From: Frey, Nathan J.

To: Wayland, Robertj; Culligan, Kevin; Hutson, Nick

Subject: Summary of Interagency Comments Under EO 12866/13564 EGU GHG NSPS

Date: Monday, September 09, 2013 9:58:54 PM

Attachments: Summary of Interagency Comments under EO 12866_13563 EGU NSPS 9.9.docx

Summary of Interagency Comments under EO12866_13564_RIA Electric Power Sector Profile 0829.docx

Summary of Interagency Comments Under EO 12866_13563 RIA 02 Intro and Background 0829.docx

Hello all,

Please see attached summary of interagency comments with respect to the latest round of edits

provided by EPA. We look forward to discussing these remaining comments with EPA on

tomorrow’s 10:30am interagency conference call.

Thanks and please let me know if you have any questions.

Nathan
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Summary of Interagency Working Comments on Draft Language under

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1. EPA’s CCS costs were based on NETL’s “next‐of‐a‐kind” COE estimates, but the technology’s

current first‐of‐a‐kind costs should be used instead

It is recommended that EPA clarify that the COEs of coal generation with CCS in Table 4 (Levelized Cost

of Electricity for Electric Generating Technologies, Excluding Transmission Costs) of “Standards of

Performance for Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating

Units” are representative of future, nth‐of‐a‐kind plants and do not reflect the present cost of

commercial offerings, which are substantially higher.

In order to more accurately portray the current cost of CCS, it is suggested that Table 1 below should

replace Table 4 (Levelized Cost of Electricity for Electric Generating Technologies, Excluding

Transmission Costs) of “Standards of Performance for Greenhouse Gas Emissions from New Stationary

Sources: Electric Utility Generating Units.”

For an emerging technology like CCS, costs can be estimated for a first‐of‐a‐kind (FOAK) plant or an nth‐

of‐a‐kind (NOAK) plant, the latter of which has lower costs due to the “learning by doing” and risk

reduction benefits that result from serial deployments as well as from continuing R&D.  For a power

plant based on fully mature technology, such as a supercritical pulverized coal plant without CO2

capture, NETL’s estimates are for an NOAK plant.  For plants that utilize technologies that are not fully

mature, such as IGCC or any plant with CO2 capture, NETL’s cost estimates are for a plant that is

somewhere between FOAK and NOAK, sometimes referred to as “next‐of‐a‐kind”.  These “next‐of‐a‐

kind” estimates do not include the cost premiums associated with FOAK demonstrations and are

probably closer to NOAK costs than FOAK costs.

Accordingly, it should be noted that EPA’s COE estimates for power plants with CO2 capture, which are

based on NETL’s “next‐of‐a‐kind” values, are more representative of future NOAK commercial offerings

and do not reflect the much higher costs currently being realized by FOAK demonstration plants.  For

example, NETL expects the actual CO2 mitigation costs for two of its FOAK coal CCS demonstration

projects (the WA Parish PC Plant and the Kemper County IGCC plant) to be 35‐80% higheri

than the more

mature costs projected by the referenced NETL studies.  While much of this cost premium may be

attributable to differences between the actual design, scope and scale of the demonstration projects

compared to what was assumed for the NETL studies, at least some of the cost delta is certainly

associated with FOAK issues.   

An NETL study on technology learning curvesii examined how “learning by doing” might reduce the cost

of an IGCC plant with CO2 capture by applying a different learning rate to each plant subsystem

consistent with its maturity level.  Learning rates varied from 0.01 for very mature technologies to 0.06

for FOAK technologies.  For the overall IGCC system, it was estimated that the NOAK cost could be 15%

lower than the FOAK cost.  Using the same approach, the study estimated that NOAK costs for PC and

NGCC plants with CO2 capture could be 10% and 14% lower than their FOAK costs, respectively.  These

relationships between FOAK and NOAK costs were used to estimate the FOAK costs in Table 1.
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As shown in the table, a rough projection of COE for the Kemper County IGCC falls near the bottom of

the range of NETL’s estimate for a FOAK IGCC plant with 90% CO2 capture.  It should be noted that the

Kemper IGCC will capture somewhat less CO2 (67% versus 90%) and that the design basis of the Kemper

IGCC differs somewhat from that assumed by the NETL studies (e.g., different gasification technologies,

lignite coal versus bituminous coal).  It should also be noted that the Kemper IGCC plant is still under

construction and may experience additional increases in cost.

Table 1 – Cost of Electricity Estimates for Power Generation with and without CCS

Technology Cost of Electricity ($2011/MWh)

CO2

Capture,

%

CO2 Emission

Rate,

lb/MWh‐gross

Capacity

Factor,

%

EPA

NETL

recommendation

(next‐of‐a‐kind)iii

NETL

recommendation

(first‐of‐a‐kind)

NGCCiv  

0 790

85 60 – 77

50 71 ‐ 92

24 600

85 69 ‐ 90 79 ‐ 103

50 85 ‐ 110 97 ‐ 125

40 480

85 74 ‐ 97 84 ‐ 111

50 92 ‐ 120 105 ‐ 137

90 87

85 90 ‐ 118 103 ‐ 135

50 115 ‐ 149 131 ‐ 170

SCPC  

0 1,675 85 92 91 ‐ 118

40 1,100 85 110 110 – 143 121 ‐ 157

90 202 85 147 147 ‐ 191 162 ‐ 210

IGCC

0 1,433 80 97 101 ‐ 131

25 1,100 80 109 112 ‐ 146 129 ‐ 168

90 152 80 136 142 ‐ 185 163 ‐ 213

Kemper IGCC ~65 541v 80    ~170vi

Nuclear     103 – 114   

2. “Next‐of‐a‐kind” costs will not be realized before more demonstration projects proceed

Despite NETL’s best efforts to accurately estimate costs, it is widely accepted among cost estimation

professionals that projections of NOAK costs for technologies that are still under development are

typically lower than the actual costs that are eventually realized (see Figure 1 below).  This “technology
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optimism” tends to persist even when substantial process contingencies are applied to early estimates,

and is applicable for CO2 capture costs as well as CO2 storage costs, both of which are embedded in the

tabulated COE estimates.  

Figure 1 – Technology Cost Curve

In addition to the premiums associated with FOAK plants, another factor that could result in higher costs

than those tabulated relates to the ability of a plant to exceed the proposed 1,100 lb/MWh‐gross

regulatory emission limit.  The tabulated estimates reflect costs for plants that would precisely meet the

emission limit during steady state operation without any buffer for operational excursions and very

limited flexibility to adjust the CO2 capture rate in response to market conditions (while still complying

with the regulation on average).  Plants designed for additional capture to provide a buffer and/or for

flexible capture rates will cost more.

3. The NETL costs used by EPA represent the low end of the COE range, but the high end of the

range should also be considered

NETL reviewed the EPA estimates and appended some recommended values to Table 1.  Both EPA and

NETL base their cost estimates on two NETL reports:

1. Cost and Performance of PC and IGCC Plants for a Range of Carbon Dioxide Capture.  August

2011.  DOE/NETL‐2011/1498.
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2. Updated Costs (June 2011 Basis) for Selected Bituminous Baseline Cases.  August 2012.  

NETL/DOE‐341/082313.   

Report 2 estimated costs in June 2011 dollars, while Report 1 estimated costs in June 2007 dollars.  For

consistency, the recommended values obtained from Report 1 have been adjusted to be in June 2011

dollars.  The recommended values also express an uncertainty range (‐0%/+30%) for each technology

cost instead of a point estimate.

                                                           

i

 This estimate is based on internal NETL analyses and did not originate with the demonstration project participants. 

As such, it may not represent their own projections of demo project costs. 

ii Quality Guidelines for Energy System Studies: Technology Learning Curve (FOAK to NOAK). NETL/DOE341/042211. March 2012. 

iii Values reported by NETL are first-year, nominal dollar COEs that include a cost of $10/tonne for transport and 

storage of captured CO2. NGCC COEs assume a delivered natural gas price of $6.13/MMBtu. All coal plants 

assume bituminous coal at a delivered cost of $2.94/MMBtu, except for the Kemper County IGCC which uses 

lignite coal. 

iv NGCC COEs are based on plants that feature an advanced F-frame gas turbine. COEs for NGCCs with more 

advanced gas turbines (H- or J-frames) would be around 5-10% less for systems without CCS and 7-14% less for 

systems with 90% CCS. 

v

 Source: Page 5, http://www.catf.us/resources/testimony/files/20120920-

Thompson_CATF_Energy_and_Power.pdf 

vi This internal NETL estimate (which did not come from Southern Company) is based on the most recent publicly 

reported capital cost of ~$7,300/kW for the Kemper IGCC plant (assumed to be a total as-spent capital cost, 

excluding costs for the lignite mine and CO2 pipeline, and calculated based on the plant’s syngas-based net capacity 

of ~524 MW) and the following assumptions based on generic NETL system studies: an O&M cost of $54/MWh 

including fuel, a capital charge factor of 0.124, and a capacity factor of 80%. 

4.  The preamble notes on page 29 that biomass‐fired generation is a technology that can provide

intermediate or base‐load power.  It would be helpful if EPA could also address biomass co‐firing,

specifically how would biomass emissions be calculated for purposes of compliance with the NSPS.    

EPA’s response to interagency comments addressed biomass, and some of the response could be

incorporated into the preamble.  For example, EPA could incorporate some of the following language:  

“EPA recognizes the potential emissions benefits of co‐firing with biomass. In September 2011, EPA

submitted its Draft Accounting Framework for Biogenic CO2 Emissions from Stationary Sources to the

Science Advisory Board (SAB) Biogenic Carbon Emissions (BCE) Panel for peer review.  The SAB BCE Panel

delivered its Peer Review Advisory to OAR on September 28, 2012[1], and EPA is evaluating the peer

review comments in order to determine the most appropriate method of accounting for CO2 emissions

from biogenic feedstocks in the regulatory context.  The overall net atmospheric impact of using a

biogenic feedstock will ultimately depend on the stationary source process and the type of feedstock

used, as well as the conditions under which that feedstock is grown and harvested.”

5. Question for background: Recognizing that this proposed rule would only require coal‐fired units to

transfer captured CO2 to a facility that reports through EPA’s GHG reporting program and does not

impose requirements for long‐term storage of CO2, would EPA have the authority to issue a separate
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regulation to address emissions from the downstream CO2 storage facilities if leakage or venting

became more of a problem than EPA anticipates?  (Through a separate 111 standard, for example?)

6.  Does EPA address in the preamble how existing coal units that have been converted to natural gas

units will be treated?  In other words, if a coal unit is converted to a natural gas (or co‐firing) unit, is it

considered a “new” source that is then subject to the NSPS for new sources?  It would be helpful for EPA

to explain the treatment of such sources in the rule.   

7. “By contrast, NGCC with CCS is not a configuration that is being planned and built today. ...”  

Recommend deleting “planned and” and therefore leaving as “that is not being built today.”  Why?  We

know of two instances where there have been corporate press announcements of “plans” to develop

NG‐CCS: GE‐Sargas and Summit‐Linde.  If EPA has specific definitions of what constitutes “planned” that

go beyond press announcements, then this might assuage our concern.

8. “... the subpart would contain two different categories, one for utility boilers and IGCC units and one

for stationary combustion turbines.”  Small technical correction: should be “stationary natural gas

combustion turbines.

9. “Therefore, we are proposing the gross electric output for steam generating units ...” et sequelae.  

EPA is clearly grappling with the concept of gross, adjusted gross, and net emission standards.  

Essentially, the proposal is that steam turbines get adjusted gross (i.e., gross minus some parasitic load,

which is small) while IGCC get gross (i.e., don’t adjust for parasitic load for CCS because of the

complexity in measurement and co‐product manufacture).  It reads a little like a bonus pass for IGCC‐

CCS, which has quite a significant parasitic load.  If power companies are designing IGCC for its benefits

and accepting the intrinsic parasitic load, then what would be the additional parasitic load for the CCS

component ‐‐ percentage?

10. Paragraph starting: “The 2013 AEO cost and performance ...”  Regarding the capacity factor

definitions here, there still seems to be some inconsistency between “supply” and “sell.”  Suggest a

quick scrubbing to keep to the term in the actual rule, which is ... “sales”.

11.  Paragraph starting “We are not currently considering ..”  Search IGCG and replace with IGCC.

12.  Footnote 237: This does not include the dispatch rate for NGCC in the table, which is important,

unless “combustion turbine” dispatch is meant to cover NGCC.

13. “A. Best system of emission reduction.  The EPA evaluated several different ...”  [systems for natural

gas].  “... because of uncertainties about technical feasibility ...” Suggest changing to, as EPA does later

on, “... BSER because of insufficient information to determine technical feasibility ...”   

13.  “Because virtually all new fossil fuel‐fired power is projected to use NGCC technology, requiring CCS

would add significant costs to electricity generation across the nation ...”  Suggest that EPA read this
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language in the context of how it might sound 8 years hence when BSER again has to be determined for

EGUs.  The EIA estimated cost for NGCC‐CCS is $93/MWhr, up from $63/MWhr for NGCC alone.  The $93

LCOE estimate for NGCC‐CCS is within the range of current prices for electricity generation across the

board (wind, solar, nuclear, etc) that EPA has emphasized as supportive of requiring partial CCS for IGCC

and SCPC in this rule.  It would seem that the price increase logic against NGCC‐CCS is contrary to a

major basis of the current NSPS rationale for coal.  Indeed, the reason that NGCC‐CCS is not BSER is

because we do not have sufficient information and essentially none have been built (so it’s not BSER),

rather than there being intrinsic problems with this technology which EPA is inappropriately trying to

use as supporting rationale.  Also, increasing the price of an electricity generation source, per se, is not

sufficient to reject BSER, as such a future evaluation should take into account the alternative energy

sources and the social and environmental benefits of the proposed requirement, i.e., this RIA analysis

would rightly bring in the social cost of carbon, which it has not done currently in this sentence and

statement.   

Regulatory Impact Analysis:

14. “... and small amounts of coal with CCS supported largely by Federal and State funding).  Delete

“largely.”  For instance, the current capital cost of Kemper (not O&M) is around $3.8B, while the direct

DoE subsidy is ~$400M, plus tax incentives.  This sentence, as written, gives a false impression of the

proportional contribution of Federal and State money to the EGUs through the term “largely,” absent a

more careful analysis of proportional contributions from Southern Corp.

Additional minor suggested changes

1. Page 8 – first sentence in the supplementary information section is not needed. 

2. Page 14 – consider the consistency regarding the use of “adequately demonstrated” before the (BSER) 

acronym. Page 18 states “BSER adequately demonstrated”, instead of “adequately demonstrated BSER”. Please 

address for consistency. 

3. Page 15 – suggest adding one more sentence to round out discussion of not proposing stds for modified or 

reconstructed sources. 

4. Page 20 – in sentence with FN 4, add “new” before “sources covered by subpart Da”. 

5. Page 20 – is it better to say “may” justify a separate BSER determination? 

6. Page 24 – please specify what type of standard “it may propose a standard” for the coal-fired EGU. An 

NSPS standard specific to that unit, which presumably is not installing CO2? 

7. Page 31 – Please address comment about international facilities with partial CCS. 

8. Page 32 – Please add a FN noting which facilities would already meet an emission limit based on partial 

CCS. 

9. Page 34 – Why is it not enough to say that there isn’t sufficient information? It seems odd to question the 

technical feasibility of implementing CCS at NGCC units. Is there a way to talk about the potential for emissions 

reductions from CCS at NGCC units, and compare that to the cost? Or note that there is not enough data to do such 

an analysis? Having one NGCC unit indicates that it is technically feasible. 

10. Page 34 – please clarify the percent involved in “a very small portion of its exhaust stream” 

11. Page 35 – in added redline, need to add an “s” to “mean”. 

12. Page 43 – FN 13 should include “CRR” as an abbreviation if the agency intends to later use it in FN 35. 

Note FN 65 also includes full citation, yet FN 113 does not. Need to make consistent throughout. 
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13. Page 64 – FN 44 references a sensitivity analysis with the year 2025, but earlier in the text 2024 is 

referenced. Which year is accurate? 

14. Page 72 – Will EPA add examples of other NSPS that do prescribe a particular technology? 

15. Page 77 – omit comma after April in redline text. 

16. Page 82 – there are two “of” in the 4th line; second “of” should be “if”. 

17. Page 84 – Suggest EPA add another sentence explaining why CO2 emissions are the only entity subject to 

the proposed standard of performance. Why not include other GHGs? 

18. Page 84 – suggest EPA add FN regarding liquid oil-fired CC units to provide more clarity to public. 

19. Page 95 – what does “we take comment” mean on the fourth to last line? 

20. Please address comments on page 96 and 104. 

21. Page 128 – Redraft the following “This combined category cannot be considered a new category”. 

22. Page 132 – Please clarify with a quantity or percent what “a major component of that air pollution” means. 

23. Page 141 – change conclude to “concludes” 

24. Page 179, 187, 208, and 244 – please address comments. 

25. Page 227 – It does not appear that additional text was added. 

26. Page 266 – Odd that the list of GHGs is placed in FN 266. Consider stating earlier. 

27. Page 279 – Please address comments. 

28. Page 336 – In the Impacts of the Proposed Action section, suggest adding a discussion here of the potential 

impacts of the alternative co-proposal , and comparing that with the separate standards proposal. Given that the coproposal is unlikely to alter the estimated impacts, costs, and benefits, it may be sufficient to add a paragraph of 

discussion in the beginning of the Section. 
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CHAPTER 2

INTRODUCTION AND BACKGROUND

2.1 Introduction

In this action, the EPA seeks to set emission limits for limit GHGs, specifically carbon

dioxide (CO2), emitted from fossil fuel‐fired electric utility generating units (EGUs). This

document presents the expected economic impacts of the proposed EGU New Source GHG

Standards rule through 20220, including some projections for years up to 2030beyond 2020.

Based on the analysis presented in Chapter 5, expected and anticipated economic conditions

will lead electricity generators to choose fuels and technologies that are designed to meet the

proposed standard without the need for additional capture or control, even in the absence of

the rule. As a result, this rule is expected to have no, or negligible, costs or monetized benefits

associated with it. This chapter contains background information on the rule and an outline of

the chapters of the report.

2.1.1   Statutory Requirement

Section 111 of the CAA requires performance standards for air pollutant emissions from

categories of stationary sources that may reasonably contribute to endangerment of public

health or welfare. In April 2007, the Supreme Court ruled in Massachusetts v. EPA that GHGs

meet the definition of an “air pollutant” under the CAA. This ruling clarified that the authorities

and requirements of the CAA apply to GHGs. As a result, the EPA must make decisions about

whether to regulate GHGs under certain provisions of the CAA, based on relevant statutory

criteria. The EPA issued a final determination that GHG emissions endanger both the public

health and the public welfare of current and future generations in the Endangerment and Cause

or Contribute Findings for Greenhouse Gases Under Section 202(a) of the CAA (74 FR 66,496;

Dec. 15, 2009). Because fossil fuel‐fired EGUs contribute significantly to domestic CO2

emissions, the EPA is proposing this action to regulate these emissions from new EGU sources

under section 111 of the CAA.  

On April 13, 2012, the EPA proposed new source performance standards for emissions

of CO2 for new affected fossil fuel‐fired EGUs (77 FR 22392). After consideration of public

comments received – totaling approximately 2.7 million – the EPA determined that significant

revisions in its proposed approach are warranted to tailor the required emission limits to the

different types of sources in the electricity sector. As such, the EPA is, in a separate action,
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rescinding the original proposal and is re‐proposing standards of performance for new affected

fossil fuel‐fired EGUs. This action addresses standards for new sources but does not address

standards for modified, reconstructed, or existing sources.   

2.1.2 Regulatory Analysis  

In accordance with Executive Order 12866, Executive Order 13563, and EPA’s Guidelines

for Preparing Economic Analyses, the EPA prepared this RIA for this “significant regulatory

action.”This rule is not anticipated to have an annual effect on the economy of $100 million or

more or adversely affect in a material way the economy, a sector of the economy, productivity,

competition, jobs, the environment, public health or safety, or State, local, or tribal

governments or communities and is therefore not an “economically significant rule.” However,

under EO 12866 (58 FR 51,735, October 4, 1993), this action is a “significant regulatory action”

because it “raises novel legal or policy issues arising out of legal mandates.” As a matter of

policy, the EPA has attempted to provide a thorough analysis of the potential impacts of this

rule, consistent with requirements of the Executive Orders.

This RIA addresses the potential costs and benefits of the new source emission limits

that are the focus of this action. The EPA does not anticipate that any costs or quantified

benefits will result from this proposed rule, if companies make the types of choices related to

new generation that the EPA’s modeling, EIA’s modeling and many utility IRP’s indicate they are

likely to make.  If some companies do choose to build new coal plants, there could be some

compliance costs. However, in these cases, the rule will result in net societal benefits.  

For new sources, the EPA and other energy modeling groups such as EIA1 do not project

that any new coal capacity without federally‐supported CCS will be built in the analysis period.

This is due in part to the low levelized cost of base load NGCC capacity relative to coal capacity,

relatively low growth in electricity demand, and use of energy efficiency and renewable energy

resources. This conclusion holds under a range of sensitivity analyses as well as in the EPA’s

baseline scenario. Furthermore, absent this rule, any new NGCC that may be built is expected

to have an annual emission rate in compliance with the standard. Because this rule does not

change these projections, it is expected to have no, or negligible, costs2 or quantified benefits

                                                      

1 AEO 2009‐2013. 2 Because of existing and anticipated trends in the marketplace, the EPA does not project that any EGUs expected

to be built within the time frame of our analysis will have to install additional controls to meet the standard.

Additionally, because new generators would already be required to monitor and report their CO2 emissions
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associated with it. Chapter 5 of this RIA also provides an illustrative analysis of the levelized cost

of electricity and health and environmental impacts associated with representative new

conventional coal and NGCC units, under a range of natural gas price assumptions. That

analysis, along with information on historical3 and projected4 gas prices, supports the

conclusion that this standard is highly likely to have no costs or benefits. While we do not

project any new coal‐fired EGUs without CCS to be built in the absence of this proposal,

because some companies may choose to construct coal or other solid fossil fuel‐fired units,

Chapter 5 also includes an analysis of the project‐level costs of a unit with and without CCS, to

quantify the potential cost for a solid fossil fuel‐fired unit with CCS. There is also a comparison

of the costs and benefits for the proposed standard that can be met using partial CCS and a

more stringent alternative requiring full CCS.       

2.2 Background for the Proposed EGU New Source GHG Standards

2.2.1 Baseline and Years of Analysis

The rule on which this analysis is based proposes GHG emission limits for new EGUs. The

baseline for this analysis, which uses IPM, includes state rules that have been finalized and/or

approved by a state’s legislature or environmental agencies as well as final federal rules.

Additional legally binding and enforceable commitments for GHG reductions considered in the

baseline are discussed in Chapter 5 of this RIA.  

All analysis is presented for compliance through the year 202205 and all estimates are

presented in 2011 dollars. CAA Section 111(b) requires that the NSPS be reviewed every eight

years.  As a result, this rulemaking’s analysis is primarily focused on projected impacts within

the current eight‐year NSPS timeframe. – using 2020 as a base year within that timeframe.  

However, the trend of favoring NGCC over coal (and therefore the core findings of no projected

costs or monetized benefits) continues beyond the 8 year NSPS timeframeupdate in both the

                                                                                                                                                                              

under the information collection requirements contained in the existing part 75 and 98 regulations (40 CFR part

75 and 40 CFR part 98), any additional monitoring or reporting costs from this proposed rule should be

negligible. Costs are only incurred if there has been a violation of an emission standard caused by a malfunction

and a source chooses to assert an affirmative defense. The owner/operator must meet the burden of proving

all of the requirements in an affirmative defense. See Chapter 6 for more details on monitoring and reporting

costs. 3 EIA. U.S. Natural Gas Prices. Available online at: http://www.eia.gov/dnav/ng/ng_pri_sum_dcu_nus_a.htm.   4

AEO 2009‐2013.   5 Conditions in the analysis year of 2022 are represented by a model year of 2020.
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IPM and EIA reference cases, as well as in the vast majority of EIA sensitivity scenarios.6

  

Sections 5.8 to 5.10 of this RIA discuss the social costs and benefits of the proposed standards

in any limited cases where new coal plant builds are affected by the standard. Any estimates

presented in this report represent annualized estimates of the benefits and costs of the

proposed EGU New Source GHG Standards rather than the net present value of a stream of

benefits and costs in these particular years of analysis.7

2.2.2 Definition of Affected Sources

This action will directly regulate CO2 emissions from affected EGUs that commence

construction after the issuance of this proposed rule. This rulemaking does not address GHG

emissions from existing, modified, or reconstructed sources.

2.2.2.1 New Sources

The statutory authority for this action is Clean Air Act (CAA) section 111(b), which

addresses standards of performance for new, modified, and reconstructed sources. Today’s

proposal applies to new sources, which are sources that “commence construction” after

publication of the proposal, other than the Wolverine project in Rogers City, Michigan,

currently the only proposed coal‐fired EGU project without CCS with an air permit that has not

already commenced construction.  We anticipate proposing standards for this project when we

finalize today’s action if the project has not yet commenced construction and has not been

canceled. See the preamble for further discussion.

2.2.2.2 Modified Sources

A modification is any physical or operational change to a source that increases the

amount of any air pollutant emitted by the source or results in the emission of any air pollutant

not previously emitted. However, projects to install pollution controls required under other

CAA provisions are specifically exempted from the definition of “modifications” under 40 CFR

                                                      

6 For example, the low gas resource sensitivity scenario, one of the scenarios most favorable to new coal builds,

does not begin to show new conventional coal builds until 2027.  The No GHG Concern case does show limited

amounts of conventional coal starting in 2023; however that model sensitivity case is unlikely to be reflected in

actual markets given that investors factor in risks associated with all possible future policies (under both

current authorities and potential legislation atand the State and Federal levels) to reduce GHG emissions over

the multi‐decade life of the plant.    7 However, the CO2‐related benefits, which are estimated using the social cost of carbon, vary depending on the

year in which the change in CO2 emissions occurs.  The social cost of carbon increases over time because future

emissions are expected to produce larger incremental damages as physical and economic systems become

more stressed in response to greater climatic change.  See Chapter 5 for details.
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60.14(e)(5), even if they emit CO2 as a byproduct. The significant majority of projects that the

EPA believes EGUs are most likely to undertake in the foreseeable future that could increase

the maximum achievable hourly rate of CO2 emissions would be pollution control projects that

are exempt under this definition. More details on modified sources can be found in the

preamble. The EPA is not proposing a standard of performance for modifications at this time. As

a result, existing sources that undertake modifications will continue to be treated as existing

sources and thus not subject to the requirements of this rule.  

2.2.2.3   Reconstructed Sources

The EPA’s CAA section 111 regulations provide that reconstructed sources are to be

treated as new sources and, therefore, subject to new source standards of performance. The

regulations define reconstructed sources, in general, as existing sources: (i) that replace

components to such an extent that the capital costs of the new components exceed 50 percent

of the capital costs of an entirely new facility and (ii) for which compliance with standards of

performance for new sources is technologically and economically feasible (40 CFR 60.15).

Historically, very few power plants have undertaken reconstructions. We are not aware that

any power plants are presently planning any project that cwould meet the requirements for a

reconstruction. The EPA is not proposing a standard for reconstructions. As a result, sources

that undertake reconstruction will be treated as existing sources and thus not subject to the

requirements of this rule.

2.2.2.4 Existing Sources  

For the purposes of this rule, an existing EGU is defined as any fossil fuel‐fired

combustion unit that sells more than one‐third of its potential electric output and more than

219,000 megawatt‐hours (MWh) net‐electrical output to the grid on a three year rolling

average basis and was in operation or commenced construction on or before publication of the

proposed rule. Existing sources are not covered in this proposed rule.

2.2.3 Regulated Pollutant

This rule sets a limit for CO2 emissions from affected sources. The EPA is proposing these

requirements because CO2 is a GHG and fossil fuel‐fired power plants are the country’s largest

stationary source emitters of GHGs. In 2009, the EPA found that by causing or contributing to

climate change, GHGs endanger both the public health and the public welfare of current and

future generations.
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The EPA is aware that other GHGs such as nitrous oxide (N2O) (and to a lesser extent,

methane (CH4)) may be emitted from fossil‐fuel‐fired EGUs, especially from coal‐fired

circulating fluidized bed combustors and from units with selective catalytic reduction and

selective non‐catalytic reduction systems installed for nitrogen oxide (NOX) control. The EPA is

not proposing separate N2O or CH4 emission limits or an equivalent CO2 emission limit because

of a lack of available data for these affected sources. Additional information on the quantity

and significance of emissions and on the availability of cost effective controls would be needed

before proposing standards for these pollutants.

2.2.4 Emission Limits

This rule proposes emission standards for affected fossil fuel‐fired units within existing

subparts – natural gas‐fired stationary combustion turbines within subpart KKKK and fossil fuel‐

fired electric utility steam generating units (boilers and IGCC units) within subpart Da. Emission

standards are proposed for existing subcategories within KKKK. Those subcategories are:

natural gas‐fired stationary combustion turbines with a heat input rating that is greater than

850 million British thermal units per hour (MMBTU/hr) and natural gas‐fired stationary

combustion turbines with a heat input rating that is less than or equal to 850 MMBtu/hr. A

separate standard is proposed for fossil fuel‐fired boilers and IGCC units within subpart Da. The

respective emission limits are shown in table 2‐.1.

Table 2‐.1. Proposed Emission Limits

Subcategory Emission Limit 

(lb CO2/MWh) 

Stationary natural gas-fired combustion turbine EGUs with a 

heat input rating greater than 850 MMBtu/hr 

1,000 

Stationary natural gas-fired combustion turbine EGUs with a 

heat input rating less than or equal to 850 MMBtu/hr 

1,100 

Fossil fuel-fired boilers and IGCC 1,100 

This action also proposes an alternative emission limit, available only to new fossil fuel‐

fired boilers and IGCC unitssolid fossil‐fired EGUs, which can be met over a 60‐operating month

rolling average basis.  The alternative emission limit will be between 1,000950 and 1,050 lb

CO2/MWh of gross energy output.  

Comment [A1]: Should revise to “850

MMBtu/hr” and be consistent with the

use of “Btu.”  
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2.2.5 Emission Reductions

As will be discussed in more detail in Chapter 5 of this RIA, the EPA anticipates that the

proposed EGU New Source GHG Standards will result in negligible changes in GHGemissions

over the analysis period (through 2020 and following years). Even in the absence of this rule,

the EPA expects that owners of new units will choose generation technologies that meet these

standards due to expected economic conditions in the marketplace.  

2.3 Organization of the Regulatory Impact Analysis

This report presents the EPA’s analysis of the potential benefits, costs, and other

economic effects of the proposed EGU New Source GHG Standards to fulfill the requirements of

an RIA. This RIA includes the following chapters:

 Chapter 3, Defining the Climate Change Problem and Rationale for the Rulemaking,

describes the effects of GHG emissions on climate and offers support for the EPA

undertaking this rulemaking.

 Chapter 4, Electric Power Sector Profile, describes the industry affected by the rule.  

 Chapter 5, Costs, Benefits, Economic, and Energy Impacts describes impacts of the

proposed rule.

 Chapter 6, Statutory and Executive Order Impact Analyses, describes the small

business, unfunded mandates, paperwork reduction act, environmental justice, and

other analyses conducted for the rule to meet statutory and Executive Order

requirements.  

Comment [A2]: Should it be consistent

with the beginning which states 2022.  
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CHAPTER 4

ELECTRIC POWER SECTOR PROFILE

4.1 Introduction

This chapter discusses important aspects of the power sector that relate to the 

proposed EGU New Source GHG Standards, including the types of power-sector sources 

affected by the proposal, and provides background on the power sector and electric generating 

units (EGUs). In addition, this chapter provides some historical background on the EPA

regulation of, and future projections for, the power sector.

4.2 Power Sector Overview

The production and delivery of electricity to customers consists of three distinct 

segments: generation, transmission, and distribution.

4.2.1 Generation

Electricity generation is the first process in the delivery of electricity to consumers. Most 

of the existing capacity for generating electricity involves does so by creating heat to create 

high pressure steam that is released to rotate turbines which, in turn, create electricity. The 

power sector consists of over 18,000 generating units, comprising fossil-fuel-fired units, nuclear 

units, and hydroelectric and other renewable sources dispersed throughout the country (see 

Table 4-1).

These electric generating sources provide electricity for commercial, industrial, and 

residential uses, each of which consumes roughly a quarter to a third of the total electricity 

produced (see Table 4-2). Some of these uses are highly variable, such as heating and air 

conditioning in residential and commercial buildings, while others are relatively constant, such 

as industrial processes that operate 24 hours a day.
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Table 4-1. Existing Electricity Generating Capacity by Energy Source, 2011

Energy Source

Number of 

Generators

Generator 

Nameplate 

Capacity (MW)

Generator Net 

Summer 

Capacity (MW)

Coal 1,400 343,757 317,640

Petroleum 3,738 57,537 51,208

Natural Gas 5,574 477,387 415,191

Other Gases 91 2,202 1,934

Nuclear 104 107,001 101,419

Hydroelectric Conventional 4,048 78,194 78,652

Wind 781 45,982 45,676

Solar Thermal and Photovoltaic 326 1,564 1,524

Wood and Wood-Derived Fuels 345 8,014 7,077

Geothermal 226 3,500 2,409

Other Biomass 1,660 5,192 4,536

Hydroelectric Pumped Storage 154 20,816 22,293

Other Energy Sources 81 1,697 1,420

Total 18,530 1,153,149 1,051,251

Source: Table 4.3, EIA Electric Power Annual, 2011

Note: This table presents generation capacity. Actual net generation is presented in Table 4-3.

Table 4-2. Total U.S. Electric Power Industry Retail Sales in 2011 (Billion kWh)

Sales/Direct Use 

(Billion kWh)

Share of Total 

End Use

Retail Sales

Residential 1,423 37.9%

Commercial 1,328 35.4%

Industrial 991 26.4%

Transportation 8 0.2%

Direct Use 133 3.5%

Total End Use 3,883 100%

Source: Table 2.2, EIA Electric Power Annual, 2011

In 2011, electric generating sources produced 3,949 billion kWh to meet electricity 

demand. Roughly 70 percent of this electricity was produced through the combustion of fossil 

fuels, primarily coal and natural gas, with coal accounting for the largest single share (see 

Table 4-3).
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Table 4-3. Electricity Net Generation in 2011 (Billion kWh)

Net Generation 

(Billion kWh)

Fuel Source 

Share

Coal 1,718 43.5%

Petroleum 28 0.7%

Natural Gas 926 23.5%

Other Gases 3 0.1%

Nuclear 790 20.0%

Hydroelectric 312 7.9%

Other 172 4.3%

Total 3,949 100%

Source: Tables 3.2.A and 3.3.A, EIA Electric Power Annual, 2011

Note: Excludes generation from commercial and industrial sectors. Retail sales are not equal to net generation 

because net generation includes net exported electricity and loss of electricity that occurs through 

transmission and distribution.

Coal-fired generating units have historically supplied “base-load” electricity, the portion 

of electricity loads which are continually present, and typically operate throughout the day. 

Along with nuclear generation, these coal units meet the part of demand that is relatively 

constant. Although much of the coal fleet operates as base load, there can be notable 

differences across various facilities (see Table 4-4). For example, coal-fired units less than 100 

megawatts (MW) in size compose 37 percent of the total number of coal-fired units, but only 6 

percent of total coal-fired capacity. Gas-fired generation is better able to vary output and is the 

primary option used to meet the variable portion of the electricity load and has historically 

supplied “peak” and “intermediate” power, when there is increased demand for electricity (for 

example, when businesses operate throughout the day or when people return home from work 

and run appliances and heating/air-conditioning), versus late at night or very early in the 

morning, when demand for electricity is reduced. 

The evolving economics of the power sector, in particular the increased natural gas 

supply and subsequent relatively low natural gas prices, have resulted in more gas being 

utilized as base load energy in addition to supplying electricity during peak load. Projections of 

new capacity and the impact of this rule on these new sources are discussed in more detail in 

Chapter 5 of this RIA.
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Table 4-4. Coal Steam Electricity Generating Units, by Size, Age, Capacity, and Thermal 

Efficiency (Heat Rate)

Unit Size Grouping 

(MW) No. Units % of All 

Units Avg. Age

Avg. Net 

Summer 

Capacity 

(MW)

Total Net 

Summer 

Capacity 

(MW)

% Total 

Capacity

Avg. Heat 

Rate 

(Btu/kWh)

0 to 25 193 15% 45 15 2,849 1% 11,154

>25 to 49 108 9% 42 38 4,081 1% 11,722

50 to 99 162 13% 47 75 12,132 4% 11,328

100 to 149 269 21% 49 141 38,051 12% 10,641

150 to 249 81 6% 43 224 18,184 6% 10,303

250 and up 453 36% 34 532 241,184 76% 10,193

Totals 1,266 316,480

Source: National Electric Energy Data System (NEEDS) v.4.10

Note: The average heat rate reported is the mean of the heat rate of the units in each size category (as opposed 

to a generation-weighted or capacity-weighted average heat rate.) A lower heat rate indicates a higher 

level of fuel efficiency. Table is limited to coal-steam units online in 2010 or earlier, and excludes those 

units with planned retirements.

4.2.2 Transmission

Transmission is the term used to describe the movement of electricity over a network of 

high voltage lines, from electric generators to substations where power is stepped down for 

local distribution. In the U.S. and Canada, there are three separate interconnected networks of 

high voltage transmission lines,

1 each operating at a common frequencysynchronously. Within 

each of these transmission networks, there are multiple areas where the operation of power 

plants is monitored and controlled to ensure that electricity generation and load are kept in 

balance. In some areas, the operation of the transmission system is under the control of a 

single regional operator; in others, individual utilities coordinate the operations of their 

 1

These three network interconnections are the western US and Canada, corresponding approximately to the area 

west of the Rocky Mountains; eastern US and Canada, not including most of Texas; and a third network 

operating in most of Texas. These are commonly referred to as the Western Interconnect Region, Eastern 

Interconnect Region, and ERCOT, respectively.
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generation, transmission, and distribution systems to balance their common generation and 

load needs.

Figure 4-1. Fossil Fuel-Fired Electricity Generating Facilities, by Size

Source: National Electric Energy Data System (NEEDS) 4.10 

Note: This map displays facilities in the NEEDS 4.10 IPM frame. NEEDS reflects available capacity on-line by the 

end of 2011. This includes planned new builds and planned retirements. In areas with a dense 

concentration of facilities, some facilities may be obscured.

4.2.3 Distribution

Distribution of electricity involves networks of lower voltage lines and substations that 

take the higher voltage power from the transmission system and step it down to lower voltage 

levels to match the needs of customers. The transmission and distribution system is the classic 

example of a natural monopoly, in part because it is not practical to have more than one set of 

lines running from the electricity generating sources to substations or from substations to 

residences and businesses.
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Transmission has generally been developed by the larger vertically integrated utilities 

that typically operate generation and distribution networks. Often distribution is handled by a 

large number of utilities that purchase and sell electricity, but do not generate it. Over the last 

couple of decades, several jurisdictions in the United States began restructuring the power 

industry to separate transmission and distribution from generation, ownership, and operation.

As discussed below, electricity restructuring has focused primarily on efforts to reorganize the 

industry to encourage competition in the generation segment of the industry, including 

ensuring open access of generation to the transmission and distribution services needed to 

deliver power to consumers. In many states, such efforts have also included separating 

generation assets from transmission and distribution assets to form distinct economic entities.

Transmission and distribution remain price-regulated throughout the country based on the cost 

of service.

4.3 Deregulation and Restructuring

The process of restructuring and deregulation of wholesale and retail electric markets 

has changed the structure of the electric power industry. In addition to reorganizing asset 

management between companies, restructuring sought a functional unbundling of the 

generation, transmission, distribution, and ancillary services the power sector has historically 

provided, with the aim of enhancing competition in the generation segment of the industry.

Beginning in the 1970s, government policy shifted against traditional regulatory 

approaches and in favor of deregulation for many important industries, including 

transportation (notably commercial airlines), communications, and energy, which were all 

thought to be natural monopolies (prior to 1970) that warranted governmental control of 

pricing. However, deregulation efforts in the power sector were most active during the 1990s.

Some of the primary drivers for deregulation of electric power included the desire for more 

efficient investment choices, the economic incentive to provide least-cost electric rates through 

market competition, reduced costs of combustion turbine technology that opened the door for 

more companies to sell power with smaller investments, and complexity of monitoring utilities’ 

cost of service and establishing cost-based rates for various customer classes.

The pace of restructuring in the electric power industry slowed significantly in response 

to market volatility in California and financial turmoil associated with bankruptcy filings of key 
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energy companies. By the end of 2001, restructuring had either been delayed or suspended in 

eight states that previously enacted legislation or issued regulatory orders for its 

implementation (shown as “Suspended” in Figure 4-2 below). Eighteen other states that had 

seriously explored the possibility of deregulation in 2000 reported no legislative or regulatory 

activity in 2001 (EIA, 2003) (“Not Active” in Figure 4-2 below). Currently, there are 15 states 

where price deregulation of generation (restructuring) has occurred (“Active” in Figure 4-2 

below). Power sector restructuring is more or less at a standstill; there have been no recent 

proposals to the Federal Energy Regulatory Commission (FERC) for actions aimed at wider 

restructuring, and no additional states have recently begun retail deregulation activity.

Figure 4-2. Status of State Electricity Industry Restructuring Activities

Source: EIA 2010b. 

4.4 Emissions of Greenhouse Gases from Electric Utilities

The burning of fossil fuels, which generates about 70 percent of our electricity 

nationwide, results in emissions of greenhouse gases. The power sector is a major contributor 

of CO2 in particular, but also contributes to emissions of sulfur hexafluoride (SF6), CH4, and N2O.

In 2011, the power sector accounted for 33 percent of total nationwide greenhouse gas

emissions, measured in CO2 equivalent, a slight increase from its 30 percent share in 1990.
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Table 4-5 and Figure 4-3 show the contributions of the power sector relative to other major 

economic sectors. Table 4-6 and Figure 4-4 show the contributions of CO2 and other GHGs from 

the power sector.
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Table 4-5. Domestic Emissions of Greenhouse Gases, by Economic Sector (million metric 

tonnes of CO2 equivalent)

Sector/Source 1990 1995 2000 2005 2011

Electricity Generation 1,866 1,992 2,336 2,446 2,201

Transportation 1,553 1,697 1,927 2,012 1,829

Industry 1,539 1,558 1,504 1,416 1,332

Agriculture 458 511 501 517 547

Commercial 388 391 376 374 378

Residential 345 367 386 371 357

U.S. Territories 34 41 46 58 58

Total Emissions 6,183 6,557 7,076 7,195 6,702

Source: EPA 2013

Figure 4-3. Domestic Emissions of Greenhouse Gases, 2011 (million metric tonnes of CO2

equivalent)

Source: EPA 2013

Other

4,501

67%

Electricity 

Generation

2,201

33%
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Table 4-6. Greenhouse Gas Emissions from the Electricity Sector (Generation, Transmission 

and Distribution), 2011 (million metric tonnes of CO2 equivalent)

Source Total Emissions

CO2 2,175.5

CO2 from Fossil Fuel Combustion 2,158.5

Coal 1,722.7

Natural Gas 408.8

Petroleum 26.6

Geothermal 0.4

Incineration of Waste 12.4

Other Process Uses of Carbonates 4.6

CH4 0.4

Stationary Combustion* 0.4

Incineration of Waste +

N2O 18.3

Stationary Combustion* 17.9

Incineration of Waste 0.4

SF6

** 7.0

Electrical Transmission and Distribution 7.0

Total 2,201.2

Source: EPA 2013

* Includes only stationary combustion emissions related to the generation of electricity.

** SF6 is not covered by this rule, which specifically regulates GHG emissions from combustion.

+ Does not exceed 0.05 Tg CO2 Eq. or 0.05 percent.

The amount of CO2 emitted during the combustion of fossil fuels varies according to the 

carbon content and heating value of the fuel used (EIA, 2000) (see Table 4-7). Coal has higher 

carbon content than oil or natural gas and, thus, releases more CO2 during combustion. Coal 

emits around 1.7 times as much carbon per unit of energy when burned as does natural gas and 

1.25 times as much as oil (EPA 2011).
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Figure 4-4. GHG Emissions from the Power Sector Relative to Total Domestic GHG Emissions 

(2011)

Source: EPA 2013

Table 4-7. Fossil Fuel Emission Factors in EPA Modeling Applications

Fuel Type Carbon Dioxide (lbs/MMBtu)

Coal 

Bituminous 205.2 – 206.6

Subbituminous 212.7 – 213.1

Lignite 213.5 – 217.0

Natural Gas 117.1

Fuel Oil 

Distillate 161.4

Residual 161.4 – 173.9

Biomass* 195

Waste Fuels 

Waste Coal 205.7

Petroleum Coke 225.1

Fossil Waste 321.1

Non-Fossil Waste 0

Tires 189.5

39%

74%

5% 0.1% 0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

CO2 SF6 N2O CH4

Other

Power Sector
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Municipal Solid Waste 91.9

Source: Documentation for IPM Base Case v.4.10. See also Table 9.9 of IPM Documentation.

Note: CO2 emissions presented here for biomass account for combustion only and do not reflect lifecycle 

emissions from initial photosynthesis (carbon sink) or harvesting activities and transportation (carbon 

source).

4.5 Carbon Dioxide Control Technologies

In the power sector there are currently only a few technical approaches available for 

significantly reducing the CO2 emissions of new fossil fuel combustion sources intended for 

intermediate and baseload operations. These include the use of: CO2 capture and storage (CCS), 

highest efficiency designs (e.g. supercritical or ultrasupercritical steam units, integrated 

gasification combined-cycle units (IGCC), or combined-cycle combustion-turbine/steam-turbine 

units), and/or low-emitting fuels (e.g. natural gas rather than coal). CCS technologies can be 

applied with any new combustion source to reduce its uncontrolled CO2 emission by as much as 

90 percent (“full capture”), or by some lesser percentage (“partial capture”).

Daily peak electricity demands, involving operation for relatively few hours per year, are 

often most economically met by simple-cycle combustion turbines (CT). Stationary CTs s used 

for power generation can be installed quickly, at relatively low capital cost. They can be 

remotely started and loaded quickly, and can follow rapid demand changes. Full-load 

efficiencies of large current technology CTs are 30-33 percent (high heating value basis), as 

compared to efficiencies of 50 percent or more for new combined-cycle units that recover and 

use the exhaust heat otherwise wasted from a CT . A simple-cycle CT’s lower efficiency causes 

it to burn much more fuel to produce a MWh of electricity than a combined-cycle unit. Thus, 

when burning natural gas its CO2 emission rate per MWh could be 40-60 percent higher than a 

more efficient NGCC unit.

Baseload electricity demand can be met with NGCC generation, coal and other fossilfired steam generation, and as well as IGCC technology. IGCC employs the use of a “gasifier” to 

transform fossil fuels into synthesis gas (“syngas”) and heat. The syngas is used to fuel a 

combined cycle generator, and the heat from the syngas conversion can produce steam for the 

steam turbine portion of the combined cycle generator. Electricity can be generated through 

this IGCC process somewhat more efficiently than through conventional boiler-steam 

Comment [A1]: Suggest to add for 

clarity.

Comment [A2]: It would be helpful to 

clarify there are other non-fossil and nonGHG emitting baseload technologies that 

are employed (e.g., hydro, nuclear) or 

may be developed in the future (e.g., 

renewable baseload technologies), to 

provide a full picture of the technology 

mix beyond fossil fuel technologies.

Comment [A3]: Delete
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generators. Additionally, with gasification, some of the syngas can be converted into other 

marketable products such as fertilizer, and CO2 can be captured for use in EOR. 

4.5.1 Carbon Capture and Storage (CCS).

Carbon capture technology has been successfully applied since 1930 on several smaller 

scale industrial facilities and is currently in the demonstration phase for power sector 

applications. There are currently larger-scale projects under construction or in the advanced 

planning stages. CCS can be achieved through either pre-combustion or post-combustion 

capture of CO2 from a gas stream associated with the fuel combusted. Furthermore, CCS can be 

designed and operated for full capture of the CO2 in the gas stream (i.e., above 90 percent) or 

for partial capture (below 90 percent).the amount of CO2 captured from the gas stream can 

vary from upwards of 90 percent (full capture) to less than 90 percent (partial capture).

For post-combustion capture, CO2 is stripped from the flue gas by passing the flue gas 

through a liquid absorbent which selectively reacts with the gaseous carbon dioxide to remove

it from the combustion gas stream. The absorbent, upon saturation, transfers to a downstream 

operation which regenerates the absorbent by desorbing the CO2 back to gaseous form. The 

absorbent recycles back into the process to repeat the capture cycle while the removed carbon 

dioxide is compressed, sent to storage and sequestered. This process is illustrated for a 

pulverized coal power plant in Figure 4-5. For post-combustion, a station's net generating 

output could be 20-30 percent lower due to the energy needs of the capture process.
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Source: Interagency Task Force on Carbon Capture and Storage 2010

Pre-combustion capture is mainly applicable to IGCC facilities, where the fuel is 

converted into gaseous components (“syngas”) under heat and pressure and some percentage 

of the carbon contained in the syngas is captured before combustion. For pre-combustion 

technology, a significant amount of energy is needed to gasify the fuel(s). This process is 

illustrated in Figure 4-6. Application of post-combustion CCS with IGCC can be designed to use 

no water-gas shift, or single- or two-stage shift processes, to obtain varying percentages of CO2

removal – from a “partial capture” percentage to 90 percent “full capture.” Pre-combustion CCS 

typically has a lesser impact on net energy output than does post-combustion CCS. For more 

detail on the current state of CCS technology, see the “Report of the Interagency Task Force on 

Carbon Capture and Storage” (2010).

Figure 4-5. Post-Combustion CO2 Capture for a Pulverized Coal Power Plant
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Source: Interagency Task Force on Carbon Capture and Storage 2010

Figure 4-6. Pre-Combustion CO2 Capture for an IGCC Power Plant
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4.6 Geologic Sequestration

4.6.1 Availability of Geologic Sequestration

Geologic storage potential for CO2 is widespread and available throughout the U.S. and 

Canada. Geologic formations suitable for sequestration include depleted oil and gas fields, 

deep coal seams, and saline formations. The Department of Energy’s (DOE) National Energy 

Technology Laboratory (NETL) estimates the current total CO2 storage resource is 

approximately 2,380 to 20,353 billion metric tons (2,625 to 22,435 billion tons) in the U.S. and 

Canada. 2 DOE’s estimates are intended to be used as an initial assessment of potential geologic 

storage. Other types of geologic formations such as organic rich shale and basalt may have the 

ability to store CO2, and DOE is currently evaluating their potential future storage capacity. 

Potential sequestration sites must undergo appropriate site characterization to ensure that the 

site can safely and securely store CO2. Estimates of CO2 storage resources by state/province 

from the DOE report are provided in Table 4-89. These state and province level estimates are 

obtained from DOE’s National Carbon Sequestration Database and Geographic Information 

System (NATCARB). Nearly every state in the U.S. has or is in close proximity to carbon storage 

potential including vast areas offshore. Information and methods used in estimating CO2

storage resource can be found in the “Methodology for Development of Geologic Storage 

Estimates for Carbon Dioxide” in Appendix B of the Carbon Utilization and Storage Atlas3 (NETL 

2012). It should be noted that the assessment of U.S. sequestration potential is an ongoing 

process. There is significant uncertainty in areas such as the Atlantic offshore due to a relative 

paucity of data and other factors.

In addition, the Department of Interior’s U.S. Geological Survey (USGS) recently 

completed an evaluation of the technically accessible storage resource for carbon storage for 

36 sedimentary basins in the onshore areas and State waters of the United States.4 The USGS 

assessment estimates a mean of 3000 billion metric tons of CO2 storage potential across the 

 2 The United States 2012 Carbon Utilization and Storage Atlas, Fourth Edition, U.S Department of Energy, Office of 

Fossil Energy, National Energy Technology Laboratory (NETL). 3 The United States 2012 Carbon Utilization and Storage Atlas, Fourth Edition, U.S Department of Energy, Office of 

Fossil Energy, National Energy Technology Laboratory (NETL). 4 U.S. Geological Survey Geologic Carbon Dioxide Storage Resources Assessment Team, 2013, National assessment 

of geologic carbon dioxide storage resources – Summary: U.S. Geological Survey Factsheet 2013-3020, 

6p.http://pubs.usgs.gov/fs/2013/3020/.

Comment [A4]: In addition to the 

differences between the DOE NETL 

assessment and USGS assessment 

described below, it would also be helpful 

to know whether the range of the NETL 

estimates reflect only technically 

accessible potential, or economic 

potential, or a combination. 
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United States. For comparison, this amount is 500 times the 2011 annual U.S. energy-related 

CO2 emissions of 5.5 Gigatons (Gt)5 Areas that were assessed by the USGS for CO2 storage 

compliment and are not identical to the areas assessed by DOE, NATCARB. The USGS 

assessment provides further evidence of the widespread availability CO2 storage reserves in the 

U.S. based on the comprehensive evaluation of the technically accessible storage resource for 

carbon storage for 36 sedimentary basins in the onshore areas and State waters of the United 

States.6

Table 4-8.9 Total CO2 Storage Resource7

Million Metric Tons*

State/Province Low Estimate High Estimate

ALABAMA 122,490 694,380 

ALASKA 8,640 19,750 

ALBERTA 41,840 131,230 

ARIZONA 130 1,170 

ARKANSAS 6,180 63,670 

BRITISH COLUMBIA 910 3,860 

CALIFORNIA 33,890 420,630 

COLORADO 37,610 357,190 

CONNECTICUT

DELAWARE 40 40 

DISTRICT OF COLUMBIA

FLORIDA 102,740 555,010 

GEORGIA 145,340 159,050 

HAWAII

IDAHO 40 390 

ILLINOIS 10,020 116,820 

INDIANA 32,020 68,210 

IOWA 10 50 

 5 U.S. Energy Information Administration, 2012

6 U.S. Geological Survey Geologic Carbon Dioxide Storage Resources Assessment Team, 2013, National assessment 

of geologic carbon dioxide storage resources – Summary: U.S. Geological Survey Factsheet 2013-3020, 

6p.http://pubs.usgs.gov/fs/2013/3020/. 7 The United States 2012 Carbon Utilization and Storage Atlas, Fourth Edition, U.S Department of Energy, Office of 

Fossil Energy, National Energy Technology Laboratory (NETL).

Comment [A5]: Comments:

1)It would be helpful to provide the 

range of USGS assessment, to compare 

with the DOE NETL estimates above;

2)It would be useful to point out the 

assessment does not evaluate the 

economically feasible storage potential. 
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KANSAS 10,880 86,340 

KENTUCKY 2,920 7,650 

LOUISIANA 169,500 2,103,980 

MAINE

MANITOBA 1,720 3,520 

MARYLAND 1,860 1,930 

MASSACHUSETTS

MICHIGAN 19,050 47,210 

MINNESOTA

MISSISSIPPI 145,010 1,185,030 

MISSOURI 10 170 

MONTANA 84,580 912,720 

NEBRASKA 23,770 113,240 

NEVADA

New Brunswick

NEW HAMPSHIRE

NEW JERSEY 0 0

NEW MEXICO 42,760 359,090 

NEW YORK 4,640 4,640 

Newfoundland & 

Labrador

NORTH CAROLINA 1,340 18,390 

NORTH DAKOTA 67,090 147,480 

Northwest Territories

Nova Scotia

Offshore Federal Only 489,840 6,440,090 

OHIO 13,460 13,460 

OKLAHOMA 56,950 244,550 

Ontario

OREGON 6,810 93,700 

PENNSYLVANIA 22,100 22,100 

PUERTO RICO

Quebec

RHODE ISLAND

SASKATCHEWAN 38,690 121,910 

SOUTH CAROLINA 30,100 34,180 

SOUTH DAKOTA 8,760 24,030 

TENNESSEE 430 3,860 

TEXAS 443,800 4,329,930 

UTAH 25,470 240,910 
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VERMONT

VIRGINIA 440 2,910 

WASHINGTON 36,620 496,730 

WEST VIRGINIA 16,650 16,650 

WISCONSIN 0 0

WYOMING 72,690 684,850 

North America Total 2,379,840 20,352,700 

*States/Provinces with a “zero” value represent estimates of minimal CO2 storage resource, while states/provinces 

with a blank represent areas that have not yet been assessed by the RCSPs.

4.6.2 Enhanced Oil and Gas Recovery in the U.S.

Geologic storage options also include use of CO2 in enhanced oil recovery. Enhanced 

recovery (ER), which includes both enhanced oil and gas recovery (EOR and EGR), refers to the 

injection of fluids into a reservoir to increase oil and/or gas production efficiency. ER is typically 

conducted at a reservoir after production yields have decreased from primary production. 

Fluids commonly used for ER include brine, fresh water, steam, nitrogen, alkali solutions, 

surfactant solutions, polymer solutions, and carbon dioxide. EOR using supercritical carbon 

dioxide, sometimes referred to as carbon dioxide ‘flooding’ or CO2-EOR, involves injecting 

carbon dioxide into an oil reservoir to help mobilize the remaining oil and make it available for 

recovery. The crude oil and CO2 mixture is produced, and sent to a separator where the crude 

oil is separated from the gaseous hydrocarbons and CO2. The gaseous CO2-rich stream then is 

typically dehydrated, purified to remove hydrocarbons, recompressed, and reinjected into the 

oil or natural gas reservoir to further enhance recovery. The DOE’s Regional Carbon 

Sequestration Partnerships (RCSPs) have documented the location of more than 225 billion 

metric tons of CO2 storage potential in oil and gas reservoirs across over 30 states. 8

CO2-EOR has been successfully used at many production fields throughout the U.S. to 

increase oil recovery. The oil and natural gas industry in the United States has over 40 years of 

experience of injection and monitoring of CO2 in the deep subsurface for the purposes of 

enhancing oil and natural gas production. This experience provides a strong foundation for the 

injection and monitoring technologies that will be needed for successful deployment of CCS. 

Although deep saline formations provide the most CO2 storage opportunity (2,102 to 20,043 

 8 The United States 2012 Carbon Utilization and Storage Atlas, Fourth Edition, U.S Department of Energy, Office of 

Fossil Energy, National Energy Technology Laboratory (NETL).
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billion metric tons), oil and gas reservoirs are currently estimated to have 226 billion metric 

tons of CO2 storage resource.9

 EPA anticipates that many early geologic sequestration (GS) 

projects may be sited in active or depleted oil and gas reservoirs because these formations have 

been previously well characterized for hydrocarbon recovery, likely already have suitable 

infrastructure (e.g., wells, pipelines, etc.), and may be suitable for long term containment of 

CO2. 

4.6.3 Trends in CO2-EOR

Carbon dioxide EOR (CO2-EOR) is the fastest-growing EOR technique in the U.S., providing 

approximately 281,000 barrels of oil per day in the U.S. which equals about 6% percent of U.S. 

crude oil production.10,11 The vast majority of CO2-EOR is conducted in oil reservoirs in the U.S. 

Permian Basin, which extends through southwest Texas and southeast New Mexico. Other U.S. 

states where CO2- EOR is utilized are Alabama, Colorado, Illinois, Kansas, Louisiana, Michigan, 

Mississippi, New Mexico, Oklahoma, Utah, and Wyoming. A well-established and expanding 

network of pipeline infrastructure supports CO2-EOR in these areas (Figure 4-89). The CO2

supply for EOR operations is largely obtained from underground formations or domes that 

contain CO2. While natural sources of CO2 comprise the majority of CO2 supplied for EOR 

operations, recent developments targeting anthropogenic sources of CO2 (e.g., ethanol plants, 

gas processing, refineries, power plants) have expanded or led to planned expansions in 

existing infrastructure related to CO2-EOR.12 Several hundred miles of dedicated CO2 pipeline is 

under construction, planned, or proposed that would allow continued growth in CO2 supply for 

EOR (see Figure 4-89). 

Anthropogenic sources of CO2 for EOR continue to increase as new projects are being 

planned or implemented. Based on an evaluation of publicly available sources13, there are 

 9 U.S. Department of Energy National Energy Technology Laboratory (2012). United States Carbon Utilization and 

Storage Atlas, Fourth Edition. 10 Oil and Gas Journal EOR Survey, April 2010. 11 Improving Domestic Energy Security and Lowering CO2 Emissions with “Next Generation” CO2-Enhanced Oil 

Recovery (CO2-EOR)”, DOE/NETL-2011/1504, June 20, 2011 12 Improving Domestic Energy Security and Lowering CO2 Emissions with “Next Generation” CO2-Enhanced Oil 

Recovery (CO2-EOR)”, DOE/NETL-2011/1504, June 20, 2011 13 See technical supporting memo document (Docket EPA-HQ-OAR-2013-XXXXEPA-HQ-OAR-2013-0495) 

Documentation for the Summary of Carbon Dioxide Industrial Capture to Enhanced Oil Recovery Projectsfor 

sources of industrial source CCS projects.
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currently twenty-two three (223) industrial source CCS projects in twelve (12) states that are 

either operational, under-construction, or actively being pursued which are or will supply 

captured CO2 for the purposes of EOR. This demonstrates that CCS projects associated with 

large point sources are occurring due to a demand for CO2 by EOR operations. Nationally, 

according to EPA’s Greenhouse Gas Reporting Program, over 64 million metric tons of CO2 was 

received for injection to enhanced oil recovery operations in 2011. A recent study by DOE 

found that the market for captured CO2 emissions from power plants created by economically 

feasible CO2-EOR projects would be sufficient to permanently store the CO2 emissions from 93 

large (1,000 MW) coal-fired power plants operated for 30 years.14 There are also several state 

and Federal subsidy programs that are in place that can make CCS more affordable.15 Based on 

all of these factors, EPA anticipates opportunities to utilize CO2-EOR operations for geologic 

storage to continue to increase. 

Based on a recent resource assessment by DOE, the application of next generation CO2-

EOR technologies would significantly increase oil production areas, further expanding the 

geographic extent and accessibility of CO2-EOR operations in the U.S. 16 Additionally, oil and gas 

fields now considered to be ‘depleted’ may resume operation because of increased availability 

and decreased cost of anthropogenic carbon dioxide, thereby increasing the demand for and 

accessibility of CO2 utilization. 

As demonstrated in this RIA, the use of CO2 for EOR can significantly lower the cost of 

implementing CCS. The opportunity to sell the captured CO2 for EOR, rather than paying directly 

for its long-term storage, strongly improves the overall economics of the new generating unit. A 

commercial market for CO2 creates a role for CO2-EOR to continue CCS deployment. According 

to the International Energy Agency, of the CCS projects under construction or at an advanced 

stage of planning, 70% intend to use captured CO2 to improve recovery of oil in mature fields 

(enhanced oil recovery, CO2-EOR). 17 Further, smaller, non-geologic sequestration markets exist 

for CO2 as well, including food products, which can lower the cost of CCS.

 14 Improving Domestic Energy Security and Lowering CO2 Emissions with “Next Generation” CO2-Enhanced Oil 

Recovery (CO2-EOR)”, DOE/NETL-2011/1504, June 20, 2011 15 Report of the Interagency Task Force on Carbon Capture and Storage (August 2010). 16 Improving Domestic Energy Security and Lowering CO2 Emissions with “Next Generation” CO2-Enhanced Oil 

Recovery (CO2-EOR)”, DOE/NETL-2011/1504, June 20, 2011 17 Tracking Clean Energy Progress 2013, International Energy Agency (IEA), Input to the Clean Energy Ministerial, 

OECD/IEA 2013. 
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Figure 4-7.8: Growth of U.S. Oil Production from CO2-based EOR

Source: NETL 2010

Figure 4-9: U.S. CO2 Storage Capacity and CO2-EOR operations 
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Figure 4-8.9: U.S. CO2 Storage Capacity and CO2-EOR operations 

Source: EPA 2013: Data sources: EPA’s Greenhouse Gas Reporting Program; Department of Energy, NATCARB; 

Department of Transportation, National Pipeline Management System.

4.6.4 Alternatives to Geologic Sequestration 

EPA recognizes there may be other commercial applications or end-uses for captured 

CO2 which creates CO2 market incentives and potentially for a meeting performance standard 

beyond injecting it underground for long-term containment. For example, alternatives to 

geologic sequestration such as applications such as mineralization of CO2 for the production of 

precipitated calcium carbonate and some production process of cement have been identified as 

potential alternatives to geologic sequestration. The Carbon Capture and Storage (CCS) Task 

Force report notes that there are several factors for determining the viability of CO2 reuse, and 

there are currently significant technical barriers to large scale commercial-scale reuse. First, 

rates of conversion must be comparable to rates of CO2 capture. Second, energy requirements 

for conversion must be low. Third, potential volumes of reactants and/or products may limit 

the scale of reuse relative to total emissions. Finally, reuse options need to consider the longterm fate of CO2 and its lifecycle emissions.18 The CCS Task Force also notes there are other 

potential commercial uses for captured CO2, such as in food and beverage manufacturing, pulp 

and paper manufacturing, the rubber and plastic industry, fire suppression, and refrigeration 

and cooling.

As noted in the preamble, however, EPA has not yet determined if such uses would be 

applicable towards meeting the standard. Consideration of how these alternatives could meet 

the performance standard involves understanding the ultimate fate of the captured CO2 and 

the degree to which the method permanently isolates the CO2 from the atmosphere, as well as 

existing methodologies to verify this permanent storage.

 18 Report of the Interagency Task Force on Carbon Capture and Storage (August 2010).
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4.7 GHG and Clean Energy Regulation in the Power Sector

4.7.1 State Policies

Several states have also recently established emission performance standards or other 

measures to limit emissions of GHGs from new EGUs that are comparable to this proposal in 

this rulemaking. 

In 2003, then-Governor George Pataki sent a letter to his counterparts in the Northeast 

and Mid-Atlantic inviting themn to participate in the development of a regional cap-and-trade 

program addressing power plant CO2 emissions. This program, known as the Regional 

Greenhouse Gas Initiative (RGGI), began in 2009 and sets a regional CO2 cap for participating 

states. The currently participating states include: Connecticut, Delaware, Maine, Maryland, 

Massachusetts, New Hampshire, New York, Rhode Island, and Vermont. The cap covers CO2

emissions from all fossil-fired EGUs greater than 25 MW in participating states, and limits total 

emissions to 91 million short tons in 2014. This emissions budget is reduced 2.5% annually in 

from 2015 to 2020.

In September 2006, California Governor Schwarzenegger signed into law Senate Bill 

1368. The law limits long-term investments in baseload generation by the state's utilities to 

power plants that meet an emissions performance standard jointly established by the California 

Energy Commission and the California Public Utilities Commission. The Energy Commission has 

designed regulations that establish a standard for new and existing baseload generation owned 

by, or under long-term contract to publicly owned utilities, of 1,100 lb CO2/MWh.

In 2006 Governor Schwarzenagger also signed into law Assembly Bill 32, the Global 

Warming Solutions Act of 2006. This act includes a multi-sector GHG cap-and-trade program 

which covers approximately 85% of the state GHG emissions. EGUs are includes in phase I of 

the program, which began in 2013. Phase II begins in 2020 and includes upstream sources. The 

cap is based on a 2 percent reduction from total 2012 expected emissions, and declines 2 

percent annually through 2014, then 3 percent each year until 2020. 

In May 2007, Washington Governor Gregoire signed Substitute Senate Bill 6001, which 

established statewide GHG emissions reduction goals, and imposed an emission standard that 

applies to any baseload electric generation that commenced operation after June 1, 2008 and is 

located in Washington, whether or not that generation serves load located within the state. 
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Baseload generation facilities must initially comply with an emission limit of 1,100 lb CO2/MWh.

In July 2009, Oregon Governor Kulongoski signed Senate Bill 101, which mandated that 

facilities generating baseload electricity, whether gas- or coal-fired, must have emissions equal 

to or less than 1,100 lb CO2/MWh, and prohibited utilities from entering into long-term 

purchase agreements for baseload electricity with out-of-state facilities that do not meet that 

standard. Natural gas- and petroleum distillate-fired facilities that are primarily used to serve 

peak demand or to integrate energy from renewable resources are specifically exempted from 

the performance standard.

In August 2011, New York Governor Cuomo signed the Power NY Act of 2011. This 

regulation establishes CO2 emission standards for new and modified electric generators greater 

than 25 MW. The standards vary based on the type of facility: baseload facilities must meet a 

CO2 standard of 925 lb/MWh or 120 lb/MMBtu, and peaking facilities must meet a CO2

standard of 1,450 lbs/MWh or 160 lbs/MMBtu.

Additionally, most states have implemented Renewable Portfolio Standards (RPS), or 

Renewable Electricity Standards (RES). These programs are designed to increase the renewable 

share of a state’s total electricity generation. Currently 30 states and the District of Columbia 

have enforceable RPS or other mandatory renewable capacity policies, and 7 states have 

voluntary goals.19 These programs vary widely in structure, enforcement, and scope. 

4.7.2 Federal Policies

In April 2007, the Supreme Court concluded that GHGs met the CAA definition of an air 

pollutant, giving the EPA the authority to regulate GHGs under the CAA contingent upon an

agency determination that GHG emissions from new motor vehicles cause or contribute to air 

pollution that may reasonably be anticipated to endanger public health or welfare. This 

decision to regulate GHG emissions for motor vehicles set the stage for the determination of 

whether other sources of GHG emissions, including stationary sources, would need to be 

regulated as well.

In response to the FY2008 Consolidated Appropriations Act (H.R. 2764; Public Law 110–

161), the EPA issued the Mandatory Reporting of Greenhouse Gases Rule (74 FR 5620) which 

 19 EIA 2012a
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required reporting of GHG data and other relevant information from fossil fuel suppliers and 

industrial gas suppliers, direct greenhouse gas emitters, and manufacturers of heavy-duty and 

off-road vehicles and engines. The purpose of the rule was to collect accurate and timely GHG 

data to inform future policy decisions. As such, it did not require that sources control 

greenhouse gases, but sources above certain threshold levels must monitor and report 

emissions.

In August 2007, the EPA issued a prevention of significant deterioration (PSD) permit to 

Deseret Power Electric Cooperative, authorizing it to construct a new waste-coal-fired EGU near 

its existing Bonanza Power Plant, in Bonanza, Utah. The permit did not include emissions 

control requirements for CO2. The EPA acknowledged the Supreme Court decision, but found 

that decision alone did not require PSD permits to include limits on CO2 emissions. Sierra Club 

challenged the Deseret permit. In November 2008, the Environmental Appeals Board (EAB) 

remanded the permit to the EPA to reconsider “whether or not to impose a CO2 BACT limit in 

light of the ‘subject to regulation’ definition under the CAA.” The remand was based in part on 

EAB’s finding that there was not an established EPA interpretation of the regulatory phrase 

“subject to regulation.” 

In December 2008, the Administrator issued a memo indicating that the PSD Permitting 

Program would apply to pollutants that are subject to either a provision in the CAA or a 

regulation adopted by the EPA under the CAA that requires actual control of emissions of that 

pollutant. The memo further explained that pollutants for which the EPA regulations only 

require monitoring or reporting, such as the provisions for CO2 in the Acid Rain Program, are 

not subject to PSD permitting. Fifteen organizations petitioned the EPA for reconsideration, 

prompting the agency to issue a revised finding in March 2009. After reviewing comments, the 

EPA affirmed the position that PSD permitting is not triggered for a pollutant such as GHGs until 

a final nationwide rule requires actual control of emissions of the pollutant. For GHGs, this 

meant January 2011 when the first national rule limiting GHG emissions for cars and light trucks 

was scheduled to take effect. Therefore, a permit issued after January 2, 2011, would have to 

address GHG emissions.

The Administrator signed two distinct findings in December 2009 regarding greenhouse 

gases under section 202(a) of the Clean Air Act. The endangerment finding indicated that 
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current and projected concentrations of the six key well-mixed greenhouse gases —CO2, CH4, 

N2O, hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and SF6 — in the atmosphere 

threaten the public health and welfare of current and future generations. These greenhouse 

gases have long lifetimes and, as a result, become homogeneously distributed through the 

lower level of the Earth’s atmosphere (IPCC, 2001). This differentiates them from other 

greenhouse gases that are not homogeneously distributed in the atmosphere. The cause and 

contribute finding indicated that the combined emissions of these well-mixed greenhouse gases 

from new motor vehicles and new motor vehicle engines contribute to the greenhouse gas 

pollution which threatens public health and welfare. Both findings were published in the 

Federal Register on December 15, 2009 (Docket ID EPA-HQ-OAR-2009-0171). These findings did 

not themselves impose any requirements on any industry or other entities, but allowed the EPA

to regulate greenhouse gases under the CAA (see preamble section II.E for regulatory 

background). This action was a prerequisite to implementing the EPA's proposed greenhouse 

gas emission standards for light-duty vehicles, which was finalized in January 2010. Once a 

pollutant is regulated under the CAA, it is subject to permitting requirements under the PSD 

and Title V programs. The 2009 Endangerment Finding and a denial of a reconsideration were 

challenged in a lawsuit; on June 26, 2012, the DC Circuit Court upheld the Endangerment 

Finding and the Reconsideration Denial, ruling that the Finding was neither arbitrary nor 

capricious, was consistent with Massachusetts v. EPA, and was adequately supported by the 

administrative record. The Court found that the EPA had based its decision on “substantial 

scientific evidence,” noted that the EPA’s reliance on assessments was consistent with the 

methods decision-makers often use to make a science-based judgment, and stated that “EPA’s 

interpretation of the governing CAA provisions is unambiguously correct.”

In May 2010, the EPA issued the final Tailoring Rule which set thresholds for GHG 

emissions that define when permits under the New Source Review and Title V Operating Permit 

programs are required for new and existing industrial facilities. Facilities responsible for nearly 

70 percent of the national GHG emissions from stationary sources, including EGUs, were 

subject to permitting requirements under the rule. This rule was upheld by the D.C. Circuit in 

2012.

The EPA entered into two proposed settlement agreements in December 2010 to issue 

rules that will address greenhouse gas emissions from fossil fuel-fired power plants and 
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refineries. These two industrial sectors make up nearly 40 percent of the nation’s greenhouse 

gas emissions. On March 27, 2012, EPA proposed NSPS for new source natural gas, coal, and 

other solid fossil-fired EGUs . After consideration of information provided in more than 2.5 7 

million comments on this proposal, as well as consideration of continuing changes in the 

electricity sector, the EPA determined that revisions in its proposed approach are warranted. 

This rule replaces that proposal. Existing source standards are not addressed in this action.

Details of the settlement agreements can be found on the EPA website.20

4.7.3. Proposed Federal Policies, Non-GHG

EPA is reviewing public comment and developing final regulations for the following

three proposed rules, which will impact EGUs: Steam Electric Effluent Limitation Guidelines, 

Cooling Water Intake Structures, and Coal Combustion Residuals (CCR). These three proposed 

rules are summarized below. In general, most EPA rulemakings affecting the power sector 

focus on existing sources. Therefore, few interactions are likely between other power sector 

rules and this rule, which focuses only on new sources.

On Friday, June 7th, 2013, EPA proposed a regulation that would strengthen the 

controls on discharges from certain steam electric power plants by revising technology-based 

effluent limitations guidelines and standards for the steam electric power generating point 

source category. Existing steam electric power plants contribute 50-60 percent of all toxic 

pollutants discharged to surface waters by all industrial categories currently regulated in the 

United States under the Clean Water Act. Furthermore, power plant discharges to surface 

waters are expected to increase as pollutants are increasingly captured by air pollution controls 

and transferred to wastewater discharges. This proposal would reduce the amount of toxic 

metals and other pollutants discharged to surface waters from power plants. EPA has proposed 

new requirements for both existing and new generating units. EPA estimates that the 

compliance costs for a new unit (capital and O&M) under the proposed standards represent at 

most 1.5 percent of the annualized cost of building and operating a new 1,300 MW coal-fired 

plant, with capital costs representing less than 1 percent of the overnight construction costs, 

and annual O&M costs representing less than 5 percent of the cost of operating a new plant. 

 20 http://www.epa.gov/airquality/ghgsettlement.html
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 Section 316(b) of the CWA, 33 U.S.C. 1326(b), requires that standards applicable to 

point sources under sections 301 and 306 of the Act require that the location, design, 

construction, and capacity of cooling water intake structures reflect the best technology 

available to minimize adverse environmental impacts. In April 2011, EPA proposed new 

standards to reduce injury and death of fish and other aquatic life caused by cooling water 

intake structures at existing power plants and manufacturing facilities. The proposed rule would 

subject existing power plants and manufacturing facilities withdrawing in excess of 2 million of 

gallons per day (MGD) of cooling water to an upper limit on the number of fish destroyed 

through impingement, as well as site-specific entrainment mortality standards. Certain plants 

that withdraw very large volumes of water would also be required to conduct studies for use by 

the permit writer in determining site-specific entrainment controls for such facilities. Finally, 

under the proposed rule, new generating units constructed at existing power plants would be 

required to reduce the intake of cooling water associated with the new unit, to a level that 

could be attained by using a closed-cycle cooling system. EPA is continuing the process of 

addressing comments and finalizing the rule.

 On June 21, 2010, EPA co-proposed regulations that included two approaches to 

regulating the disposal of coal combustion residuals (CCRs) generated by electric utilities and 

independent power producers. CCRs are residues from the combustion of coal in steam electric 

power plants and include materials such as coal ash (fly ash and bottom ash) and flue gas 

desulfurization (FGD) wastes. Under one proposed approach, EPA would list these residuals as 

``special wastes,'' when destined for disposal in landfills or surface impoundments, and would 

apply the existing regulatory requirements established under Subtitle C of RCRA to such wastes. 

Under the second proposed approach, EPA would establish new regulations applicable 

specifically to CCRs under subtitle D of RCRA, the section of the statute applicable to solid (i.e., 

non-hazardous) wastes. Under both approaches, CCRs that are beneficially used would remain 

exempt under the Bevill exclusion. While the Agency is still evaluating all the available 

information and comments, and while a final risk assessment for the CCR rule has not yet been 

completed, reliance on the data and analyses discussed in the preamble to the recent Steam 

Electric ELG proposal may have the potential to lower the CCR rule risk assessment results by as 

much as an order of magnitude. If this proves to be the case, EPA’s current thinking is that, the 

revised risks, coupled with the ELG requirements that the Agency may promulgate, and the 
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increased Federal oversight such requirements could achieve, could provide strong support for 

a conclusion that regulation of CCR disposal under RCRA Subtitle D would be adequate.

4.8 Revenues, Expenses, and Prices

Due to lower retail electricity sales, total utility operating revenues declined in 2011 to 

$281 billion from a peak of almost $300 billion in 2008. Despite revenues not returning to 2008 

levels in 2011, operating expenses were appreciably lower and as a result, net income also rose 

in comparison to both 2009 and 2010 (see Table 4-9). Recent economic events have put 

downward pressure on electricity demand, thus dampening electricity prices and consumption 

(utility revenues), but have also reduced the price and cost of fossil fuels and other expenses.

Electricity sales and revenues associated with the generation, transmission, and distribution of 

electricity are expected to rebound and increase modestly by 2015, when revenues are 

projected to be roughly $359 billion (see Table 4-10).

Table 4-9 shows that investor-owned utilities (IOUs) earned income of about 11.9

percent compared to total revenues in 2011. Based on EIA's Annual Energy Outlook 2013, Table 

4-10 shows that the power sector is projected to derive revenues of $359 billion in 2015.

Assuming the same income ratio from IOUs (with no income kept by public power), and using 

the same proportion of power sales from public power as observed in 2011, the EPA projects 

that the power sector will expend over $320 billion in 2015 to generate, transmit, and 

distribute electricity to end-use consumers.

Over the past 50 years, real retail electricity prices have ranged from around 7 cents per 

kWh in the early 1970s, to around 11 cents, reached in the early 1980s. Generally, retail 

electricity prices do not change rapidly and do not display the variability of other energy or 

commodity prices, although the frequency at which these prices change varies across different 

types of customers. Retail rate regulation has largely insulated consumers from the rising and 

falling wholesale electricity price signals whose variation in the marketplace on an hourly, daily, 

and seasonal basis is critical for driving lowest-cost matching of supply and demand. In fact, the 

real price of electricity today is lower than it was in the early 1960s and 1980s (see Figure 4-79).
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Figure 4-97. National Average Retail Electricity Price (1960 – 2011)

Source: EIA 2013

Table 4-98. Revenue and Expense Statistics for Major U.S. Investor-Owned Electric Utilities 

for 2010 ($millions)

2009 2010 2011

Utility Operating Revenues 276,124 285,512 280,520

Electric Utility 249,303 260,119 255,573

Other Utility 26,822 25,393 24,946

Utility Operating Expenses 244,243 253,022 247,118

Electric Utility 219,544 234,173 228,873

Operation 154,925 166,922 161,460

Production 118,816 128,831 122,520

Cost of Fuel 40,242 44,138 42,779

Purchased Power 67,630 67,284 61,447

Other 10,970 17,409 18,294

Transmission 6,742 6,948 6,876

0

2

4

6

8

10

12

14

1960 1970 1980 1990 2000 2010

cents/KWh (2011$)
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Distribution 3,947 4,007 4,044

Customer Accounts 5,203 5,091 5,180

Customer Service 3,857 4,741 5,311

Sales 178 185 185

Admin. and 

General 15,991 17,120 17,343

Maintenance 14,092 14,957 15,772

Depreciation 20,095 20,951 22,555

Taxes and Other 29,081 31,343 29,086

Other Utility 24,698 18,849 18,245

Net Utility Operating Income 31,881 32,490 33,402

Source: Table 8.3, EIA Electric Power Annual, 2011

Note: This data does not include information for public utilities.

Table 4-109. Projected Revenues by Service Category in 2015 for Public Power and InvestorOwned Utilities (billions)

Generation $207

Transmission $40

Distribution $111

Total $359

Source: EIA 2013

Note: Data are derived by taking either total electricity use (for generation) or sales (transmission and 

distribution) and multiplying by forecasted prices by service category from Table 8 of EIA AEO 2013

(Electricity Supply, Disposition, Prices, and Emissions).
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Figure 4-7. National Average Retail Electricity Price (1960 – 2011)

Source: EIA 2013

On a state-by-state basis, retail electricity prices vary considerably. The Northeast and 

California have average retail prices that can be as much as double those of other states (see 

Figure 4-108).

0

2

4

6

8

10

12

14

1960 1970 1980 1990 2000 2010

cents/KWh (2011$)
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Figure 4-108. Average Retail Electricity Price by State (cents/kWh), 2011

Source: EIA 2012

Note: Data are displayed as 5 groups of 10 States and the District of Columbia.

 U.S. total average price per kilowatthour is 9.90 cents.

Source: U.S. Energy Information Administration, Annual Energy Review –

 Electricity Section, Table 4, September 27, 2012.
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4.9 Natural Gas Market

The natural gas market in the United States has historically experienced significant price 

volatility from year to year, between seasons within a year, and can undergo major price swings 

during short-lived weather events (such as cold snaps leading to short-run spikes in heating 

demand). Over the last decade, gas prices (both Henry Hub prices and delivered prices to the 

power sector) have ranged from below $3 to nearly $10/mmBtu on an annual average basis 

(see Figure 4-119). During that time, the daily price of natural gas reached as high as 

$15/mmBtu. Recent forecasts of natural gas availability have also experienced considerable 

revision as new sources of gas have been discovered and have come to market, although there 

continues to be some uncertainty surrounding the precise quantity of the resource base.

Current and projected natural gas prices are considerably lower than the prices 

observed over the past decade, largely due to advances in hydraulic fracturing and horizontal 

drilling techniques that have opened up new shale gas resources and substantially increased 

the supply of economically recoverable natural gas. According to AEO 2012 (EIA 2012):

Shale gas refers to natural gas that is trapped within shale formations. Shales are 

fine-grained sedimentary rocks that can be rich sources of petroleum and natural 

gas. Over the past decade, the combination of horizontal drilling and hydraulic 

fracturing has allowed access to large volumes of shale gas that were previously 

uneconomical to produce. The production of natural gas from shale formations 

has rejuvenated the natural gas industry in the United States.

The U.S. Energy Information Administration's Annual Energy Outlook 2012 (Early 

Release) estimates that the United States possessed 2,214 trillion cubic feet (Tcf) of 

technically recoverable natural gas resources as of January 1, 2010. Natural gas from 

proven and unproven shale resources accounts for 542 Tcf of this resource estimate. 

Many shale formations, especially the Marcellus, are so large that only small portions of 

the entire formations have been intensively production-tested. Consequently, the 

estimate of technically recoverable resources is highly uncertain, and is regularly 

updated as more information is gained through drilling and production. At the 2010 rate 

of U.S. consumption (about 24.1 Tcf per year), 2,214 Tcf of natural gas is enough to 

supply over 90 years of use. Although the estimate of the shale gas resource base is 
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lower than in the prior edition of the Outlook, shale gas production estimates increased 

between the 2011 and 2012 Outlooks, driven by lower drilling costs and continued 

drilling in shale plays with high concentrations of natural gas liquids and crude oil, which 

have a higher value in energy equivalent terms than dry natural gas.21

EIA’s projections of natural gas conditions did not change substantially in AEO 2013 

from the AEO 2012, and EIA is still forecasting abundant reserves consistent with the above 

findings. Recent historical data reported to EIA is also consistent with these trends, with 2012 

being the highest year on record for domestic natural gas production.22 The average delivered 

natural gas price to the power sector was $3.44 per MMBtu in 2012, down from $4.78/MMBtu 

in 2011.23 

EIA projections of future natural gas prices assume trends that are consistent with 

historical and current market behavior, technological and demographic changes, and current 

laws and regulations.

24 Depending on actual conditions, there may be significant variation from 

the price projected in the reference case and the price observed. To address this uncertainty, 

EIA issues a range of alternative cases, including cases with higher and lower economic growth, 

which address many of the uncertainties inherent in the long-term projections. The EPA 

describes the AEO 2013 reference case and a number of relevant alternative cases in the 

analyses in Chapter 5.

 21 For more information, see: http://www.eia.gov/forecasts/archive/aeo11/IF_all.cfm#prospectshale; 

http://www.eia.gov/energy_in_brief/about_shale_gas.cfm 22 http://www.eia.gov/dnav/ng/hist/n9010us2a.htm 23 http://www.eia.gov/dnav/ng/hist/n3045us3A.htm; Assumes that 1 TCF = 1.023 MMBtu natural gas 

(http://www.eia.gov/tools/faqs/faq.cfm?id=45&t=8) 24 EIA 2010c.
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Figure 4-119. Natural Gas Spot Price, Annual Average (Henry Hub)

Source: EIA 2010d, EIA 2011, EIA 2012, EIA 2013

4.10 Electricity Demand and Demand Response

Electricity performs a vital and high-value function in the economy. Historically, growth 

in electricity consumption has been closely aligned with economic growth. Overall, the U.S. 

economy has become more efficient over time, producing more output (gross domestic 

product – GDPGDP) per unit of energy input, with per capita energy use fairly constant over the 

past 30 years (EIA, 2010e). The growth rate of electricity demanded has also been in overall 

decline for the past sixty years (see Figure 4-1210), with several key drivers that are worth 

noting. First, there has been a significant structural shift in the U.S. economy towards less 

0

2

4

6

8

10

12

1990 1995 2000 2005 2010 2015 2020 2025 2030 2035 2040

2011 dollars per million Btu

Natural Gas Spot Price, Annual Average (Henry Hub)

EIA Historical

EIA Projected (AEO 2011)

EIA Projected (AEO 2012)

EIA Projected (AEO 2013)
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energy-intensive sectors, like services.25 Second, companies have strong financial incentives to 

reduce expenditures, including those for energy. Third, companies are responding to the 

marketplace and continually develop and bring to market new technologies that reduce energy 

consumption. Fourth, other policies, such as energy efficiency standards at the state and 

Federal level, have helped address certain market failures. These broader changes have altered 

the outlook for future electricity growth (see Figure 4-10). 

Figure 4-7. Electricity Growth Rate (3 Year Rolling Average) and Projections from the Annual 

Energy Outlook 2013

Source: EIA 2009, EIA 2013

Energy efficiency initiatives have become more common, and investments in energy 

efficiency are projected to continue to increase for the next 5 to 10 years, driven in part by the 

growing number of states that have adopted energy efficiency resource standards. These 

investments, and other energy efficiency policies at both the state and federal level, create 

incentives to reduce electricity consumption and peak load. According to EIA, demand-side 

 25 EIA 2013
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management provided actual peak load reductions of 33.3 GW in 2010. For context, the current 

coal fleet is roughly 314 GW of capacity.

Demand for electricity, especially in the short run, is not very sensitive to changes in 

prices and is considered relatively price inelastic, although some demand reduction does occur 

in response to price. With that in mind, the EPA modeling does not typically incorporate a 

“demand response” in its electric generation modeling (Chapter 5) to the increases in electricity 

prices typically projected for EPA rulemakings. Electricity demand is considered to be constant 

in EPA modeling applications and the reduction in production costs that would result from 

lower demand is not considered in the primary analytical scenario that is modeled. This leads to 

some overstatement in the private compliance costs that the EPA estimates for rules where 

compliance costs are anticipated for a rulemaking. Note that this NSPS is not anticipated to 

create compliance costs for projected new EGU sources

. 

4.110 References

Interagency Task Force on Carbon Capture and Storage. Report of the Interagency Task Force on 

Carbon Capture and Storage. August 2010. Available online at: 

http://www.epa.gov/climatechange/downloads/CCS-Task-Force-Report-2010.pdf.

Intergovernmental Panel on Climate Change. Climate Change 2001: The Scientific Basis. 2001. 

Available online at: 

http://www.grida.no/publications/other/ipcc_tar/?src=/climate/ipcc_tar/wg1/218.htm.

National Energy Technology Laboratory (NETL). Reducing CO2 Emissions by Improving the 

Efficiency of Existing Coal-fired Power Plant Fleet. July 2008. Available online at: 

http://www.netl.doe.gov/energy-analyses/pubs/CFPP%20Efficiency-FINAL.pdf. 

Pacific Northwest National Laboratory (PNNL). An Assessment of the Commercial Availability of 

Carbon Dioxide Capture and Storage Technologies as of June 2009. June 2009. Available 

online at: http://www.pnl.gov/science/pdf/PNNL-18520_Status_of_CCS_062009.pdf.

U.S. Energy Information Administration (U.S. EIA). Carbon Dioxide Emissions from the 

Generation of Electric Power in the United States. July 2000. Available online at: 

ftp://ftp.eia.doe.gov/environment/co2emiss00.pdf.
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U.S. Energy Information Administration (U.S. EIA). Electric Power Annual 2003. 2003. Available 

online at: http://www.eia.gov/electricity/annual/archive/03482003.pdf.

U.S. Energy Information Administration (U.S. EIA). Electric Power Annual 2009. 2009. Available 

online at: http://www.eia.gov/electricity/annual/archive/03482009.pdf. 

U.S. Energy Information Administration (U.S. EIA). Electric Power Annual 2010. 2010a. Available 

online at: http://www.eia.gov/electricity/annual/.

U.S. Energy Information Administration (U.S. EIA). “Status of Electricity Restructuring by State.” 

2010b. Available online at: 

http://www.eia.gov/cneaf/electricity/page/restructuring/restructure_elect.html.

U.S. Energy Information Administration (U.S. EIA). AEO 2010 Retrospective Review. 2010c. 

Available online at: http://www.eia.gov/forecasts/aeo/retrospective/. 

U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2010. 2010d. 

Available online at: http://www.eia.gov/oiaf/archive/aeo10/index.html. 

U.S. Energy Information Administration (U.S. EIA). Annual Energy Review 2010. 2010e. Available 

online at: http://www.eia.gov/totalenergy/data/annual/pdf/aer.pdf.

U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2011. 2011. Available 

online at: http://www.eia.gov/forecasts/archive/aeo11/. 

U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2012 (Early Release). 

2012. Available online at: http://www.eia.gov/forecasts/aeo/.

U.S. Energy Information Administration (U.S. EIA). Today in Energy: s Most states have 

Renewable Portfolio Standards. 2012a. Available online at: 

http://www.eia.gov/todayinenergy/detail.cfm?id=4850.

U.S. Energy Information Administration (U.S. EIA). Annual Energy Outlook 2013. 2013. Available 

online at: http://www.eia.gov/forecasts/aeo/.

U.S. Environmental Protection Agency (U.S. EPA). Available and Emerging Technologies for 

Reducing Greenhouse Gas Emissions from Coal-Fired Electric Generating Units. October 

2010. Available online at: http://www.epa.gov/nsr/ghgdocs/electricgeneration.pdf. 
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U.S. Environmental Protection Agency (U.S. EPA). Inventory of U.S. Greenhouse Gas Emissions 

and Sinks: 1990–2011. April 2013. Available online at: 

http://www.epa.gov/climatechange/Downloads/ghgemissions/US-GHG-Inventory-2013-

Main-Text.pdf.