts of the four environmental policies over the period from 2012 to 

2020 are substantial. These impacts include many factors, including: the positive impacts of 

expenditures on environmental controls and replacement electricity capacity; the negative effects 

of reduced coal sales and reduced coal production; the positive effects of increased natural gas 

sales; both the negative effects of higher natural gas prices on consumers and the positive effects 

on producers; and the negative effects of electricity price effects on consumers. In addition, the 

timing of impacts depends upon how the capital costs of pollution controls and increased 

replacement capacity are financed. The overall impacts are thus a complicated result of a large 

number of positive and negative factors. 

These estimates are subject to various types of uncertainties, including uncertainties regarding 

the energy market and other inputs. As noted above, the coal unit retirements and energy market 

impacts are subject to various uncertainties, which translate into uncertainties regarding the 

economic impacts. There are additional uncertainties regarding the modeling of these economic 

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Study Results 

impacts. The macroeconomic modeling does not, for example, take into account the potential 

negative effect on the overall productivity and growth of the economy of reduced productive 

investment due to the fmancing of pollution control expenditures. The model also does not 

presume that environmental compliance expenditures use any unemployed or idle resources. In 

addition, the model assumes that consumers can shift away from more expensive energy and thus 

reduce the negative impacts of higher natural gas and electricity prices, an assumption that may 

understate the likely negative impacts ofthe price increases. 

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References 

IV. References 

Bipartisan Po licy Center. 20 II. Environmental Regulation and Electric System Reliability. 

Washington, D.C.: Bipartisan Policy Center. 

Brattle Group. 20 I O. Potential Coal Plant Retirements Under Emerging Environmental 

Regulations. Cambridge, MA: Brattle Group, December 8. 

Ceres. 2011. New Jobs-Cleaner Air: Employment Effects Under Planned Changes to the EPA's 

Air Pollution Rules. Report prepared by the University of Massachusetts Political 

Economy Research Institute. Boston: Ceres, February. 

Charles River Associates. 20 lOa. Prospects for an EPA-Driven Capital Crisis for Utilities. 

Boston, MA: CRA, September. 

Charles River Associates. 20 lOb. A Reliability Assessment of EPA's Proposed Transport Rule 

and Forthcoming Utility MACT. Washington, D.C.: CRA, December. 

Edison Electric Institute. 2011. Potential Impacts of Environmental Regulation on the Us. 

Generation Fleet. Report prepared by ICF International. Washington, D.C.: EEl, January. 

Electric Power Research Institute. 20 I O. Cost Analysis of Proposed National Regulation of Coal 

Combustion Residuals from Electric Generating Industry. Palo Alto, CA: EPRI, 

November. 

ICF International. 20 I O. Clean Air, Ash and Water Regulations: Potential Impact of EPA 

Proposed Rules. Fairfax, VA: ICF, October. 

ICF International. 20 II. Retiring Coal Plants While Protecting System Reliability. Fairfax, VA: 

ICF, August. 

M.l Bradley & Associates and Analysis Group. 20 II. Ensuring a Clean, Modern Electric 

Generating Fleet while Maintaining Electric System Reliability. Concord, MA: M.J. 

Bradley & Associates, June. 

Montgomery, W. David. 2011. Prepared Testimony ofW. David Montgomery, Ph.D., before the 

Senate Committee on Environment and Public Works, Subcommittee on Green Jobs and 

the New Economy. February 15. 

North American Electric Reliability Corporation. 2010. 2010 Special Reliability Scenario 

Assessment: Resource Adequacy Impacts of Potential US. Environmental Regulations. 

Princeton: NERC, October. 

U.S. Census Bureau. 20 II. "Profile of General Population and Housing Characteristics: 2010." 

(factfinder2.census.gov/faces/nav/jsfi'pageslindex.xhtml, accessed September 20, 20 II) 

NERA Economic ConsuHing 17 
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References 

U.S. Energy Information Administration. 2011. Annual Energy Outlook 2011. Washington, D.C.: 

EIA, April. (www.eia.gov/forecastsiaeo/pdfl0383(201 I).pdf, accessed September 20, 

2011) 

U.S. Environmental Protection Agency. 2005. "Rule To Reduce Interstate Transport of Fine 

Particulate Matter and Ozone (Clean Air Interstate Rule); Revisions to Acid Rain 

Program; Revisions to the NOX SIP Call; Final Rule." 70 Federal Register 25162. 

Washington, D.C.: EPA, May 12. 

U.S. Environmental Protection Agency. 2010. "Federal Implementation Plans To Reduce 

Interstate Transport of Fine Particulate Matter and Ozone; Proposed Rule." 75 Federal 

Register 45210. Washington, D.C.: EPA, August 2. 

U.S. Environmental Protection Agency. 2011a. "Federal Implementation Plans: Interstate 

Transport of Fine Particulate Matter and Ozone and Correction of SIP Approvals." 76 

Federal Register 48208-48483. Washington, D.C.: EPA, August 8. 

(www.gpo.gov/fdsys/pkg/FR-2011-08-08/pd£l20 11-17600.pdf, accessed September 20, 

2011) 

U.S. Environmental Protection Agency. 2011b. "National Pollutant Discharge Elimination 

System-Cooling Water Intake Structures at Existing Facilities and Phase I Facilities; 

Proposed Rule." 76 Federal Register 22174-22288. Washington, D.C.: EPA, April 20. 

(www.gpo.gov/fdsys/pkg/FR-2011-04-20/pd£l2011-8033.pdf, accessed September 20, 

20ll) 

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Appendix A: Compliance Measures and Cost Estimates 

This appendix provides information on the data and methodologies used to model potential 

compliance measures and compliance costs at coal units for relevant environmental policies in 

the reference case and the four potential EPA regulations (CSAPR, MACT, CCR, and 3l6(b)). 

We begin with information related to the reference case and then provide information related to 

each of the potential EPA regulations. We present our cost assumptions for air emission control 

technologies, which we used as inputs for both the reference case and policy case, at the end of 

this appendix. 

A. Reference Case 

As discussed in the report body, we modeled the energy market impacts ofthe potential EPA 

regulations using the National Energy Modeling System (NEMS), a comprehensive U.S. energy 

model developed and maintained by the U.S. Energy Information Administration (E1A). With 

the exception of the environmental policy inputs discussed in this appendix, we used the same 

inputs to NEMS as EIA used for its Annual Energy Outlook (AEO) 2011 (EIA 20lla). Note that 

the inputs for AEO 2011 which we did not modify include inputs related to various national, 

regional, and state environmental policies that are currently in place, such as state renewable 

portfolio standards and the Regional Greenhouse Gas Initiative. 

The environmental policies in the reference case that are most relevant to the potential EPA 

regulations are the Clean Air Interstate Rule (CAIR) to reduce S02 and NOx emissions from 

power plants and policies to reduce mercury emissions from power plants. EIA describes its 

inputs related to these policies for AEO 2011 in EIA (2011b, pp. 104-107). Table A-I 

summarizes our compliance assumptions related to these policies for our reference case. 

Table A-t. Compliance Assumptions for Reference Case 

Policy Emission Compliance Assnmptions 

CAIR S0 2 Apply Phase I S02 cap (3.6 million tons) through 2011 and allow 

NEMS to determine which units would need to install S02 control 

technologies or switch to lower-sulfur coal in the interstate cap-andtrade program; from 2012 onward, allow S02 cap to revert to pre-CArR 

level (based on Acid Rain Program) 

NOx Apply Phase I NO, cap (1.5 million tons) through 2011 and allow 

NEMS to determine which units would need to install NOx control 

technologies in the interstate cap-and-trade program; from 2012 

onward, allow NO, cap to revert to pre-CAIR level (based on NO, 

Budget Trading Program) 

State Mercury Include mercury reductions as required by state policies and allow 

policies NEMS to determine which units would need to install mercury control 

technologies 

Source: NERA assumptions as explained in text 

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Appendix A: Compliance Measures and Cost Estimates 

1. Clean Air Interstate Rule 

EPA promulgated CAIR in 2005 to reduce S02 and NO, emissions from power plants in 28 

Eastern states (EPA 2005).1 EPA established interstate cap-and-trade programs for both types of 

emissions. The caps for both types of emissions became tighter over two phases. The NO, 

program consisted of Phase I (2009-2014) with a cap of 1.5 million tons and Phase 2 (2015 

onward) with a cap of 1.2 million tons. The S02 program consisted of Phase I (20 10-2014) with 

a cap 00.6 million tons and Phase 2 (2015 onward) with a cap of2.5 million tons. In December 

2008, the U.S. Court of Appeals for the D.C. Circuit remanded CAIR to EPA but did not vacate 

it, thus allowing the first phases of the NO, and S02 programs to take effect while EPA 

developed a replacement rule. 

Our modeling for the reference case reflects that the CAIR Phase I programs have taken effect. 

We applied the CAiR Phase I caps for SOz and NO, emissions (using EIA's inputs for AEO 

2011) through 2011 and allowed NEMS to decide which units would need to install S02 control 

technologies or switch to lower-sulfur coal in the interstate cap-and-trade program. Our NEMS 

inputs for the reference case also include the S02 and NO, control technologies that coal units 

have installed or have announced that they will install to comply with CAIR requirements (or 

any state or local policies requiring reductions in these emissions). EIA (2011, p. 106) 

summarizes the recent and planned retrofits for S02 and NO, policies that are in NEMS. 

As discussed in the report body and below, EPA has promulgated the Cross-State Air Pollution 

Rule (CSAPR) as a replacement for CAiR to take effect in 2012 (EPA 2011a). CSAPR would 

cover a somewhat different set of Eastem states than CAiR but would also involve interstate capand-trade programs and would set the caps at similar levels to CAIR. Thus, including CAIR in 

our reference case from 20 12 onward would make it difficult to isolate the incremental impacts 

of CSAPR. We therefore terminated the CAiR Phase I caps after 2011 in our reference case and 

reverted S02 and NO, caps to pre-CAIR levels (based on the Acid Rain Program and NO, 

Budget Trading Program, respectively). Note that EP A also removed future CAIR caps from its 

reference case for modeling the incremental impacts of CSAPR (EPA 20 II b, pp. 30-32). 

2. State Mercury Policies 

Seventeen states have enacted policies to limit mercury emissions from coal units (EPA 20Ilc, 

pp. 3-8). These state mercury policies vary significantly in their form, stringency, and schedule. 

Some policies took effect as early as 2008, while others will take effect as late as 2017. 

EIA incorporated these state mercury policies into AEO 2011, and we used the same inputs for 

our reference case. To comply with these state mercury policies, some coal units install mercury 

control technologies such as activated carbon injection (AC!) and fabric filters in the reference 

case. We allowed NEMS to determine the compliance measures at coal units based on 

parameters built into NEMS on mercury emission rates for different types of coal and different 

1 S02 emissions from power plants in Western states are regulated under the Acid Rain Program (EPA 20IOa). We 

did not modifY the S02 caps for Western power plants in NEMS for our reference case or policy case. 

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Appendix A: Compliance Measures and Cost Estimates 

configurations of environmental control technologies, including scrubbers and SCR (EIA 2011b, 

p.105-106). 

Note that when NEMS determines based on its compliance calculations that coal units will install 

scrubbers, the scrubbers are assumed to be wet scrubbers (EIA 2011a, p. 46). Thus, reductions in 

mercury emissions from scrubbers that NEMS builds to comply with state mercury requirements 

reflect parameters for wet scrubbers. When NEMS calculates mercury emissions from coal units 

with existing or planned dry scrubbers, however, the mercury emissions accurately reflect 

parameters for dry scrubbers. Modeling issues related to wet and dry scrubbers are discussed 

further in the context ofMACT HCI compliance below. 

B. Cross-State Air Pollution Rule 

EPA promulgated CSAPR as a replacement for CAIR in August 2011 (EPA 201Ia). As noted 

above, CSAPR would cover a somewhat different set of Eastern states (27 in total) than CAIR 

but would also involve interstate cap-and-trade programs and would set the caps at similar levels 

to CAIR. CSAPR would set caps on emissions in each state but would allow interstate trade of 

emission allowances provided that state emissions stay within so-called variability limits. 

Covered units would not be able to use allowances from the Acid Rain Program, NOx Budget 

Trading Program, or CAIR for compliance with CSAPR. The caps for both S02 and NO, would 

become tighter over two phases. The S02 program would consist of Phase I (2012-2013) with a 

cap of 3.4 million tons and Phase 2 (2014 onward) with a cap of 2.1 million tons. The annual 

NO, program would consist of Phase I (2012-2013) with a cap of 1.2 million tons and Phase 2 

(2014 onward) with a cap of 1.1 million tons. 

Table A-2 summarizes our compliance assumptions for CSAPR. 

Table A-2. Compliance Assumptions for CSAPR 

Policy Emission Compliance Assumptions 

CSAPR S02 Apply S02 caps (3.4 million tons in 2012-2013 and 2.1 million tons 

from 2014 onward) and allow NEMS to determine which units would 

need to install S02 control technologies or switch to lower-sulfur coal 

in the interstate cap-and-trade program (within state variability limits); 

in order to discourage unrealistic fuel switching in the model in 2012-

2013, do not allow banking of CSAPR S02 allowances in those years 

NO, Apply NO, caps (1.2 million tons in 2012-2013 and 1.1 million tons 

from 2014 onward) and allow NEMS to determine which units would 

need to install NO, control technologies in the interstate cap-and-trade 

program (within state variability limits); allow banking ofCSAPR NOx 

allowances 

Source: NERA assumptions as explained in text 

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Appendix A: Compliance Measures and Cost Estimates 

1. CSAPR 502 Compliance 

We modeled the CSAPR S02 program in NEMS as an interstate cap-and-trade program with 

state variability limits and two phases. We allowed NEMS to determine which units would 

install S02 control technologies and which would switch to lower-sulfur coal. 

CSAPR modeling by EPA indicates substantial switching among various coals in 2012 and 2013 

based on their sulfur content (EPA 201lb and NERA analysis of underlying data). Although 

EPA's modeling results seem reasonable for the total amounts oflow-sulfur and ultra-low-sulfur 

coal, it may not be feasible to achieve the extent of fuel switching implied in EPA's modeling 

due to the prevalence oflong-term fuel contracts, rail networks, and other real-world 

practicalities for coal units to switch their coal types on such a large scale in the early years of 

the program. Coal units appear to switch fuels in the early years in EPA's analysis to build up a 

large bank ofCSAPR S02 allowances. To avoid what seems to be potentially unrealistic fuel 

switching in our modeling, we include fuel switching to meet the 2012 and 2013 caps but not to 

build up a bank ofCSAPR S02 allowances in the early years ofthe program. 

2. CSAPR NO. Compliance 

We modeled the CSAPR NOx program in NEMS as an interstate cap-and-trade program with 

state variability limits and two phases. We allowed NEMS to determine which units would 

install various NOx control technologies. Since fuel switching is not an issue for NOx programs, 

we allowed banking ofCSAPR NO, allowances in all years. 

C. Utility MACT 

EPA proposed the Utility Maximum Achievable Control Technology (MACT) rule in May 2011 

to reduce emissions of mercury and other hazardous air pollutants (including mercury, other 

hazardous metals, and acid gases) from coal- and oil-fired power plants across the country. The 

rule would set emission rate standards for different types of coal and oil based on maximum 

achievable control technology. The emission rate standards would apply to mercury, particulate 

matter (PM) as a proxy for all non-mercury hazardous metals, and hydrogen chloride (HC!) as a 

proxy for all acid gases. Covered power plants would have up to three years to comply with the 

rule, but permitting authorities could grant one-year extensions to power plants if they required 

additional time. Table A-3 shows the proposed emission rate standards for mercury, particulate 

matter, and hydrogen chloride from existing coal units under the Utility MACT rule. 

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Appendix A: Compliance Measures and Cost Estimates 

Table A-3. Proposed Utility MACT Emission Rate Standards for Existing Coal Units 

Coal Rank Mercury 

Bituminous and subbituminous 1.21bffBtu 

Lignite 4.0lb/TBtu 

Notes: TBtu: trillion British thermal units of fuel input 

MMBtu: million British thennal units of fuel input 

Hydrogen 

Chloride 

0.0020 IblMMBtu 

0.0020 IblMMBtu 

Particulate 

Matter 

0.030 IblMMBtu 

0.030 IblMMBtu 

The mercury standard for lignite shown in the table is the "beyond-the· floor" limit; the MACT standard 

based on the top 12 percent of units would be 11.0 IbITBtu. 

The mercury standard for bituminous and subbituminous coal is the update from the original value of 

1.0 IblTBtu based on EPA's letter of May 18, 2011 (EPA 201 Ie). 

Source: EPA (2011 d), p. 25027 

Table A-4 summarizes our assumptions for MACT. 

Table A-4. Compliance Assumptions for MACT 

Policy Emission Compliance Assumptions 

MACT Mercury Apply mercury standards in 2015 at all units and allow NEMS to 

determine which units would need to install ACI, fabric filters, and/or 

scrubbers 

HCI Assign costs for DSI in 2015 at unscrubbed units smaller than 300 MW 

that consume subbituminous coal (these units requiring DSI will also 

require fabric filters); require dry scrubbers at all non-DSI units that 

consume Western bituminous coal, subbituminous coal, or lignite (these 

units requiring dry scrubbers will also require fabric filters); require wet 

scrubbers at all units that consume Eastern bituminous coal (these units 

requiring wet scrubbers will not require fabric filters, but NEMS may 

retrofit them with fabric filters for mercury or they may require fabric 

filters for MACT PM compliance) 

PM In addition to requiring fabric filters at all units with DSI or dry 

scrubbers, and in addition to requiring fubric filters (in combination 

with ACI) at some units for MACT mercury compliance, require fabric 

filters for MACT PM compliance at the necessary number of coal units 

so that the same percentage of total U.S. coal capacity has fabric filters 

in 2015 as in the EPA MACT RIA; use EPA's list of coal units 

installing fabric filters from the MACT RIA to identify the additional 

coal units that would require fabric filters 

Source: NERA assumptions as explained in text 

1. MACT Mercury Compliance 

As noted above in the context of state mercury policies for the reference case, NEMS estimates 

mercury emissions from coal units and can determine which units would install ACI, fabric 

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Appendix A: Compliance Measures and Cost Estimates 

filters, and/or scrubbers to comply with mercury reduction requirements. We required mercury 

reductions at all u.s. coal units based on the mercury standards in Table A-3. We assumed that 

compliance with the mercury standards would be required by 20 IS. Note that our inclusion of 

state mercury policies in the reference case dampens the impacts of the national MACT mercury 

standards in the policy case, because some coal units install ACl, fabric filters, and/or scrubbers 

anyway in the reference case to comply with the state mercury policies. 

2. MACT HCI Compliance 

NEMS does not model HCl emissions from coal units. Indeed, HCl emission rates from 

individual units can vary significantly over time as the unit burns coal from different mines and 

seams with different chlorine contents. Since NEMS does not model HCl emissions from coal 

units and thus cannot determine which controls would be required for compliance with HCl 

policies, we developed rules to assign HCl control technologies to individual units based on 

review of techno logy assumptions in EPA's regulatory impact analysis (RIA) for the MACT 

proposal (EPA 20 II f) and other analyses, including comments on the MACT proposal submitted 

to EPA from various organizations (in Oocket No. EPA-HQ-OAR-2009-0234). We assumed that 

compliance with the HCl standard would be required by 2015. 

We assumed that every coal unit would require either dry sorbent injection (OSI), a dry scrubber, 

or a wet scrubber to comply with the HCl standard. Note that the variability in HCl emission rate 

at individual coal units over time would tend to cause owners to make relatively conservative 

assumptions about compliance measures so that they do not exceed the standard when the 

chlorine content oftheir coal happens to be high. OSI has significantly lower capital costs than a 

dry scrubber, which in turn has lower capital costs than a wet scrubber (EPA 201Ic)? Since 

NEMS does not include OSI among its set of emission control technologies, we could not 

directly apply OSI to coal units in NEMS. Instead, we assigned costs to units requiring OSI to 

represent installation of OS I. 

We assumed that OSI would be installed for HCl compliance at unscrubbed units smaller than 

300 MW that consume subbituminous coaL The size limit for OSI is the same as the Bipartisan 

Policy Center's assumption for its analysis of potential EPA regulations (BPC 2011, p. 24); the 

Edison Electric Institute made a similar assumption for one of its modeling scenarios by limiting 

OSI to units smaller than 200 MW (EEl 2011, p. 4). We assumed that dry scrubbers would be 

installed for HCl compliance at all unscrubbed and non-OSI units that consume Western 

bituminous coal, subbituminous coal, or lignite. We further assumed wet scrubbers would be 

installed for HCl compliance at all unscrubbed units that consume Eastern bituminous coaL OSI 

and dry scrubber installations would also require fabric filters. 

As noted above, NEMS assumes that all new scrubbers are wet scrubbers (EIA 20 II a, p. 46). 

Scrubber cost inputs for the Retirement Model however, accurately reflect whether the unit 

would need to install a wet scrubber or dry scrubber (or OSI). Moreover, we modified the unitspecific cost inputs in NEMS so that units needing to install wet scrubbers, dry scrubbers, or OSI 

had the appropriate costs. 

2 Additional information on the costs of air emission control technologies appears at the end of this appendix. 

NERA Economic Consulting A-6 
150 

Appendix A: Compliance Measures and Cost Estimates 

3. MACT PM Compliance 

NEMS does not model PM emissions from coal units and thus cannot detennine which controls 

would be required for compliance with PM policies. The main control technologies for PM 

emissions are electrostatic precipitators (ESPs) and fabric filters (also called baghouses). NEMS 

includes fabric filters among its set of emission control technologies, but since NEMS does not 

model PM emissions, it only installs fabric filters on its own to reduce mercury emissions. We 

therefore developed rules to assign fabric filters to individual units based on reviews of 

technology assumptions in EPA's MACT RIA (EPA 2011f) and other analyses. We assumed that 

compliance with the PM standard would be required by 2015. 

We assumed that most, but not all, coal units would require a fabric filter for PM compliance. 

Since NEMS installs fabric filters (in combination with ACI) on some coal units for compliance 

with state mercury policies and MACT mercury standards, these units would comply with the 

PM standard as well. We also required installation offabric filters at units installing DSI or dry 

scrubbers for HCI compliance, and so these units too would comply with the PM standard. Thus, 

the only remaining coal units without fabric filters at this point are units with wet scrubbers 

(either existing wet scrubbers or new wet scrubbers for HCI compliance) and with sufficiently 

low mercury emission rates without fabric filters based on the NEMS parameters and 

detenninations for mercury compliance. We reviewed EPA's MACT RIA data and assumed 

installation of fabric filters at the remaining coal units if they had fabric filters in the EPA data. 

The percentage oftotal U.S. coal capacity having fabric filters in our policy case is therefore 

approximately the same as the percentage in EPA's MACT RIA.3 

Note that installing fabric filters at most U.S. coal units by 2015 is assumed to be feasible, 

despite the analysis by industry experts that such a large number of fabric filters could not be 

manufactured and installed in such a short period (UARG 2011). 

D. Coal Combustion Residuals 

EPA has considered several alternative forms of regulations in recent years for the disposal of 

coal combustion residuals (CCR), which include fly ash, bottom ash, boiler slag, and scrubber 

waste. The alternative forms of CCR regulations differ in their classification of CCR under 

Subtitles C or D of the Resource Conservation and Recovery Act (hazardous and non-hazardous, 

respectively) and compliance measures (for example, requiring liners at all surface 

impoundments or only at new surface impoundments). EPA proposed three alternative forms of 

CCR regulations in June 2010 (EPA 20IOb). The unit-specific information in the RIA for this 

proposed rule, however, was based on a prior set of alternative forms that EPA developed in 

2009 (EPA 2010c, p. 3). 

Table A-5 summarizes our compliance assumptions for CCR regulations. 

3 EPA (20llf, pp. 8-18 and 8-14) gives the total U.S. coal capacity in 2015 in the MACT scenario as 

299 OW, and 243 OW have fabric filters. Thus, 81 percent of total U.S. coal capacity in 2015 would have 

fabric filters in EPA's MACT scenario. 

NERA Economic Consulting A-7 
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Appendix A: Compliance Measures and Cost Estimates 

Table A-S. Compliance Assumptions for CCR Regulations 

Policy 

CCR 

Compliance Assumptions 

Assign costs to units in 2015 based on EPA Subtitle 0 in initial 

proposal 

Source: NERA assumptions as explained in text 

We modeled CCR compliance costs at coal units in 2015 based on EPA's unit-specific 

information for the initial form of CCR regulation under Subtitle 0 of the Resource Conservation 

and Recovery Act (EPA 201Oc, Exhibit 13). As noted above, EPA only provided unit-specific 

information for the initial set of alternatives it developed in 2009; EPA did not provide unitspecific information for the final set of alternatives that it proposed in 2010. The initial form of 

CCR regulation under Subtitle 0 would lead to a cost of$30 billion (present value in 2009 

dollars). 4 Note that this cost lies near the middle ofthe range of cost estimates for CCR 

regulation. For example, EPA (20 lOb, p. 10) gives the cost of the final fonn of Subtitle C 

regulation as $20 billion, and EPRI (2010, p. 4-3) gives the cost of Subtitle C regulation as 

between $55 billion and $77 billion. 

We used this unit-specific cost information from EPA (2010c, Exhibit 13) as the basis for the 

potential costs of CCR regulation. 

E. Section 316(b) 

EPA proposed alternative forms of regulations for coo ling water intake under Section 316(b) of 

the Clean Water Act in April2011 (EPA 201Ig). The regulations would affect the design of 

cooling water intake structures (to reduce impingement of aquatic organisms against intake 

structures) and the flow rates through coo ling water systems (to reduce entrainment of aquatic 

organisms into cooling water systems) at power plants and other large facilities. The alternative 

forms of316(b) regulations differ in their requirements for intake structures and flow rates, 

including possible use of best professional judgment for detennining best technology available 

on a site-specific basis. 

Table A-6 summarizes our compliance assumptions for 316(b) regulations. 

Table A-6. Compliance Assumptions for 316(b) Regulations 

Policy 

316(b) 

Compliance Assumptions 

Assign costs to units in 2015 based on EPA Option 1 for impingement 

and 46 facilities installing cooling tower retrofits for entrainment 

Source: NERA assumptions as explained in text 

4 EPA (20IOb, Exhibit J3) gives the total annualized cost ofthe initial form ofthe Subtitle D alternative as 

$2.2 billion in 2009 dollars. EPA annualized these costs over 50 years. Using a real annual discount rate of 

7 percen~ this implies a present value 0[$30 billion. 

NERA Economic Consulting A-8 
152 

Appendix A: Compliance Measures and Cost Estimates 

We modeled 316(b) compliance costs for coal units in 2015 based on EPA information in the 

proposed rule related to Option 1, which includes a national requirement to reduce impingement, 

and an assumption that a total of 46 facilities would install cooling towers for entrainment under 

site-specific determinations. EPA (2011g, p. 22219) shows that Option I would lead to costs of 

$5 billion (present value in 2009 dollars) for electric generators to reduce impingement.5 We 

estimated the apportionment of these costs across generation units, including coal units as well as 

natural gas, oil, and nuclear units, based on unit-specific cooling water intake data from ErA 

Form 860 (ErA 2011c). 

EPA (2011g, p. 22211) noted that ifthe 46 fossil units with the largest cooling water withdrawals 

from tidal waters installed cooling towers to reduce entrainment, their total cost would be 

$7 billion.6 Note that of the two hypothetical cooling tower scenarios for which EPA provided 

information, this scenario involved fewer facilities and lower total costs. We identified the 46 

fossil units with the largest cooling water intake withdrawals from tidal waters using EIA Form 

860 (EIA 20 lIc) and apportioned costs to individual units based on their intake data. 

We used this unit-specific cost information based on EPA (20IIg) as the basis for our modeling 

of the potential costs of3l6(b) regulation. 

F. Cost Assumptions for Air Emission Control Technologies 

As discussed above, we relied on unit-specific inputs in NEMS for information about coal units 

for modeling retirements and energy market impacts. We modified the potential costs of air 

emission control technologies in NEMS to base them on EPA (201Ic). 

Table A-7 shows EPA and ElA assumptions for the costs of air emissions controls. These cost 

estimates include energy penalties for net capacity and heat rate due to some ofthe controls. 

Some types of costs show economies of scale (i.e., unit costs per kW are smaller for large units 

than small units), but other types of costs are uniform for all sizes of units. We used these cost 

assumptions from EPA in our modeling. 

Note that the sudden large increase in demand for control technologies and skilled construction 

workers implied by our techno logy assumptions may not be feasible within the limited time 

assumed in our study and, in any event, the increased demand could drive up prices for control 

technologies. We did not develop any estimates of this "gold rush" effect. We assumed that the 

retrofits would be feasible on such a large scale and that there would be no price inflation due to 

the sudden increase in demand. 

5 EPA (201Ig, p. 22219) gives the total annualized cost of Option I for electric generators as $386 million in 

2009 dollars. EPA annualized these costs over 50 years. Using a real annual discount rate of7 percent, this 

implies a present value of $5 billion. 

6 EPA (201Ig, p. 22211) gives the total annualized cost of the 46 mcilities installing cooling towers as 

$480 million in 2009 dollars. EPA annualized these costs over 50 years. Using a real annual discount rate of 

7 percent, this implies a present value of$7 billion. 

NERA Economic Consulting A-9 
153 

Appendix A: Compliance Measures and Cost Estimates 

Table A-7. Air Emission Contl"Ol Costs 

300MW 

EtA EPA 

Wet Scrubber 

Capital (2010$lkW) $850 $762 $622 

Fixed O&M (201 O$lkW-year) $2440 $24.99 $11.20 

Variable O&M (201 O$IMWh) $2.11 $044 $2.11 

Capacity Penalty -1.84% -5.00% -1.84% 

Heat Rate Penalty 1.87% 5.26% 1.87% 

Dry Scrubber 

Capital (2010$lkW) $727 $532 

Fixed O&M (201 O$lkW-year) $17.71 $8.86 

Variable O&M (2010$IMWh) $2.70 $2.70 

Capacity Penalty -145% -145% 

Heat Rate Penalty 147% 147% 

SCR 

Capital (2010$lkW) $268 $225 $217 

Fixed O&M (201 O$lkW-year) $2.60 $2.25 $0.83 

Variable O&M (2010$IMWh) $1.38 $0.34 $1.38 

Capacity Penalty -0.58% 0.00% -0.58% 

Heat Rate Penalty 0.59% 0.00% 0.59% 

ACI 

Capital (20 1 O$lkW) $30 $6 $12 

Fixed O&M (2010$lkW-year) $0.12 $1.71 $0.05 

Variable O&M (2010$IMWh) $0.52 $0.26 $0.56 

Capacity Penalty -0.06% 0.00% -0.06% 

Heat Rate Penalty 0.06% 0.00% 0.06% 

Fabric Filter 

Capital (2010$lkW) $230 $78 $187 

Fixed O&M (2010$lkW-year) $0.94 $5.97 $0.83 

Variable O&M (2010$IMWh) $0.16 $0.00 $0.16 

Capacity Penalty -0.60% 0.00% -0.60% 

Heat Rate Penalty 0.60% 0.00% 0.60% 

DSI 

Capital (2010$lkW) $134 $61 

Fixed O&M (2010$lkW-year) $2.39 $0.94 

Variable O&M (2010$IMWh) $7.70 $7.70 

Capacity Penalty -0.79% -0.79% 

Heat Rate Penalty 0.79% 0.79% 

Note: H_" denotes that NEMS does not model the control technology. 

Source: EPA (201 Ie) andNEMS inputs 

G. References 

EtA 

$580 

$24.99 

$044 

-5.00% 

5.26% 

$184 

$1.88 

$0.34 

0.00% 

0.00% 

$6 

$1.71 

$0.26 

0.00% 

0.00% 

$78 

$5.97 

$0.00 

0.00% 

0.00% 

$538 

$8.35 

$2.11 

-1.84% 

1.87% 

$460 

$6.76 

$2.70 

-145% 

147% 

$201 

$0.73 

$138 

-0.58% 

0.59% 

$8 

$0.03 

$0.60 

-0.06% 

0.06% 

$170 

$0.73 

$0.16 

-0.60% 

0.60% 

$43 

$0.61 

$7.70 

-0.79% 

0.79% 

$485 

$24.99 

$044 

-5.00% 

5.26% 

$165 

$1.66 

$0.34 

0.00% 

0.00% 

$6 

$1.71 

$0.26 

0.00% 

0.00% 

$78 

$5.97 

$0.00 

0.00% 

0.00% 

Bipartisan Policy Center. 2011. Environmental Regulation and Electric System Reliability. 

Washington, D.C.: BPC, June. (www.biparlisanpolicy.org/sites/default/files/-

BPC%20Electric%20System%20Reliability.pdf, accessed September 20, 20 II) 

Edison Electric Institute. 2011. Potential Impacts of Environmental Regulation on the U.S. 

Generation Fleet. Prepared by ICF International. Washington, D.C.: EEl, January 

(www.pacificorp.com/content/damipacificorp/doc/Energy Sources/lntegrated Resource 

NERA Economic Consutting A-10 
154 

Appendix A: Compliance Measures and Cost Estimates 

Planl2011IRPIEEIModelingReportFinal-28January201I.pdf, accessed September 20, 

2011) 

Electric Power Research Institute. 20 I O. Cost Analysis of Proposed National Regulation of Coal 

Combustion Residuals from the Electric Generating Industry. Palo Alto, CA: EPRI, 

November. 

U. S. Court of Appeals for the D.C. Circuit. 2008. North Carolina v. EPA. 550 F.3d 1176, I) 78. 

Case 05-1244. Washington, D.C.: U.S. Court of Appeals for the D.C. Circuit, December 

23. (www.epa.gov/airmarkets/progsregs/cair/docs/CAIRRemandOrder.pdf, accessed 

September 20, 2011) 

U.S. Energy Information Administration. 2011a. Annual Energy Outlook 2011. Washington, 

D.C.: EIA, April. (www.eia.gov/forecasts/aeo/pdf/0383(2011).pdf, accessed September 

20,2011) 

U.S. Energy Information Administration. 2011b. Assumptions to the Annual Energy Outlook 

2011. Washington, D.C.: EIA, July. (www.eia.gov/forecasts/aeo/assumptionslpdfl0554(2011).pdf, accessed September 20, 2011) 

U.S. Energy Information Administration. 2011c. "Fonn 860 Data Files." 

www.eia.gov/cneaflelectricity/page/eia860.html, accessed September 20, 20 II 

U.S. Environmental Protection Agency. 2005. "Rule To Reduce Interstate Transport of Fine 

Particulate Matter and Ozone (Clean Air Interstate Rule); Revisions to Acid Rain 

Program; Revisions to the NOx SIP Call; Final Rule." 70 Federal Register 25162-25405. 

Washington, D.C.: EPA, May 12. (edocket.access.gpo.gov/2005/pdfl05-5723.pdf, 

accessed September 20, 20 II) 

U.S. Environmental Protection Agency. 2010a. Acid Rain and Related Programs: 2009 

Highlights. Washington, D.C.: EPA, December. 

(www.epa.gov/airmarkets/progress/ARP09 downloadsl ARP 2009 Highlights.pdf, 

accessed September 20, 20 II) 

U.S. Environmental Protection Agency. 201Ob. "Hazardous and Solid Waste Management 

System; Identification and Listing of Special Wastes; Disposal of Coal Combustion 

Residuals From Electric Utilities; Proposed Rule." 75 Federal Register 35128-35264. 

Washington, D.C.: EPA, June 21. (http://www.regulations.gov/#!documentDetail;-

D=EPA-HO-RCRA-2009-0640-0352, accessed September 20, 2011) 

U. S. Environmental Protection Agency. 20 I Oc. Regulatory Impact Analysis for EPA's Proposed 

RCRA Regulation of Coal Combustion Residues Generated by the Electric Utility 

Industry: Appendix. Washington, D.C.: EPA, April 30. (www.regulations.gov/-

#!documentDetail;D=EPA-HO-RCRA-2009-0640-0003, accessed September 20, 2011) 

NERA Economic Consulting A-11 
155 

Appendix A: Compliance Measures and Cost Estimates 

U.S. Environmental Protection Agency. 2011a. "Federal Implementation Plans: Interstate 

Transport of Fine Particulate Matter and Ozone and Correction of SIP Approvals." 76 

Federal Register 48208-48483. Washington, D.C.: EPA, August 8. 

(www.gpo.gov/fdsys/pkg/FR-2011-08-08/pdfI20 11-17600.pdf, accessed September 20, 

2011) 

U.S. Environmental Protection Agency. 2011 b. Regulatory Impact Analysisfor the Federal 

Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and 

Ozone in 27 States; Correction of SIP Approvalsfor 22 States. Washington, D.C.: EPA, 

June. (www.epa.gov/airtransport/pdfs/FinaIRIA.pdf, accessed September 20, 2011) 

U.S. Environmental Protection Agency. 2011c. Documentation Supplementfor EPA Base Case 

v4.IO_PTox Updatesfor Proposed Toxics Rule. Washington, D.C.: EPA, March. 

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2011) 

U.S. Environmental Protection Agency. 2011d. ''National Emission Standards for Hazardous Air 

Pollutants From Coal- and Oil-Fired Electric Utility Steam Generating Units and 

Standards of Performance for Fossil-Fuel-Fired Electric Utility, Industrial-CommercialInstitutional, and Small Industrial-Commercial-Institutional Steam Generating Units; 

Proposed Rule." 76 Federal Register 24976. Washington, D.C.: EPA, May 3. 

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September 20, 2011) 

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2011) 

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Control Technology to the Electric Generating Unit Inventory As Projected by EPA. 

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D=EPA-HO-OAR-2009-0234-17785, accessed September 20, 20 II) 

NERA Economic Consulting A-12 
156 

Appendix 8: Coal Unit Retirement Model 

NERA has developed a retirement IJ10del to estimate the possible coal unit retirements due to the 

potential costs of EPA regulations. The model uses Monte Carlo uncertainty analysis to simulate 

the decision facing coal unit owners on whether to incur the costs to comply with additional 

future environmental requirements (and other future costs) or to retire the unit. 

The sections below are organized as follows: Section A describes the main decision module, and 

Section B describes the sub-modules that generate the specific estimates used to run the Monte 

Carlo simulations in the main decision module. 

A. Retirement Decision Module 

The owner of each coal unit is presumed to base its decision on whether or not to retire the unit 

by comparing the future costs for the unit-taking into account potential additional 

environmental compliance costs as well as other costs-to the future costs of the likely 

alternative generation. The retirement decision module calculates the expected net present value 

(NPV) of costs for existing coal units as well as the NPV of costs for the likely alternative. Based 

upon likely future fuel market conditions, the alternative unit for comparison is assumed to be a 

combined cycle gas turbine (CCGT) unit. The cost calculations for coal and gas are done 

separately, but correlations in variables subject to uncertainty are taken into account. All retrofit 

costs are assumed to be incurred in 20 I S. 

1. Net Present Value of Costs for Existing Coal Units 

The NPV of costs for existing coal unit i is given by the following expression: 

Equation 1. NPV of existing coal costs 

r 

d;,R; + Idu(Cu + 0u + Eu) I=l 

Where: 

R; is the capital cost of retrofits. The total cost of retrofits for a given plant depends on the 

plant's current configuration, the randomly drawn retrofit costs for that plant from the 

retrofiticonstruction cost module, and what regulatory requirements the plant has in the 

regulatory scenario of interest. The cost of retrofits is then just the sum of the costs for each 

individual retrofit technology required at the plant. 

d;r is the discount rate for unit i in year r, where r is the year in which retrofits take place. It is 

given by: 

(

_I )1-1 

I+r 

NERA Economic Consulting 8-1 
157 

Appendix B: Coal Unit Retirement Model 

where t indicates time in years, where the first year in the model is 1=1. The discount rate for 

a given unit depends on whether the utility that owns the unit is private or public. Following 

the NEMS model, we take the mean of the (real) discount rate to be 7 percent for units 

owned by public power organizations (e.g., the Tennessee Valley Authority and rural electric 

cooperatives) and 11.8 percent for units owned by private (investor-owned) companies, 

including units owned by regulated utilities with private (investor-owned) parent companies. 

di' is the discount rate for unit i in year t, defined as above for drTI is the remaining lifetime of unit i in years. 

C, is the cost of coal for unit i in year t. The cost of coal is calculated by the hourly operation 

module when run decisions are calculated. It is essentially the average cost of coal across all 

operating hours weighted by the capacity factor at each hour. These plant-specific costs are 

developed as described in the coal cost module section. For the small number of plants with 

missing coal costs, average regional costs are used. If a retrofit increases the plant heat rate it 

will increase coal costs. 

Oil is the operating and maintenance (O&M) cost for unit i in year t. This is calculated as the 

sum of variable O&M and fixed O&M. Some retrofits result in additional O&M costs; where 

this is the case, variable O&M and/or fixed O&M are increased accordingly. We use EPA's 

O&M cost assumptions from the MACT analysis. Variable O&M costs for a year are 

calculated as the sum of hourly variable O&M costs. Ifwe take V;h to be the variable O&M 

costs for unit i in hour h (in dollars per megawatt-hour), then V;" the variable O&M costs for 

unit i in year t, are given by: 8760 

2,TC,(L'h ' V;h) h=1 

where TCI is the total capacity for plant i and LiI, is the capacity factor for plant i in hour h. 

• Eil is the cost of system energy for unit i in year t necessary to compensate for capacity 

factors less than one at any hour. In order to make an appropriate comparison between 

existing coal and new gas, the costs of both gas and coal in our model are calculated as the 

costs to generate TCI times 8760 energy per year. This assures that the retirement decision 

accounts for differences in the capacity factors of new and existing units. Thus, included in 

the calculation of the costs of existing coal is the cost of system energy necessary to 

compensate for capacity factors less than one at any hour. Eil is calculated as: 

PMu ·PEu ·Gu 

Here, Gil is the generation by unit i in year t, PMiI is the ratio of the weighted average system 

energy cost to the overall average electricity price across all simulation draws at the power 

hub to which plant i is assigned (WASCy/ASECiI), and PEiI is the average marginal cost of 

energy in the NERC region to which i belongs in year t (from the NEMS model outputs). The 

value of Gil is an output of the hourly operation module and is calculated as: 8760 

Gu = 2, TC;(L;h) h",,1 

The weighted average system energy cost is calculated as: 

NERA Economic Consulting B-2 
158 

8760 1: (I L,,1t )P,,1t 

WASCij, = -"/t,,,"1~87C760---

1: Lij/t 

11=1 

Appendix B: Coal Unit Retirement Model 

whereas the overall average system energy cost is: 

I I 100 8760 

ASEC =_._." ~P " 8760 100 L... L... ijlt J=l h=l 

where Ph is the marginal cost of energy at hour h from the electricity price module. Thus, the 

factor of PM,,' PElf in the calculation of Ell serves to calibrate the outputs of the electricity 

price and hourly operation modules to NEMS electricity prices and map the five power hubs 

to the twenty-two NERC regions. 

2. Net Present Value of Costs for Potential Alternative Unit (New CCGT) 

The NPV of costs for replacing existing coal unit i with new CCGT of equal capacity is 

calculated as: 

Equation 2. NPV of replacement CCGT costs 

T, 

1:d"(CG,, + OG" + EG" + ONit ) 

1",,1 

Where dit and TI are identical to that for existing coal, and: 

CGit is the average delivered cost of gas for the region in which unit i is located in year t 

using the appropriate capacity factor and heat rate. 

OGit is the total O&M costs in year t for a CCGT constructed to replace unit i. This 

incorporates both fixed and variable O&M costs. The variable O&M costs are a function of 

the hourly capacity rnctors for a new CCGT in year t. These capacity factors are modeled 

based on the predicted operation of a sample of recently constructed CCGTs in each region 

and are an output ofthe hourly operation module. Thus, there are actually several 

calculations of replacement CCGT costs to compare to each coal plant, one for each CCGT 

in the sample of recently constructed CCGTs in each region. 

EGit is the cost of grid energy to bring total generation to TC; times 8760. This is calculated 

in the same way as the cost of grid energy for coal plants. 

ONit is the equivalent annual overnight capital cost payment in year t for a CCGT 

replacement for plant i. The overnight costs are always annualized over the entire lifetime of 

the gas plant (30 years, consistent with the NEMS model), and are based on the sampled 

CCGT overnight costs drawn in the retrofit/construction cost module. However, since T; may 

be less than 30 (and the modeling horizon only encompasses 25 years), the entire capital cost 

ofthe plant is not reflected in this calculation. This avoids inappropriately overstating the 

equivalent annual cost of a CCGT plant built to replace an existing coal plant. 

NERA Economic ConsuRing B-3 
159 

Appendix B: Coal Unit Retirement Model 

3. Monte Carlo Retirement Decision Calculation 

The NPV of costs for existing coal and for replacement CCGT are compared in each of the 100 

simulation draws used in the Monte Carlo formulation. The costs for CCGT are based on the 

minimum of costs calculated using the sampled recently constructed CCGTs in each region as 

the basis for hourly operation of a new CCGT. Since a new CCGT would be at least as efficient 

as any existing CCGTs, this calculation is conservative (in the sense that it might overstate the 

future costs of a future CCGT and thus understate the likelihood of retirement). 

The owner is presumed to retire the coal unit based upon a comparison of the NPV of the costs 

ofthe coal unit and the costs ofthe replacement CCGT plant. In particular, the retirement 

decision sub-module calculates the difference in costs for each ofthe 100 equally-likely Monte 

Carlo draws. The coal unit is presumed to retire ifthe expected value of this cost difference is 

positive, i.e., the coal unit is expected to be more expensive than the replacement natural gas unit. 

B. Individual Cost Component Sub-Modules. 

The Retirement Model includes separate sub-modules to model the various elements that 

influence the cost of continuing to operate an existing coal unit and the cost of replacing the 

exiting coal unit with a new combined cycle gas turbine (CCGT) unit. The methodology in each 

sub-module for energy prices results in mean values based upon the NEMS model using AEO 

2011, with the sub-modules focusing on developing estimates of the potential alternative price 

paths. These sub-modules are summarized and described below. 

\. Natural gas price simulation sub-module. This sub-module simulates possible future natural 

gas price paths. The formulation assumes that future natural gas prices can be modeled as an 

autoregressive process. 

2. Coal price sub-module. This sub-module models regional coal prices. The formulation 

assumes that future coal prices can be modeled as a vector autoregression (V AR) process. 

Coal prices in several regions are modeled as dependent time series. 

3. Electricity price sub-module. This sub-module models hourly electricity prices. The 

empirical formulations are based upon data from five major trading hubs across the United 

States. 

4. Hourly power plant operation sub-module. This sub-module models the hourly operation of 

existing coal plants greater than 25 megawatts (MW) capacity. The sub-module also models 

operation of CCGT units in each region on the basis of recently constructed units. 

5. Retrofit and construction costs sub-module. This sub-module models retrofit costs for 

emission control technologies and construction costs for new CCGT units as random 

variables, with the construction parameters assumed to be correlated. (Costs for the same 

type of control at different plants are assumed to be more highly correlated than costs for 

different controls and for controls and new construction costs.) The parameters for the model 

are taken from EPA cost assumptions for the MACT analysis and recent engineering reports. 

NERA Economic Consuhing 8-4 
160 

Appendix B: Coal Unit Retirement Model 

The following sections provide additional information on these sub-modules. 

1. Natural Gas Price Simulation Sub-Module 

The natural gas price module models natural gas prices as an autoregressive process of order one 

(AR-I process). The model for price at time tis: 

Equation 3. Natural gas price model 

log(p,)=a+ylog(pt-l)+e" e, - N(0,O'2) 

The parameters of the model are a constant term (a), an autoregressive term (y), and a random 

error term (e,), which is assumed to be normally distributed with zero mean and unknown 

variance (0'2). The parameters are estimated from daily Henry Hub price data for the years 

2005-2010. The estimated value of the autoregressive term is less than one, and therefore the 

model for gas price is mean-reverting. 

Using the estimated parameter values, we then simulate 100 future daily natural gas price paths 

from 2011-2035 for use in the model. Simulation is relatively simple: starting from the last day's 

price in the historical data, simulate the first day of the forecast series by taking the log of the 

previous day's price, multiplying by the estimated value of y, adding the estimated value of a, 

and adding a value drawn from N(0,O'2). This is repeated for the second day of the forecast 

using the simulated value from the first day, and so on until prices have been simulated through 

the end of 2035. This entire process is then repeated 100 times to give 100 daily price paths 

through 2035. 

As noted above, we adjust the simulated natural gas price paths such that the expected gas price 

in each year matched the EIA forecast. The expression for the price at time t in our model is 

given by: 

Equatiou 4. Expression for price in the natural gas model 

P, = exp(a+ £,)P;_I 

From this we have that the expression for the expected price at time t, given the price in the 

previous period, is: 

Equatiou 5. Expression for expected value of price in period I given price in period /-1. 

E(p,lp,_I)=exp(a+O'/z)P::'1 

From this expression it is clear that any constant C added to the right hand side ofthe original 

log-log form of the model will result in the conditional expectation ofp, being muhiplied by 

exp(C). Thus, we simulate many price paths and take the mean price in each year (which is a 

consistent estimator of the expectation of price in any year). We then add a constant Cy to the 

right hand side of Equation 3 for every day in year y such that the expected price in year y 

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Appendix B: Coal Unit Retirement Model 

matches the NEMS price in year y. We then simulate 100 price paths from this calibrated form of 

the model. 

2. Coal Price Sub-Module 

The variability in coal prices is modeled using information for the two main coal contracts for 

bituminous and sub-bituminous coal (Central Appalachian/Big Sandy and Powder River Basin 

(PRB), respectively) using a vector autoregression (V AR). (Lignite coal variability is assumed to 

be the same as sub-bituminous.) The model assumes that coal prices are a stochastic process and 

that prices in the two regions are related. The mathematical form of the model is: 

Equation 6. Coal price model 

1't =c+A1't_t +E" E, ~N2(0,L) 

Where Y, is a 2x I vector of prices (the Appalachian and PRB prices at time t), A is a linear 

transformation of the lagged price Y,-J, c is a 2xl vector of constants, and Ot is a bivariate normal 

random variable with a 2xl mean vector of zeroes and covariance matrix L. We use historical 

weekly coal price data from 2005-2010 to estimate the parameters of the model (c, A, and L). 

We then simulate from this model 100 weekly price paths for 2011-2035 for PRB and 

Appalachian coal. As noted, the modeling assures that the mean prices are equal to those 

predicted in NEMS; we calculate the ratio of the average price in each year for each of the two 

coal contracts in our forecast to the average price from 2005-2010. We then add constants to the 

expression in equation 4 to make the ratios ofthe annual average price to the 2005-20 I 0 average 

the same as the ratio of the annual mine mouth prices for bituminous and subbituminous coal in 

NEMS to the average prices for those coals from 2005-20 I O. Thus, the V AR model gives us the 

dependence structure and uncertainty in coal prices, whereas NEMS provides the means. 

We then take a two-year moving average of the simulated coal prices in each of the 100 

simulations and then take the ratio of this moving average to the overall average coal price for 

each year (across all simulations). We use the plant-specific average fuel costs from EIA 423 for 

2005-2010 and multiply them by the ratio of the moving average from each of the 100 

simulations to the overall moving average to get plant-specific coal prices for each week in the 

model. We use a long-term moving average to reflect that most coal prices for electric utilities 

are set by long-term contracts and an analysis of historical market prices compared to historical 

coal costs for electric utilities showed that a two-year moving average was a good predictor of 

relative coal price movements. 

A small number of plants are missing cost data for delivered coal in EIA 423. We impute costs 

for delivered coal based on the quantity and type of coal delivered to each plant using an inversedistance weighted average ofthe costs ofthe same type of coal delivered to nearby plants. We 

verified that the historical average delivered prices for the 22 NERC regions in the NEMS model 

calculated from EIA 423 (and using the above methodology to fill in missing prices) were very 

similar to NEMS average prices for the years 2005-2010 for those regions. The ErA data 

provides monthly coal costs; for consistency with the run decision model, we linearly interpolate 

between the monthly costs to obtain daily coal costs. 

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Appendix B: Coal Unit Retirement Model 

3. Electricity Price Sub-Module 

The variability in hourly electricity prices is modeled using data for five hubs throughout the 

United States (ERCOT, PJM, Cinergy, SPI5, and NYISO). Electricity prices are taken to be a 

function ofthe previous hour's electricity price, natural gas prices (with the magnitude of the 

effect varying with the hour), hour of day, season, whether the day is a weekend day or a 

weekday, and an innovation (error) term. The innovations are normal with zero mean and 

stochastic, time-varying variance. The mathematical specification is an exponential GARCH 

(EGARCH) model and is given by the following set of equations: 

Equation 7. Electricity price model 

log(p,) = X,/3 + a 10g(P'_I) + £, 

£, = a,z, z, ~ N(O,I) 

log(a;) = llJ+y.g(Z'_I)+y, log(a'~l) 

g(Z,) = ez, + A~z,l- E~Z'II)) 

Where P, is the price at time t, and Xis a matrix of co variates. The structure of the model allows 

the sign and magnitude of the standard normal random variable Z,to affect volatility (a2

) 

separately. The model also allows for heteroskedasticity (through the dependence of a,2 on a'~l) 

and volatility clustering (periods oflarge price swings and periods of relative calm). 

The covariates in the mean regression (the matrix X;) include dummy variables for hour of day, 

hour of day dummies interacted with natural gas prices, seasonal dummies, and 

weekday/weekend dummies. The model parameters are estimated on historical electricity price 

data for the five electricity price hubs for 2005-2010. We then simulate electricity price series for 

each of the five hubs from the model, using as inputs the simulated natural gas prices from the 

natural gas price model. We simulate 100 realizations of hourly prices for 2011-2015. 

4. Hourly Power Plant Operation Sub-Module 

The hourly power plant operation module models power plant hourly run decisions and output as 

a function of price and marginal costs. The relevant price variability in the model is determined 

by matching each power plant to one of the five regional hubs. As noted, the mean electricity 

prices are based upon NEMS AEO 2011. 

The decision of whether to operate is modeled as a logistic regression: 

Equation 8. Run decision model 

r, ~ bernoulli(p,) 

eX,p 

p =Pr(r =1)=-- , , l+ex,P 

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Appendix B: Coal Unit Retirement Model 

Where rl = I indicates that the plant decides to run at time t. Here X, is a vector of covariates, 

which in this case are constant, the hourly electricity price, and negative one times the sum of 

fuel costs and allowance costs per MWh for the plant at each hour. In the case of CCGT plants, 

the implied heat rate (ratio of the electricity price to the gas price) is used in place of the 

electricity price less costs. 

Conditional on operating, we then model the capacity factor (output divided by capacity) as a 

mixture of linear regression models. In this model, each unit can operate in up to five distinct 

"modes," and the choice of "mode" is a function ofthe electricity price less costs (or, in the case 

ofCCGT, the implied heat rate) and a constant specific to each mode. Conditional on choosing a 

"mode," the capacity factor is modeled as normally distributed with mean and variance estimated 

from the data. The mathematical representation of the model is: 

Equation 9. Capacity factor model 

m, I r, = 1- multinomial(l,s,) 

e XdJj 

Sj' =Pr(m, =jlr, =1)=" X" fi, L... e ,p, 

i",-} 

L, 1m, = j,r, = 1- N(f.1,rr2) 

5 

Where mt is the operating mode at time t (mt=I, ... ,5), St is a simplex vector (vector whose 

components add to one, making them plausible as probabilities for different alternatives), X, is a 

matrix of covariates (here covariates are the electricity price less costs for coal plants or implied 

heat rate for CCGT and a dummy for the operating "mode" alternative), Lt is the capacity factor 

at time t and fL and ,i are the mean and variance of a normal distribution. The choice of this form 

for the model was based on the observation that power plant capacity factors exhibit 

multimodality, whereas electricity prices, the main factor in power plant operation decisions, do 

not. Thus, some type of model allowing for flexible multimodality was necessary, and the 

mixture of normal models is one such model that has well-established estimation techniques 

available. 

We estimate the model on historical hourly power plant operation data for coal plants and a 

sample of recently constructed CCOTs for the years 2005-2010. The model predicts the 

historical capacity factors very accurately, with virtually all of the variance in the historical data 

explained by the model. We then simulate power plant operation for coal plants and sampled 

CCGTs using the simulated electricity, coal, and gas prices from the electricity and gas price 

modules for the years 2011-2035, as well as estimates of incremental variable cost of new 

controls, expected allowance prices, and heat rate penalties of new controls as factors affecting 

coal plant marginal costs. The result is 100 sets of hourly plant operation patterns for every plant 

in the dataset. 

5. Retrofit Costs and Construction Costs Sub-Module 

This sub-module develops information on the variability in technology retrofit costs as well as 

CCGT construction costs, which are assumed to be correlated in our model. We model the 

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Appendix B: Coal Unit Retirement Model 

variability in costs for the relevant control technologies (wet and dry scrubbers, dry sorbent 

injection, fabric filters, activated carbon injection, closed cycle cooling, and coal combustion 

residual compliance costs) and for new CCGTs. The correlations include those for different 

technologies and the same plant, for the same technology across plants, and for retrofit costs and 

new construction costs. The vector of all control costs is modeled as multivariate lognormal, 

mathematically represented as: 

Equation 10. Retrofit/control costs model 

r - N(fl,'L) 

c=e" 

Where r is a multivariate normal random variable with mean vector J.1 and covariance matrix'L, 

and c is the controVconstruction cost vector (a vector containing all controVconstruction costs for 

all plants). There exists a closed-form expression for the expected value of c as a function ofJ.1. 

We take the EPA's control costs estimates for different control types and EIA's overnight costs 

for CCGT as the expected value of c, and back solve for the mean vector J.1. No suitable data 

exists to estimate the covariance matrix 'i.. Thus, we create a covariance matrix from a 

correlation matrix with the following assumed structure. We assume that the correlation between 

costs for the same control at different plants is 0.6 and the correlation between costs for different 

controls at different plants is 0.4. We assume that the correlation between costs for all 

environmental controls and the capital cost of a new CCGT is 0.4. Thus, we assume that costs for 

the same type of control will be more highly correlated than costs for different types of controls. 

In order to create a covariance matrix from this correlation matrix, we also must define a 

variance vector for the controVconstruction costs (a vector containing the variances for each 

control type/plant combination and for CCGT retrofit costs). As described previously for the 

mean vector, there is a closed-form expression for the variance vector of the normal distribution 

in terms of the variance vector of the lognormal distribution. Variances are based on the 

uncertainty ranges given in the Raytheon Coal Unit Environmental Cost Model documentation 

(which is used by EIA to estimate plant retrofit costs in the NEMS model). In the Raytheon 

documentation, retrofit costs estimates are given with an uncertainty of ±30%. We assume that 

standard deviations of the lognormal cost distributions are 15% of the cost, or half of the 

uncertainty range given by the Raytheon report. 

The model takes 100 separate draws ofretrofitlconstruction costs from the multivariate 

lognormal distribution defined above. The joint variability in costs for retrofits and for new 

CCGT construction is then used in the retirement decision sub-module, as discussed above. 

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Appendix C: Energy Market Modeling 

This appendix provides details on the National Energy Modeling System (NEMS) as well as our 

data and methodology for using NEMS to model the potential energy market impacts ofthe four 

EPA regulations. This appendix also shows key energy market impact results from NEMS for 

each year between 2012 and 2020. 

A. National Energy Modeling System 

This section provides an overview ofNEMS and its input categories related to emission controls. 

1. Overview 

The U.S. Energy Information Administration (EIA) developed and maintains NEMS to produce 

projections of energy prices and quantities in the long term. EIA also uses NEMS to perform 

policy analyses in response to requests from Congress, the White House, the Department of 

Energy, and other government agencies. EIA prepares an Annual Energy Outlook (AEO) with 

long-term projections of energy prices and quantities based on current policies and various 

assumptions. As discussed in Appendix A, our modeling of the potential energy market impacts 

of the four EPA regulations with NEMS is based on inputs for AEO 2011 (EIA 201Ia); its 

assumptions are summarized in EIA (2011 b). 

Figure C-I shows the thirteen modules in NEMS and their linkages. All modules interact via the 

Integrating Module at the center ofthe figure. The four modules to the left in the figure (Oil and 

Gas Supply, Natural Gas Transmission and Distribution, Coal Market, and Renewable Fuels) 

relate to the supply of primary energy sources. The four modules to the right in the figure 

(Residential Demand, Commercial Demand, Transportation Demand, and Industrial Demand) 

relate to the demand for energy. The two modules to the bottom of the figure (Electricity Market 

and Petroleum Market) convert primary energy sources into electricity and petroleum products. 

Finally, the two modules to the top ofthe figure (Macroeconomic Activity and International 

Energy) provide information from outside U.S. energy systems. 

NEMS uses the thirteen modules shown in Figure C-l to balance energy supply and demand in 

each region ofthe United States. In particular, the model calculates the least-cost way to satisfy 

demand in each region based on the costs of alternative forms of energy and various constraints, 

including resource availability and energy transportation infrastructure. The level of regional 

detail in NEMS varies for different forms of energy. For example, NEMS divides the United 

States into 22 electricity markets, 13 coal production regions, and nine natural gas production 

regions. Regional detail for energy demand is based on the nine Census divisions. 

Additional detail on energy market modeling and NEMS can be found in EIA (2009) and EIA 

(2011 b). 

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Appendix C: Energy Markel Modeling 

Figure C-\. Overview of NEMS 

Integrating 

Module 

Source: EIA (2011 b, p. 4) 

2. Input Categories Related to Emission Controls 

NEMS input files include a database of all generation units in the United States as well as 

paramcters that apply uniformly to all units within certain categories. The database includes 

current and planned scrubber, SCR, and particulate controls for each coal unit in the United 

States. The database also includes information on some types of environmental control costs for 

each coal unit. Other types of environmental control costs enter NEMS as parameters that apply 

uniformly to the relevant coal units. 

Table Col summarizes unit-specific and uniform inputs related to emission controls. Note that 

direct sorbent injection (DS!) is not included as an emission control in NEMS, as discussed in 

Appendix A. 

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Appendix C: Energy Market Modeling 

Table Col. NEMS Inputs Related to Emission Controls 

Miscellaneous Scrubbers SCR ACI FF DSI 

Unit- - Construction date - Current or - Current or - Current or - Current or - Not in 

specific • Retirement date planned planned planned planned NEMS 

inputs • Capacity configuration configuration configuration configuration 

- Capacity factor • Capital cost - Capital cost - Emission - Emission 

(historical) ($IkW) ($/kW) reduction reduction 

• Heat rate - Emission -Additional percentage percentage 

• Baseline fixed O&M cost reduction fixedO&M (based on (based on 

(excluding controls) percentage cost other other controls 

- Baseline variable O&M - Additional controls and and coal type) 

cost (excluding controls) variable coal type) 

- Baseline annual capital O&Mcost 

cost (excluding controls) - Emission 

reduction 

percentage 

Uniform - Capacity - Capital cost - Capital cost -Not in 

inputs for penalty ($IkW) ($IkW) NEMS 

all coal - Heat rate - Additional - Additional 

units penalty fixedO&M fixed O&M 

- Additional cost cost 

fixedO&M - Additional 

cost variable 

- Additional O&Mcost 

variable 

O&Mcost 

Source: NERA review ofNEMS inputs 

3. Input Categories Related to CCR and 316(b) 

NEMS does not model compliance with CCR or 3l6(b) policies. As discussed further below, we 

modeled these policies in NEMS by adding their costs to the unit-specific inputs for general 

capital costs. 

B. Methodology 

This section describes NEMS inputs and outputs for modeling the potential energy market 

impacts of the four EPA regulations. 

1. NEMS Inputs 

We entered three types of modeling inputs into NEMS: (I) potential emission control costs; (2) 

coal unit retirements; and (3) compliance measures. This section describes each of these types of 

inputs. 

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Appendix C: Energy Market Modeling 

a. Emission Control Costs 

As described in Appendix A, we used EPA estimates for potential emission control costs rather 

than the EIA assumptions built into NEMS. As summarized above in Table C-l, NEMS 

incorporates data on the potential costs of environmental controls in case installation of such 

controls is required. We modified these emission control costs in NEMS for both the reference 

case and policy case so that costs would consistently reflect EPA cost estimates in both cases. 

For example, the reference case includes state mercury regulations that would cause some coal 

units to install ACI and fabric filters. The costs of these ACI and fabric filter retrofits in the 

reference case reflect EPA cost assumptions, just as they do in the policy case. 

To achieve the maximum level of unit-level detail on costs and compliance measures, we used 

the unit-specific inputs shown in Table C-J to the maximum extent possible. For emission 

control costs without unit-specific inputs in NEMS, we used uniform inputs for all units. As 

shown above in Table C-J, NEMS has unit-specific inputs for scrubber capital costs and SCR 

capital and O&M costs, so we modified these unit-specific inputs to reflect EPA cost 

assumptions. Since NEMS only has uniform inputs for scrubber O&M costs and ACI and FF 

costs, we modified those uniform inputs to reflect EPA cost assumptions. Since NEMS does not 

model DSI, the variable O&M cost ofFF, or the heat rate and capacity penalties of any 

emissions controls other than scrubbers, we adjusted the relevant unit parameters manually in the 

unit database. Our modifications for emission control costs are shown below in Table C-2. 

Ta ble C-2. Modification of NEMS Emission Control Costs 

Scrubbers SCR AC[ FF DS[ 

Capital Assign by unit Assign by unit Assign uniform Assign uniform Assign by unit 

usingNEMS usingNEMS cost to all un its cost to all units usingNEMS 

scrubber capital SCR capital cost general capital 

cost input input variable cost input 

variable variable 

FixedO&M Assign uniform Assign by unit Assign uniform Assign uniform Assign by unit 

cost to all units usingNEMS cost to all units cost to all units usingNEMS 

SCRfixedO&M general fixed 

cost input O&M cost input 

variable variable 

Variable O&M Assign unifonn Assign by unit Assign uniform Assign by unit Assign by unit 

cost to all units usingNEMS cost to all units usingNEMS usingNEMS 

SCR variable general variable general variable 

O&M cost input O&M cost input O&M cost input 

variable variable variable 

Heat Rate Assign uniform Assign by unit Assign by unit Assign by unit Assign by unit 

Penalty penalty to all usingNEMS usingNEMS usingNEMS usingNEMS 

units heat rate input heat rate input heat rate input heat rate input 

variable variable variable variable 

Capacity Penalty Assign uniform Assign by unit Assign by unit Assign by unit Assign by unit 

penalty to all usingNEMS usingNEMS usingNEMS usingNEMS 

units capacity input capacity input capacity input capacity input 

variable variable variable variable 

Source: NERA 

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Appendix C: Energy Market Modeling 

b. Coal Unit Retirements 

As described in Appendix B, we used the Retirement Model to determine which coal units would 

likely retire rather than incur costs for the four EPA regulations. We also used the Retirement 

Model for the reference case to determine which coal units would likely retire even in the 

absence of the four EPA regulations. We entered these retirements into the NEMS database of 

generation units for the end of2014 (immediately before compliance with MACT, CCR, and 

316(b) is assumed to be required in 2015). We did not allow NEMS to retire coal units based on 

its own economic evaluations in either the reference case or the policy case.' 

c. Compliance Measures 

The compliance measures that we modeled for CSAPR, MACT, CCR, and 316(b) for the policy 

case are described in Appendix A. That appendix also describes our modeling of compliance 

measures for the two most relevant environmental policies in the reference case: CAIR and state 

mercury regulations. Our methodology and assumptions are summarized briefly here. 

We modeled CAIR in the reference case by setting regional emission caps through 2011 in 

NEMS and allowing NEMS to determine which coal units would need to install environmental 

controls or fuel switch to lower their S02 and NOx emissions. We modeled state mercury 

regulations in the reference case by requiring mercury reductions in specific regions in NEMS 

based on the locations of states with mercury regulations and allowed NEMS to determine which 

coal units would need to install ACI, fabric filters, and/or scrubbers to comply. 

For the policy case, we modeled CSAPR by setting regional caps in NEMS and allowing NEMS 

to determine which additional coal units would need to install environmental controls or fuel 

switch to lower their S02 and NOx emissions beyond reductions for CAIR (or for caps without 

CAIR from 2012 onward). We modeled the MACT mercury standards by requiring mercury 

reductions based on the standards shown in Appendix A and allowing NEMS to determine which 

coal units would need to install ACI, fabric filters, and/or scrubbers to comply. We modeled the 

MACT HCl and PM standards by requiring scrubbers, DSI, and/or fabric filters at particular 

units, as discussed in detail in Appendix A. Finally, we modeled the CCR and 316(b) regulations 

in NEMS by applying their unit-specific costs in the NEMS database of generation units using 

the input variable for general capital costs, since NEMS does not model compliance with non-air 

emission regulations such as the CCR and 316(b) regulations. 

I The NEMS model provides less detailed modeling of coal unit retirements than provided for in the retirement 

model we used. With regard to dispatch, NEMS provides for 216 distinct periods (summer, winter, spring and 

fall by peak, off-peak and weekend). As with other retirement models (see, e.g., Brattle Group 2010), our 

retirement model models the full 8,760 hours per year of electricity prices and thus allows for more precise 

dispatch modeling and furecasts of costs for existing and potential new units. Our model also incorporates 

uncertainties in key energy price and cost variables and allows the retirement decision to depend upon these 

uncertainties. 

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Appendix C: Energy Market Modeling 

2. NEMS Outputs 

Based on the coal unit retirements and the costs ofthe compliance measures, NEMS calculated 

the cost-minimizing set of energy prices and quantities. NEMS also endogenously determined 

the new generation capacity necessary in each electricity region to replace the coal units that 

would retire. The electricity price results from NEMS include the costs of compliance measures 

as well as the costs for new generation capacity, among other electricity price components. 

C. Results 

This section shows key energy market impact results from NEMS due to the four EPA 

regulations for each year between 2012 and 2020. 

1. Coal-Fired Generation 

Figure C-2 shows the change in coal-frred generation between 2012 and 2020 due to the four 

EPA regulations relative to reference case projections. Coal-fired generation decreases because 

ofthe coal unit retirements and the additional costs borne by coal units that do not retire (which 

make the units less competitive in electricity markets and thus lower their capacity factors). Note 

that coal units incur costs for their S02 and NO, emissions in the policy case beginning in 2012 

due to the introduction of the trading program for CSAPR, with CAIR assumed not to be in place 

after 201 \. In 2015, when many coal units install scrubbers and DSI for MACT HCI compliance, 

their S02 emissions decrease and allowance prices decrease to zero. As a result, coal units have 

lower costs for S02 emissions from 2015 onward than they had from 2012 to 2014. This tends to 

raise their capacity factors relative to their levels from 2012 to 2014. Coal unit retirements 

contribute to lower coal-fired generation from 2015 onward. 

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Appendix C: Energy Market Modeling 

Figure C-2. Change in Coal-Fired Generation Relative to Reference Case 

:c- 0% 

3: -40 -2% Q) :;; 

r::: -80 -4% '" r::: 

'" ~ .s::: 

-120 -6% u 

I -160 

Q) 

-8% r::: JlI '" 

,g -200 

~::X=a::~* 

r::: -10% Q) 

E 0 ~ 

~ -240 -12% Q) 

a. Q) 

(!) -280 -14% 

2010 2012 2014 2016 2018 2020 

1 __ Coal Generation 'Change -0-Percentage Change] 

Note: Coal-tired generatioo in 2010 was 1800 million MWh (ErA 2011a). 

Source: NERA calculations as explained in text 

2. Electricity Sector Coal Demand 

Figure C-3 shows the change in electricity sector coal demand between 2012 and 2020 due to the 

four EPA regulations relative to reference case projections. Just as for coal-fired generation, 

electricity sector coal demand decreases because ofthe coal unit retirements and the additional 

costs borne by coal units that do not retire (which make the units less competitive in electricity 

markets and thus lower their capacity factors). The percentage change in electricity sector coal 

demand is similar to the percentage change in coal:fIred generation; the small difference between 

the percentage changes reflects shifts in the average heat content of coal consumed by units. 

NERA Economic Consulting C-7 
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Appendix C: Energy Market Modeling 

Figure C-3. Change in Electricity Sector Coal Demand Relative to Reference Case 

0 0% 

en 

c -20 -2% CI> 

.s Cl 

c c 40 4% .2 '" .=. 

0 

i -60 -6% CI> 

Cl 

.l!I ." -80 -8% c c .. '" I:! E -100 -10% .. CI> 0- 0 

-120 -12% 

2010 2012 2014 2016 2018 2020 

1 __ Coal Demand Change ~percentage Ch~~ 

Note: Electricity sector coal demand in 2010 was 1000 million tons (ETA 2011a). 

Source: NERA calculations as explained in text 

3. Coal Price 

Figure C-4 shows the change in average coal minemouth (i.e., wholesale) price between 2012 

and 2020 due to the four EPA regulations relative to reference case projections. The price of coal 

would decrease because of reduced demand for coal by the electricity sector. 

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Appendix C: Energy Market Modeling 

Figure C-4. Change in Average Coal Minemouth Price Relative to Reference Case 

$0.00 

~ -$0.50 c: 

L_-'--~-"----'--t 0.0% 

~ -$1.00 o 

~ -$1.50 

~ -$2.00 

~ -$2.50 

-1.5% ~ 

c: -3.0% ~ 

u 

-4.5% ~ 

J!! 

-6.0% ;; 

~ 

-7.5% /f. 

-$3.00 ____________ ._ . .-L -9.0% 

2010 2012 2014 2016 2018 2020 

Feoa' Price Chang~'~ Percentage Change I Note: Average coal minemouth price in 2010 was $37/toll (2010$) (ETA 2011.). 

Source: NERA calculations as explained in text 

4. Natural Gas-Fired Generation 

Figure C-S shows the change in natural gas-fired generation between 2012 and 2020 due to the 

four EPA regulations relative to reference case projections. When coal units retire and capacity 

factors for the remaining coal units decrease (due to the costs of environmental controls), the 

electricity sector shifts toward natural gas. The increase in natural-gas fired generation reflects 

both new gas units and higher capacity factors for existing gas units. The increase in natural gasfired generation in each year is somewhat smaller than the decrease in coal-fired generation 

shown above in Figure C-2 because other energy sources also substitute for coal and total 

electricity consumption decreases somewhat in response to higher electricity prices (shown 

below in Figure C-8). 

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Appendix C: Energy Market Modeling 

Figure C-S. Change in Natural Gas-Fired Generation Relative to Reference Case 

_ 210 .c 

3: 

:Ii! 

180 

<: 150 

~ 120 I 90 <: 

0 

60 "" f! 

CI> 30 <: 

CI> 

C!) 0 '-'--L2010 2012 

~--~f:~ f 

20% u 

~~t:~~~~~==~= 15% E 

+ 10% ~ 15% ~ 

-'-_'---~'---~_-LI 0% 

2014 2016 2018 2020 

~ Gas Generation Change -0-P~~c~ntage c;hange I 

Note: Natural gas-fired generation in 2010 was 750 million MWh (EIA 20lla). 

Source: NERA calculations as explained in text 

5. Electricity Sector Natural Gas Demand 

Figure C-6 shows the change in electricity sector natural gas demand between 2012 and 2020 

due to the four EPA regulations relative to reference case projections. Just as for natural gas-fired 

generation, the increase in electricity sector natural gas demand reflects both new gas units and 

higher capacity factors for existing gas units. The percentage change in electricity sector natural 

gas demand in each year is similar to the percentage change in natural gas-fired generation. 

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Appendix C: Energy Market Modeling 

Figure C-6. Change in Electricity Sector Natural Gas Demand Relative to Reference Case 

~ 1.8 30% 

'" 

~ 

.2! 1.5 25% '" u 

:E '" !: 

:::I 1.2 20% II u 

!: 0 

~ 0.9 ~ 15% '" '" ;§. 0.6 

B 

10% !: 

1::1 '" ~ !: 0.3 5% '" co 0.. E 

'" 0 0.0 0% 

2010 2012 2014 2016 2018 2020 

1 __ Gas De~and Change ~ Percentage cha~g~l 

Note: Electricity sector natural gas demand in 2010 was 7.2 trillion cubic reet (EIA 201la). 

Source: NERA calculations as explained in text 

6. Natural Gas Price 

Figure C-7 shows the change in natural gas price at Henry Hub between 2012 and 2020 due to 

the four EPA regulations relative to reference case projections. The price of natural gas would 

increase because of the substantial increase in demand for natural gas by the electricity sector 

(taking into account the reduction in natural gas demand in other sectors as prices rise). 

NERA Economic Consulting C-11 
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Appendix C: Energy Market Modeling 

Figure C-7. Change in Natural Gas Price at Henry Hub Relative to Reference Case 

$0.80 16% 

~ $0.60 '" 12% OJ 

<: ::;; .. ::;; .c 

... U 

0 $0.40 8% '" ~ 

0 19 '" !:!. <: 

'" u $0.20 4% ~ ~ '" 0-

$0.00 0% 

2010 2012 2014 2016 2018 2020 

r -- Gas Price Change --0-Percentage change] 

Note: Average natural gas price at Henry Hub in 2010 was $4.50IMMBtu (2010$) (EIA 2011a). 

Source: NERA calculations as explained in text 

7. Electricity Price 

a. u.s. Electricity Price 

Figure C-S shows the change in average U.S. electricity retail price between 2012 and 2020 due 

to the four EPA regulations relative to reference case projections. The increase in electricity 

price reflects environmental control costs at coal units that do not retire, S02 and NOx emission 

costs for CSAPR, construction of new gas units and increased capacity factors for existing gas 

units, and higher natural gas price. 

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Appendix C: Energy Market Modeling 

Figure CoS. Change in Average U.S. Electricity Retail Price Relative to Rererence Case 

$8 

~ $7 

~ $6 

~ $5 

~ $4 

~ 53 

.g '" $2 

0. $1 

$0 

2010 2012 2014 2016 2018 

Price Change _'J-- Percentage Change 

2020 

8% 

'" 6% g 

S'lf; <3 

~ 

1 

1% (f. 

0% 

Note: Average U.S. electricity retail price in 2010 was $97/MWh (2010$) (EIA 201Ia). 

Source: NERA calculations as explained in text 

b. Regional Electricity Price 

Figure C-9 provides a map of the 22 electricity regions modeled in NEMS. 

Figure C-9. NEMS Electricity Regions 

Source: EIA (20 II b. p. 95) 

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Appendix C: Energy Market Modeling 

Table C-3 provides estimates of the electricity retail price impacts in the 22 NEMS electricity 

regions between 2012 and 2020 due to the four EPA regulations. The impacts reflect different 

extents to which natural gas prices, coal prices, emission allowance costs, coal unit retirements, 

and retrofits affect electricity prices in each year in different regions. For example, regions that 

rely much more on natural gas-fIred generation than coal-fired generation (e.g., New England) 

have larger impacts during 2012-2014 than 2015-2020, because the increase in natural gas prices 

tapers off over time (see Figure C-7). On the other hand, regions that rely much more on coalfIred generation than natural gas-fIred generation (e.g., Kentucky and Tennessee) have smaller 

impacts during 2012-2014 than 2015-2020, because coal unit retirements and most retrofits 

occur in 2015. 

Table C-3. Regional Electricity Retail Price Impacts, 2012-2020 (201O$/MWb) 

2012 2013 2014 2015 2016 2017 2018 2019 2020 Ava 

us Average +$3.80 +$5.45 +$5.21 +$6.16 +$6.73 +$6.25 +$6.06 +$5.62 +$5,56 +$5.65 

NEMS Regions 

NEWE New England +$4.01 +$5,81 +$4.96 +$4.69 +$2.99 +$1.61 +$0.99 +$1.30 -$0.24 +$2.93 

NYCW NYC +$6.63 +$10.35 +$8.90 +$8,12 +$6.91 +$5.95 +$5.47 +$5.21 +$5.23 +$6.97 

NYU NY Long Island +$10.77 +$17.39 +$15.45 +$14.09 +$12.48 +$12.22 +$11.65 +$11.40 +$11.53 +$13.00 

NYUP NY Upstate +$6.14 +$9.37 +$8.04 +$6.65 +$5,45 +$5.33 +$5.32 +$5.59 +$5.62 +$6.39 

RFCE Mid-Atlantic +$8.29 +$13.26 +$11.41 +$12.57 +$10.81 +$11.26 +$10.69 +$7.24 +$7.88 1-$10.38 

SRVC VA & Carolinas +$2.63 +$3.71 +$3.71 +$4.13 +$4.91 +$4.72 +$4.41 +$4.13 +$4.06 +$4.05 

SRSE Southeast +$3.19 +$4.29 +$5.15 +$7.17 +$9.63 +$8.97 +$8.51 +$8.02 +$7.53 +$6.94 

FRCe Florida +$3.60 +$4.81 +$4.22 +$4.22 +$4.42 +$4.20 +$3.96 +$3.64 +$3.82 +$4.10 

RFCM LowerMI +$3.70 +$5.41 +$7.10 +$7.31 +$10.00 +$9.51 +$8.83 +$8.46 +$8.35 +$7.63 

RFCW OH,IN,&WV +$5.42 +$8.65 +$8.08 +$7.18 +$7.12 +$6.85 +$6.59 +$6.48 +$6.70 +$7.01 

SRCE KY&TN +$4.68 +$4.38 +$5.30 +$9.11 +$11.36 +$10.88 +$10.25 +$9.93 +$9.37 +$8.36 

MROE WI & UpperMI +$5.63 +$7.78 +$8.12 +$6.57 +$7.37 +$7.14 +$6.79 +$6.54 +$6.66 +$6.96 

MROW Upper Midwest +$1.41 +$1.11 +$1.23 +$4.90 +$8.36 +$8.20 +$7.94 +$7.85 +$7.54 +$5.39 

SRGW South IL & East MO +$3.98 +$5.83 +$6.20 +$6.69 +$8.59 +$6.11 +$7.49 +$6.93 +$6.72 +$6.73 

SPNO KS & WestMO +$5.46 +$2.35 +$3.13 +$4.84 +$8.10 +$7.98 +$8.17 +$6.61 +$9.13 +$6.42 

SRDA AR, LA, & West MS +$2.03 +$3.40 +$4.27 +$5.14 +$6.96 +$6.56 +$6.29 +$5.98 +$5.80 +$5.16 

SPSO Oklahoma +$3.33 +$7.65 +$8.27 +$8.89 +$11.13 +$10.61 +$9.75 +$9.43 +$9.68 +$6.75 

ERCT Texas +$4.85 +$7.01 +$6.14 +$9.15 +$6.27 +$3.51 +$4.34 +$3.60 +$3.16 +$5.34 

RMPA CO & EastWY +$0.60 +$0.40 +$0.70 +$1.54 +$2.16 +$1.99 +$1.86 +$1.72 +$1.65 +$1.40 

NWPP Northwest -$0.14 -$0.30 -$2.27 -$1.22 -$0.07 +$0.38 +$1.20 +$1.40 +$1.36 +$0.04 

AZNM AZ&NM +$0,82 +$0.70 +$1.04 +$1.39 +$1.71 +$1.69 +$1.56 +$1.86 +$1.85 +$1.40 

CAMX California +$1.34 +$2.05 +$2.19 +$2.26 +$2.28 +$2.59 +$2.59 +$2.45 +$2.45 +$2.25 

Source: NERA calculations as explained in text 

Table C-4 shows the percentage changes in electricity retail prices in the 22 NEMS electricity 

regions relative to reference case projections. 

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Appendix C: Energy Market Modeling 

Table C-4. Regional Electricity Retail Price Impacts, 2012-2020 (Percentage Changes) 

2012 2013 2014 2015 2016 2017 2018 2019 2020 

us Average +4.3% +6.2% +6.0% +7.1% +7.7% +7.2% +7.0% +6.5% +6.5% 

NEMS Regions 

NEWE New England +2.9% +4.3% +3.7% +3.7% +2.3% +1.2% +0.7% +1.0% ~O.2% 

NYCW NYC +3.8% +6.1% +5,3% +4.9% +4.2% +3.6% +3.4% +3,2% +3.2% 

NYU NY Long Island +6.3% +10.4% +9.4% +8.7% +7.7% +7.6% +7.3% +7.1% +7.2% 

NYUP NY Upstate +5,0% +7.9% +6.9% +5.8% +4.8% +4.7% +4.8% +5.0% +5.0% 

RFCE Mid-Atlantic +8.4% +13.7% +11.9% +13.1% +11.3% +11.7% +11.0% +7.4% +7.8% 

SRVC VA & Carolinas +3.3% +4.6% +4.7% +5.2% +6.3% +6.1% +5.6% +5.2% +5.0% 

SRSE Southeast +3.8% +5,3% +6.5% +9.1% +11.9% +10.4% +9,6% +8.9% +8,3% 

FRCC Florida +3.4% +4.5% +4.0% +4.0% +4.2% +4.0% +3.8% +3.5% +3.7% 

RFCM LowerMI +4.7% +6.9% +9.1% +9.2% +12.4% +11.7% +10.9% +10.5% +10.4% 

RFCW OH, IN, &WV +6.2% +10.2% +9.7% +8.7% +8.7% +8.5% +8.3% +8.3% +8.6% 

SRCE KY&TN +7.2% +6.9% +8.5% +14.7% +18.6% +17.9% +17.0% +16.5% +15.5% 

MROE WI & UpperMI +7.6% +10.5% +10.7% +8.7% +9.4%, +9.3% +8.9% +8.7% +8.8% 

MROW Upper Midwest +2.0% +1.6% +1.7% +7.0% +12.1% +11.9% +11.6% +11.6% +11.3% 

SRGW South Il & East MO +6.5% +9.6% +10.3% +11.0% +14.1% +13.3% +12.4% +11.5% +11.2% 

SPNO KS & WeslMO +6.9% +2.8% +3.7% +5.8% +9.9% +9.9% +10.4% +11.1% +12.0% 

SRDA AR, LA, & West MS +2.7% +4.6% +5.9% +7.1% +9.9% +9.4% +9.0% +8.7% +8.4% 

SPSO Oklahoma +4.7% +11.1% +12.0% +12.8% +16.0% +15.3% +14.1% +13.6% +14.0% 

ERCT Texas +6.4% +9.4% +8.3% +12.2% +8.1% +4.4% +5.5% +4.5% +3,9% 

RMPA CO & EastWY +0.7% +0.4% +0.8% +1.7% +2.4% +2.2% +2.1% +1.9% +1.9% 

NWPP Northwest ·0.2% ·0.5% -3.7% -2.0% -0.1% +0.6% +2.1% +2.5% +2.5% 

AZNM AZ&NM +1.0% +0.8% +1.2% +1.6% +1,9% +1.9% +1.8% +2.1% +2,1% 

CAMX California +0.9% +1.4% +1.5% +1:6% +1.6% +1.9% +1.9% +1.8% +1.8% 

Source: NERA calculations as explained in text 

D. References 

Brattle Group. 2010. Potential Coal Plant Retirements Under Emerging Environmental 

Regulation. Cambridge, MA: Brattle Group, December 8. 

Ava 

+6.5% 

+2.2% 

+4.2% 

+8.0% 

+5.6% 

+10.7% 

+5.1% 

+8.2% 

+3.9% 

+9.5% 

+8.6% 

+13.6% 

+9.2% 

+7.9% 

+11.1% 

+8.1% 

+7.3% 

+12.6% 

+7.0% 

+1.6% 

+0.1% 

+1.6% 

+1.6% 

u.s. Energy Information Administration. 2009. The National Energy Modeling System: An 

Overview 2009. Washington, D.C.: EIA, October. (www.eia.gov/FTPROOT/-

forecastingl05812009.pdf, accessed September 20, 2011) 

u.s. Energy Information Administration. 2011a. Annual Energy Outlook 2011. Washington, 

D.C.: ETA, April. (www.eia.gov/forecasts/aeo/pdfl0383(2011).pdf, accessed September 

20,2011) 

u.s. Energy Information Administration. 2011b. Assumptions to the Annual Energy Outlook 

2011. Washington, D.C.: EIA, July. (www.eia.gov/forecasts/aeo/assumptions/pdfl0554(20 Il).pdf, accessed September 20, 20 II) 

NERA Economic Consutting C-1S 
180 

Appendix D: Macroeconomic Modeling 

This appendix provides details on the Policy Insight Plus (PI+) macroeconomic model developed 

and licensed by Regional Economic Models, Inc. (REMI) as well as our data and methodology 

for using this model to estimate the potential macroeconomic impacts of the EPA regulations. 

A. Overview of REMI Modell 

The REMI PI+ model produces estimates of the changes in employment, gross domestic product 

(GOP), disposable personal income (i.e., personal income after taxes), and other macroeconomic 

variables due to changes in supply, demand, prices, and other types of inputs. Each version of the 

REMI PI+ model is custom-built for the regions of interest, which can range from counties to 

entire countries. The REMI PI+ model incorporates detailed and up-to-date macroeconomic data 

from the U.S. Bureau of Economic Analysis, the U.S. Bureau of Labor Statistics, the U.S. 

Census Bureau, and other public sources. The REMI PI+ model is widely used by federal, state, 

and local agencies, as well as analysts in the private sector and academia, to estimate the effects 

of regulations, investments, closures, and other scenarios. 

Figure 0-\ shows the five blocks in the REMI PI+ model and their linkages. The Output and 

Demand block balances supply and demand for all major sectors of the economy, including both 

domestic and international sources of supply and demand. The Labor and Capital Demand block 

models employment and capital stock based on output, wage rates, and capital costs. The 

Population and Labor Supply block models labor participation rate and population based on 

wage rates in the various regions and the size of the various sectors. The Compensation, Prices, 

and Costs block models each sector's production cost, including labor cost based on wage rates. 

Finally, the Market Shares block uses production cost to model each sector's domestic market 

share and international market share, which are passed back up to the Output and Demand block. 

I This section draws on model documentation from Regional Economic Models, Inc. (REMl20 II). 

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Appendix D: Macroeconomic Modeling 

Figure D-I. Key Blocks and Linkages in the REM! Model 

1I1~ __ 

"*--

Source: REM! (2011) 

B. Overview of Methodology 

We modeled the potential macroeconomic impacts of the EPA regulations using a 70-sector 

REM I PI+ model covering the entire United States. The model has regional detail based on 

Census divisions. 

We developed inputs to the REMI model using the energy market modeling results from NEMS 

for the four EPA regulations. 2 lnputs to the REMI model can take the form of either dollar 

amounts or percentage changes fi'om the built-in forecasts in the model. We entered all our 

inputs for this study as do liar amounts measured in constant dollars. 

The types of REM I inputs developed from NEMS and other sources are summarized below. 

I. Environmental control costs. We developed inputs for the positive effects of the capital and 

operations and maintenance (O&M) costs of environmental controls at the coal units that do 

not retire. These inputs include the costs of all the projected scrubbers, SCR, ACI, fabric 

filters, DSI, and compliance measures for the CCR and 316(b) regulations, broken out to the 

specific model regions in which they are projected to occur. We used the same cost 

Details on the energy market modeling results from NEMS are provided in Appendix C. 

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Appendix 0: Macroeconomic Modeling 

assumptions as those used in modeling potential coal unit retirements. These capital and 

O&M costs enter the REMI model as increased demand for machinery manufacturing and 

construction. 

2. Replacement capacity costs. We developed REMI inputs for the positive effects of capital 

costs of new generation capacity to replace the coal units that are projected to retire. Most of 

the replacement capacity is combined-cycle gas technology. We developed estimates ofthe 

capital costs of replacement capacity using energy market modeling results and capital cost 

assumptions from NEMS. These capital costs enter the REMI model as increased demand for 

machinery manufacturing and construction.3 The costs are apportioned to model regions 

based upon the regions where NEMS has projected the construction of new units will occur. 

3. Coal sales decreases. We developed REMI inputs reflecting the negative effects of 

reductions in coal sales. These reductions arise both from coal unit retirements and from the 

lower capacity factors for coal units that continue to operate but are utilized less because 

their generation costs are greater due to controls. We developed estimates of reductions in 

coal sales using regional coal production and mine mouth (i.e., wholesale) price results from 

NEMS. The NEMS results reflect estimates of changes in coal demand not only in the 

electricity sector but also in the residential, commercial, and industrial sectors; the changes in 

these other sectors are small because these other sectors consume very little coal relative to 

the electricity sector. The values enter the REMI model as decreased sales for the mining 

sector in the relevant regions. 

4. Coal price decreases. We developed REMI inputs for the negative impacts of decreases in 

coal prices on producers due to the decreased demand for coal in the electricity sector. The 

gains to electricity consumers from the lower coal prices are included below in the estimated 

effects of changes in electricity prices (which reflect the net effect of compliance costs and 

changes in fuel costs). In principle, the reductions in coal prices would lead to gains to 

consumers in non-electric sectors. NEMS does not provide information on coal prices and 

costs for these sectors that would allow us to assess these potential effects but they would be 

small because non-electric coal use is a small fraction of utility coal use.4 We developed 

estimates of the decreases in coal prices using regional coal production and mine mouth (i.e., 

wholesale) price results from NEMS. The negative impacts on producers enter the REMJ 

model as decreases in dividend income and government transfer payments (due to the 

decrease in government tax receipts from lower dividend income taxes). 

J The O&M costs of replacement capacity are assumed to be approximately equal to the avoided O&M costs of 

the coal units that retire. Thus, neither the O&M costs ofreplacement capacity nor the avoided O&M costs of the 

coal units that retire are entered into the REM! model, as they would cancel each other out. Since O&M costs of 

the generating units themselves are small relative to the other inputs to the REM! model, omission of the O&M 

costs of replacement capacity and coal units that retire does not significantly affect the results of the 

macroeconomic modeling. In contrast, we do include inputs to reflect the O&M costs of new retrofits as noted 

ahove. 

4 The residential, commercial, and industrial sectors collectively accounted for less than 7 percent of total U.S. 

coal consumption in 2010 (E!A 20! I a). Coal price effects for these sectors are considerably smaller than any 

other effect included in this macroeconomic impact analysis. 

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Appendix D: Macroeconomic Modeling 

5. Natural gas sales increases. We developed REMl inputs for the positive impacts of increases 

in natural gas sales due to the increase in demand from the electricity sector (from new 

natural gas units replacing the coal units that retire and higher capacity factors for existing 

gas units). The net increase in natural gas sales, however, is smaller than the increase in 

electricity demand because the increases in natural gas prices lead to reduced demand from 

residential, commercial and industrial sectors.5 We developed estimates of the net increase in 

natural gas sales using regional natural gas production and wellhead (i.e., wholesale) price 

results from NEMS. The values enter the REMI model as increased sales for the oil and gas 

extraction sector. 

6. Natural gas price increases. We developed REMI inputs for both the positive impacts on 

natural gas producers of higher natural gas prices (relative to cost increases) and the negative 

effects of higher natural gas prices on non-utility consumers. (As with coal prices, the 

negative effects on electric company customers are included in the electricity price impacts.) 

We developed regional estimates ofthe increase in natural gas prices using regional natural 

gas consumption and retail price results for the residential, commercial, and industrial sectors 

from NEMS. The impacts on consumers enter the REMI model for households as decreases 

in purchasing power due to increases in natural gas prices and for commercial and industrial 

sectors as increases in natural gas costs. The impacts on producers enter the REMI model as 

increases in dividend income and government transfer payments (due to the increase in 

government tax receipts associated with dividend income taxes). 

7. Electricity price increases. We developed REMI inputs for the negative impacts of increases 

in electricity prices on consumers (residential, commercial, and industrial). Because changes 

in electricity sector costs-for pollution control equipment and fuel price changes-are 

reflected in electricity prices, electricity producers as a group are not expected to be affected. 

We developed regional estimates of the increase in electricity prices for consumer groups 

using regional electricity consumption and retail price results for the residential, commercial, 

and industrial sectors from NEMS. These values enter the REMI model as increases in 

electricity price (change in purchasing power) for households and electricity costs for 

commercial and industrial sectors in the various regions. 

8. FinanCing of capital costs. This component arises because the capital costs for pollution 

control and new capacity are not reflected fully in electricity rates in the years in which they 

are incurred, although these costs are ultimately reflected in higher electricity rates (as noted 

above). We developed information on the financing of pollution control and replacement 

capacity expenditures, in particular the extent to which these capital expenditures would lead 

to reduced investment or reduced consumption in the years in which the capital expenditures 

are made, and then increased investment or increased consumption in the years in which 

, We used the version of REM! that allows for complete fuel substitution for other mctor inputs, which assumes 

that consumers can shift away from more expensive energy and thus reduce the negative impacts of higher 

natural gas and electricity prices. This assumption may understate the negative imacts of the price increases. We 

also entered the costs of substitution away from energy into the REM! model as increased demand for energyefficient appliances. Including this effect may overstate the positive impacts ifthe REM! model already 

incorporates these positive adjustments related to substitution away from energy. 

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Appendix D: Macroeconomic Modeling 

electricity price increases reflect these capital costs but the capital expenditures have already 

been made. 

C. Information on Modeling Components 

This section provides additional information on the inputs to the REMI modeling. 6 

1. Environmental Control Costs 

Environmental control costs consist ofthe capital and O&M costs for compliance measures at 

the coal units that do not retire. As discussed in the report body, we assumed that CSAPR would 

take effect in 2012 and MACT, CCR, and 316(b) would take effect in 2015. The NEMS results 

reflect compliance in these years, but that model does not incorporate leadtimes for controls. 

NEMS builds some scrubbers for compliance with the CSAPR S02 policy in 2012, and it builds 

other controls by 2015. We entered the capital costs of controls installed in 2012 into the REMI 

model as costs in 2012, and we entered the capital costs of controls installed in 2015 into the 

REMI model as costs spread evenly in 2013, 2014, and 2015 to reflect their leadtime. Costs from 

2016 onward primarily reflect the O&M cost of environmental controls. The costs are net of 

pollution control costs in the reference scenario (which primarily reflect currently planned 

retrofits by 2012 and mercury controls for state policies in the reference case). 

The environmental control costs represent increased demand for manufacturers and construction 

companies. We reviewed detailed budgets for several retrofit projects in the electricity sector 

(e.g., PSNH 2010, DOE 2003) and determined that approximately 70 percent of the costs were 

for equipment and 30 percent for construction. Thus, we modeled 70 percent ofthe 

environmental control costs in each year in REMI as increased demand for the machinery 

manufacturing sector and the remaining 30 percent as increased demand for the construction 

sector. These environmental control costs are allocated to regions in REMI based on the 

locations of the coal units incurring the costs. 

2. Replacement Electricity Capacity Costs 

Replacement capacity costs consist of the capital costs fur new electricity capacity (primarily 

combined-cycle gas units) that NEMS projects will be built, based on its evaluation of supply 

and demand in regional electricity markets, to replace the coal units that retire. 7 Most of the 

6 We considered using the optional NEMS macroeconomic activity module to develop the macroeconomic impact 

estimates but concluded that it would be less appropriate than REM! for this study. The NEMS macroeconomic 

module uses only changes in energy prices and quantities from NEMS to assess macroeconomic impacts. Thus, 

the module does not account for the increase in demand for machinery manufucturing and construction or the 

need to finance the capital expenditures. REM! allows us to incorporate both effects. Moreover, the NEMS 

macroeconomic module aggregates all energy price changes (including electricity, coal, and natural gas) into a 

single energy price index for purposes of evaluating macroeconomic impacts. REM! allows us to input separate 

estimates for the different energy types. 

7 As noted above, neither the O&M costs for replacement capacity nor the avoided O&M costs for coal units that 

retire are included in the macroeconomic modeling, because they are assumed to be approximately equal in size 

and therefore would cancel each other out. 

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Appendix D: Macroeconomic Modeling 

replacement capacity is built shortly before 2015 in anticipation of the many coal unit 

retirements in that year, but some replacement capacity is built later in the modeling period. The 

assumed capital costs for new capacity are based upon EIA estimates (2011 b, p. 97). The 

replacement capacity costs are net of new capacity costs in the reference scenario. (The four 

policies pull forward some new capacity that would be built later in the reference scenario.) 

The replacement capacity costs represent increased demand for manufacturers and construction 

companies. Based on our review of electricity sector project budgets (described above), we 

assumed that 70 percent ofthe capital costs were for equipment and 30 percent for construction. 

Thus, we modeled 70 percent of the replacement capacity costs in each year in REMI as 

increased demand for the machinery manufacturing sector and the remaining 30 percent as 

increased demand for the construction sector. 

NEMS generates estimates of replacement capacity costs for each of its 22 electricity regions, 

which are based on electric reliability regions defined by the North American Electric Reliability 

Corporation (NERC). We allocated these values to the regions in the REMI model based upon 

the shares of baseline generation capacity. 

3. Coal Sales Reduction 

The coal unit retirements and reduction in capacity factors for non-retiring coal units projected 

due to the four regulations would lead to decreased demand for coal in the electricity sector. We 

modeled the reduction in coal sales using regional NEMS results on coal production and 

minemouth (i.e., wholesale) price. In particular, we calculated the change in coal production in 

each region and multiplied it by the average ofthe minemouth prices in the reference case and 

policy case in each region to capture the quantity effect of the four regulations for coal. 8 We 

allocated these values to the regions in the REMI model based on the regional data from NEMS. 

The values enter the REMI model as decreased sales for the mining sector. 

4. Coal Price Decreases 

This section considers the effects of coal price decreases on producer surplus. As noted above, 

we did not model coal price effects on consumers because the price effect for the electricity 

sector is included in the electricity price effects and the price effects for residential, commercial, 

and industrial sectors are negligible because oftheir low coal consumption. 

The reduction in coal prices due to reduced demand by the electricity sector would reduce 

producer surplus in the coal sector.9 We developed REMI inputs for this reduction in producer 

surplus in the coal sector based on NEMS results by multiplying the change in coal minemouth 

price (a negative value) by the average of coal productions in the reference and policy cases. We 

entered the reduction in producer surplus into the REMI model as reductions in dividend income 

and allocated it across regions based on their share of the U.S. population. Since dividends are 

8 The price effects on consumer and producers surplus are modeled below. 

9 Producer surplus is the amount by which price exceeds marginal cost (or the minimum amount that producers 

would accept to produce the good), summed over all production. It relates to total profit in a sector. 

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Appendix D: Macroeconomic Modeling 

distributed by companies after paying income taxes, we flTst multiplied the producer surplus by 

an estimated effective corporate income tax rate and modeled this change in government 

corporate income tax receipts as a change in transfer payments. We used an estimated effective 

corporate income tax rate of 40 percent based on a review of tax rates for energy companies (API 

2010, p. 7) and allocated the change in transfer payments across regions based on their share of 

the U.S. population. We then modeled the remainder of producer surplus as dividend payments. 

5. Natural Gas Sales Increase 

The new gas units and higher capacity factors for existing gas units due to the four regulations 

would lead to increased demand for natural gas in the electricity sector. Since higher natural gas 

prices in the REMI model lead to lower natural gas sales, but the regulations would lead to both 

higher natural gas prices and higher natural gas sales due to the outward shift of the demand 

curve for natural gas in the electricity sector, we needed to calibrate the natural gas sales inputs 

to ensure that the REMI results would be consistent with the NEMS results for natural gas sales. 

We did this by running the REMI model first with the inputs shown above except the change in 

natural gas sales, examining the natural gas sales results from the REMI model, and calibrating 

the natural gas sales inputs to correspond with the values from NEMS. We modeled the increase 

in natural gas sales using regional NEMS results on natural gas production and wellhead (i.e., 

who lesale) price. In particular, we calculated the change in natural gas production in each region 

and multiplied it by the average of the wellhead prices in the reference case and policy case in 

each region to capture the quantity effect of the four regulations for natural gas. We allocated 

these values to the regions in the REMI model based on the regional data from NEMS. The 

values enter the REMI model as increased sales for the oil and gas extraction sector. 

6. Natural Gas Price Increases 

This section considers the impacts of increases in natural gas prices---due to increased electricity 

sector demand--on consumers and producers. 

a. Impacts on Natural Gas Consumers 

The increase in natural gas demand in the electricity sector would increase the price of natural 

gas for all sectors of the economy. We used regional NEMS results on natural gas consumption 

and retail prices for the residential, commercial, and industrial sectors to develop REMI inputs 

for these adverse consumer impacts. NEMS produces these results for the nine Census divisions. 

We calculated the change in retail natural gas price in each region and multiplied it by the 

average consumption in the reference and policy cases in each region to capture the price effect 

of the four regulations for natural gas. We allocated these values to the regions in the REMI 

model based on their historical shares of natural gas expenditures in their Census divisions. We 

entered the values for the residential sector in the REMI model as decreased household 

purchasing power (reflecting the increased natural gas prices), and we entered the values for the 

commercial and industrial sectors as increased natural gas costs for these sectors. 

NERA Economic ConsuHing D-7 
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Appendix D: Macroeconomic Modeling 

b. Impacts on Natural Gas Producers 

The increase in natural gas prices due to expanded demand by the electricity sector would 

increase producer surplus in the natural gas sector. As with producer surplus in the coal sector, 

we modeled the increase in natural gas as increases in dividend payments and government 

transfer payments, using an effective corporate income tax rate of 40 percent. The change in 

producer surplus is calculated as the change in wellhead price multiplied by the average 

production in the reference and policy cases. 

7. Electricity Price Increases 

The four regulations would lead to increases electricity prices for the residential, commercial, 

and industrial sectors. We used regional NEMS results on electricity consumption and retail 

prices for the residential, commercial, and industrial sectors to develop REMI inputs for this type 

of impact.IO NEMS produces these results for the nine Census divisions. We calculated the 

change in retail electricity price in each region and multiplied it by baseline consumption in each 

region to capture the price effect of the four regulations for electricity. We allocated these values 

to the regions in the REMI model based on their historical shares of electricity expenditures in 

their Census divisions. We entered the values for the residential sector in the REMI model as 

increased electricity price (change in purchasing power) for households, and we entered the 

values for the commercial and industrial sectors as increased electricity costs for these sectors. 

8. Financing of Capital Costs 

We presume that electricity companies would finance the net capital cost requirements (capital 

costs for environmental controls and new capacity minus contemporaneous electricity rate 

increase due to financing) in each year through debt financing. The impacts on the economy in 

each year would depend in part upon the extent to which the increased utility demand for 

capital-primarily from 2012 to 2015, with much smaller investment required from 2016 onward 

for replacement capacity-would lead to reductions in investment elsewhere in the economy, i.e., 

crowd out other investment. Since the REMI model does not reflect changes in the overall 

productivity of the economy due to changes in investment, however, the distinction between 

changes in investment and changes in consumption as the source of financing is less important. 1 

I 

The extent of crowding out of other investment depends upon the short-run demand and supply 

elasticities for investment capital as well as on the detailed general equilibrium effects in the 

overall economy. If the short-run capital supply elasticity is zero, as many researchers have 

found (see Bernheim 2002),100 percent of the increased demand by the electricity companies 

would be reflected in reduced investment elsewhere. 

to Note that the changes in retail electricity prices from NEMS reflect the annualized costs of environmental 

controls and replacement capacity, not the actual expenditures by the electricity sector in each year. This issue is 

discussed below in the context of financing. 

II Studies suggest that the general equilibrium economic effects of crowding out productive investment could be 

substantiaJ. See Schmalensee (1994). 

NERA Economic Consulting D-8 
188 

Appendix D: Macroeconomic Modeling 

Various studies have considered the specific crowding out of pollution control expenditures. 

Gray and Shadbegian (2001) find that pollution control expenditures in the pulp and paper sector 

actually lead to more than a 100 percent reduction in other capital expenditures in the sector 

when account is taken of reductions at individual plants (188 percent decline) and approximately 

100 percent decline considering only capital expenditures at other facilities. Jorgenson and 

Wilcoxen (1990) in their study of the effects of pollution control expenditures on the U.S. 

economy use a short-run elasticity for the supply of capital of zero (i.e., perfectly inelastic), 

implying 100 percent crowding out of investment in the short-tenn. 

One plausible alternative is to assume 100 percent crowding out of private investment, based 

upon estimates of a zero short-term elasticity of supply of capital and some ofthe empirical 

estimates for compliance costs. Since the elasticity of supply may be greater than zero, we 

assumed crowding out of 50 percent for the net investment years.

I2 We presumed that that the 

other 50 percent of net utility investment would come from additional savings and thus reduced 

consumption. I3 We presumed that the bondholders would receive additional income in the later 

years. 

The reduced private investment is entered into REMI as reduced investment in residential 

structures, nonresidential structures, and nonresidential equipment based on their shares of 

baseline U.S. investment. The change in income for bondholders is entered into the REMI model 

as changes in consumption. 14 

D. Modeling Results for the Four Environmental Policies 

We modeled the potential net macroeconomic impacts of the four regulations by entering all the 

inputs categories described above into the REMI model. We also calibrated the REMI model to 

ensure that the net changes in sales for the coal, natural gas, and electricity sectors with a\l the 

inputs were consistent with their net changes in sales from NEMS.I5 

12 !fthe modeling included the negative effects of crowding out productive investment on economic growth, it 

would be more important to be precise about the specific amount of crowding out of private investment. 

13 These calculations presume that environmental compliance expenditures do not use unemployed or idle 

resources. As Schmalensee (1994) points out, there is no reason why tightening environmental regulation would 

weaken economy-wide forces that produce unemployment and, indeed, that the net short-term impact of 

tightening environmental standards is likely to increase overall unemployment in the near term in the process of 

shifting jobs within the economy (with monetary and fiscal policies, changes in exchange rates, changes in 

foreign economic policies and economic conditions and firm and household expectations being the major filctors 

determining overall macroeconomic conditions). 

14 Entering the change in income alternatively as a change in dividends, interest, and rent would yield very similar 

results (because REM! indicates that dividends, interest, and rent in any year are mostly used for consumption in 

that same year). 

IS We performed this calibration by (I) running REM! once with all inputs except changes in sales; (2) calculating 

the difference between changes in sales from REM! for the coal, natural gas, and electricity sectors and their 

changes in sales from NEMS; and (3) running REMI again with the difference in sales (in addition to other 

inputs) so that the sales results from REMI would be consistent with the sales results from NEMS. 

NERA Economic Consufting 0-9 
189 

Appendix D: Macroeconomic Modeling 

Figure D-2 shows the annual impacts of the four environmental policies on U.S. employment, 

GDP, and disposable personal income from 2012 to 2020 predicted by the REMI model. 

Figure 0-2. Macroeconomic Modeling Results 

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,g, -150,000 .. 

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-400,000 -L-_______ --"""~"'---------'-

2010 2012 2014 2016 2018 2020 

$0 

-$5 

-$10 

-$15 

-$20 

-$25 

-$30 

-$35 

-$40 

L-Employ~~nt~ GOP ---Oisp~o~able Personal Income I 

Source; NERA calculations as e~l'lained in text 

NERA Economic Consulting 

z;:-

0 

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0 

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190 

Appendix D: Macroeconomic Modeling 

E. References 

American Petroleum Institute. 2011. Putting Earnings in Perspective: Factsfor Addressing 

Energy Policy. Washington, D.C.: API, July 12. (www.api.org/statistics/-

earnings/upload/earnings perspective.pdf, accessed September 20, 20 II) 

Bernheim, B. Douglas. 2002. "Taxation and Saving", ch. 18, p. 1173-1249 in Auerbach, A. J. 

and Feldstein, M. eds., Handbook of Public Economics, vol. 3, Elsevier. 

Gray, W. B. and Shadbegian, R. J. 1998. "Environmental Regulation, Investment Timing, and 

Technology Choice." The Journal of Industrial Economics 46: 235-256. 

Jorgenson, Dale W. and Peter J. Wilcoxen. 1990. "Environmental Regulation and U.S. Economic 

Growth." RAND Journal of Economics 21(2): 314-340. 

Public Service of New Hampshire. 2010. Clean Air Project: Merrimack Station. Prepared for the 

New Hampshire Public Utilities Commission: Docket 08-\03 Informational Session. 

March 31. (www.puc.nh.govlRegulatory/CaseFile/2008/08-

I 03/LETTERS,%20MEMOS/08-1 03%2020 I 0-03-

31 %20PSNH%20Clean%20Air%20Project.pdf, accessed September 20, 20 II) 

Regional Economic Models, Inc. 20 II. "The REMI Model." 

(www.remi.comlindex.php?page=model&hl=en US, accessed September 20,2011) 

Schmalensee, Richard. 1994. The Costs of Environmental Protection, in Balancing Economic 

Growth and Environmental Goals, Washington, D.C.: American Council for Capital 

Formation Center for Policy Research, pp. 55-80. 

U.S. Department of Energy. 2003. An Investigation of Site-Specific Factorsfor Retrofitting 

Recirculating Cooling Towers at Existing Power Plants. Prepared for the U.S. DOE 

National Energy Technology Laboratory by Parsons Infrastructure and Technology 

Group, Inc. January 22. 

(www.netl.doe.govftechnologiesfcoalpowerfewr/waterfpdfs/316b NETL ParsonFinalRep 

ort wAddnd 012203.pdf, accessed September 20,2011) 

U.S. Energy Information Administration. 2011a. Annual Energy Outlook 2011. Washington, 

D.C.: EIA, April. (www.eia.gov/forecasts/aeo/pd1l0383(2011).pdf, accessed September 

20,2011) 

U.S. Energy Information Administration. 201 lb. Assumptions to the Annual Energy Outlook 

2011. Washington, D.C.: EIA, July. (www.eia.gov/forecasts/aeo/assumptionsfpdll0554(2011).pdf, accessed September 20,2011) 

NERA Economic Consulting 0-11 
191 

NERA 

Economic Consulting 

NERA Economic Consulting 

200 Clarendon Street, 11th Floor 

Boston, Massachusetts 02116 

Tel: +1 617 927 4500 

Fax: +1 617 927 4501 

www.nera.com 
Impacts of Seven EPA Regulations 

Annual cost (electric sector) $15.4 B $15.0 B $16.7 B 

Peak year cost (electric sector) $37.1 B $36.1 B $44.1 B 

Total cost (electric sector, 2013 - 2034) $203 B $1988 $220 B 

U.S. average employment loss 590,0001yr 887,OOOlyr 544,0001yr U.S. peak year employment loss Over 700,000 2.2 million Almost 900,00

Peak loss in Upper Midwest 207,000 455,000 236,000 Peak loss Miss. Valley 59,000 591,000 55,000 

Total coal shutdowns 69,000 MW 69,000 MW 54,000 MW 

average income loss per household $2261yr $5121yr $2171yr 

U.S. peak year income loss $415lfamily $723lfamily $415lfamily 

Peak loss in Upper Midwest $685/family $1,300/family $650lfamily Peak loss in Miss. Valley $654lfamily $1,600/family $644/family 
EXPLANATION 

National Economic Research Associates (NERA) analyzed the impacts of seven EPA regulations tha

coal-fired electricity generation: Mercury and Air Toxics Standards (aka Utility MACT rule). region

national ambient air quality standards (NAAQS) for ozone, S02 NAAQS, PM2.5 NAAQS, 316(b), a

combustion residuals. The N.wERA model was used to conduct the analysis. Many of the economic a

assumptions are taken directly from EPA's analysis and EIA data. 

NERA's analysis involved modeling three scenarios. Scenario 1 uses EPA's annualized costs for a 

ozone standard and assumes the costs are incurred beginning in the year in which compliance is requ

each nonattainment area. Scenario 2 assumes that EPA's annualized costs for a revised ozone stand

capitalized and incurred before and during the year in which compliance is required for each nonatt

area. Thus, scenarios 1 and 2 bracket the costs of a revised ozone standard of 65 ppb. Scenario 3 a

natural gas prices that are similar to EIA's low Estimated Ultimate Recovery (EUR) case, which maprices from $0.50/MMBtu to $1.50/MMBtu higher than EIA's AEO 2012 reference case. The analysis is 

to avoid double counting. For example, emission controls installed to comply with one rule are not 

again in determining the cost of complying with another rule that might require the same emission contdollars are reported by NERA in either 2010$ or 2012$. All cumulative impacts, except employm

present values as of January 2013, calculated at a five percent discount rate. 

NERA's analysis does not use worst case assumptions and relies, in most instances, on EIA data and E

estimates. For example, NERA uses EPA costs to model the effects of regulating coal combustion rand cooling water intakes (316(b». Overall, we believe the impacts projected by 

NERA are conservativej it is very possible the impacts of these regulations could be more severe than 

projections. For example -
The analysis does not include CSAPR, which has been vacated. If EPA adopts a replacement 

impacts projected by NERA could be greater than shown in this analysis. 

The analysis assumes that (1) EPA will regulate coal combustion residuals as non-hazardous waste; 

will not require the installation of closed cycle cooling at all electric generating facilities; (3) EPA w

the ozone standard to a level of 65 ppb, rather than a more stringent level; and (4) no further e

reductions from coal-fueled units will be necessary due to EPA's revised 502 standard. If EPA 

regulations that are more stringent than these assumptions (or if the regulations are implemented in 

stringent manner), the impacts will be more severe than NERA's projections. 

The analysis does not include the potential effects of EPA's planned greenhouse gas regulations for 

coal-fired units. EPA has not proposed any such regulations yet but has indicated that it will at som

time. 

The analysis does not consider possible changes to EPA's effluent guidelines for power plan

discharges. EPA has not proposed any changes yet, but is expected to later this year. 

The analysis assumes that all necessary emission controls can be installed by 2016 to comply wi

without incurring any additional costs due to unusually large demands for labor and materials. 

The modeling does not analyze the potential for electric reliability problems that could be cause

large number of premature coal unit shutdowns over a short time frame in order to comply w

deadlines. Many experts and public officials have raised concerns about electric reliability. 

Employment losses caused by the EPA rules take into account the net effect of jobs that are lost (e.g

higher energy prices) and jobs that are created (e.g., construction of pollution controls) by these regula
Household disposable income is the total amount of money available for spending or saving by a fam

taxes have been paid. 

The NewERA macroeconomic model includes 11 regions of the U.S. The Upper Midwest region is comp

Ohio, Michigan, Indiana, Kentucky and West Virginia. The Mississippi Valley region is comprised of Wi

Illinois, Missouri and Arkansas. 

October 
196 

SUBMITTED BY THE HONORABLE CHARLES MCCONNELL

IMPACT OF EPA REGULATIONS 

National Economic Research Associates (NERA) analyzed the impacts of seven EPA 

regulations that affect coal'fucled electricity generation: MATS, regional haze, 

ozone NAAQS, SOl NAAQS, Pl'vh, NAAQS, 316(b) and coal combustion residuals. 

The analysis evaluates three scenarios: two make different assumptions about the 

timing of ozone compliance costs; the third assumes slightly higher natural gas 

prices than current projections. The projected economic impacts for all three 

scenarios arc substantial. NERA's analysis does not usc "worst case" assumptions 

These arc some of the highlights of the analysis: 

NERA's 129'page report, Eco11omic Implicatio11s of Recent and Allticipated EPA Regulatio11s 

Affecting the Electricity Sector, proVides details on the scenarios, assumptions and 

other impacts. The report is available at www.cleancoalusa.org. 

October 26, 2012 
Peak Year Employment Losses Caused by EPA Regulations 

(Five key regions of the U.S.) 
Peak Year Annual Household Income Losses Caused by EPA Regulations 

(Five key regions of the U.S.) 
199 

SUBMITTED BY THE HONORABLE CHARLES MCCONNELL
200 

SUBMITTED BY THE HONORABLE CHARLES MCCONNELL

Æ