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 Com ments on Draft Language under

EO12866 Interagency Review.  Subje ct to Further Policy Review.

1 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 CO 2



### 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 CO 2 

### 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 CO 2 

### 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 CO 2 

### 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% higher i 

### 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 curves ii 

### examined how “learning by doing” might reduce the cost

of an IGCC plant with CO 2 

### 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 CO 2 

### 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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## Summary of Interagency Working Com ments on Draft Language under

EO12866 Interagency Review.  Subje ct to Further Policy Review.

2 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% CO 2 

### capture. It should be noted that the

Kemper IGCC will capture somewhat less CO 2 

### (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)

CO 2



### Capture,

% CO 2 

### Emission

Rate,

lb/MWh

‐ gross Capacity

Factor,

% EPA NETL

recommendation

(next

‐ of

‐ a

‐ kind) iii 

### NETL

recommendation

(first

‐ of

‐ a

‐ kind)

NGCC iv 

### 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 ~65 541 v 

### 80 ~170 vi



### 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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## Summary of Interagency Working Com ments on Draft Language under

EO12866 Interagency Review.  Subje ct to Further Policy Review.

3 optimism” tends to persist even when substantial process contingencies are applied to early estimates,

and is applicable for CO 2 

### capture costs as well as CO 2 

### 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 CO 2 

### 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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## Summary of Interagency Working Com ments on Draft Language under

EO12866 Interagency Review.  Subje ct to Further Policy Review.

4 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 di d 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: Tech nology 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 CO 2 

### . NGCC COEs assume a delivered natural ga s 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 tu rbine. 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 So uthern Company) is based on the most recent publicly

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

excluding costs for the lignite mine and CO 2 

### 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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## Summary of Interagency Working Com ments on Draft Language under

EO12866 Interagency Review.  Subje ct to Further Policy Review.

5 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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## Summary of Interagency Working Com ments on Draft Language under

EO12866 Interagency Review.  Subje ct to Further Policy Review.

6 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 w ould 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 co mpare 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 abbrev iation 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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## Summary of Interagency Working Com ments on Draft Language under

EO12866 Interagency Review.  Subje ct to Further Policy Review.

7 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 th e 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 com ponent 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.

### Summary of Interagency Working Comments on Draft Language under

EO12866/13563 Interagency Review.  Subject to Further Policy Re view.

2

‐ 1 CHAPTER 2

INTRODUCTION AND BACKGROUND

2.1 Introduction

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

dioxide ( CO 2 )

, 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 202 2 0

, including some projections for years up to 2030 beyond 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 CO 2

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 CO 2 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,

### Summary of Interagency Working Comments on Draft Language under

EO12866/13563 Interagency Review.  Subject to Further Policy Re view.

2

‐ 2 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 EIA 1 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, costs 2 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 CO 2 emissions

### Summary of Interagency Working Comments on Draft Language under

EO12866/13563 Interagency Review.  Subject to Further Policy Re view.

2

‐ 3 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 historical 3 and projected 4 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 202 2 0 5 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 timeframe update 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.

### Summary of Interagency Working Comments on Draft Language under

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2

‐ 4 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 CO 2 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 at and the State and Federal levels) to reduce GHG emissions over

the multi

‐ decade life of the plant.

7 However, the CO 2 ‐ related benefits, which are estimated using the social cost of carbon, vary depending on the

year in which the change in CO 2 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.

### Summary of Interagency Working Comments on Draft Language under

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2

‐ 5 60.14(e)(5), even if they emit CO 2 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 CO 2 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 c w ould 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 CO 2 emissions from affected sources. The EPA is proposing these

requirements because CO 2 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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2

‐ 6 The EPA is aware that other GHGs such as nitrous oxide (N 2 O) (and to a lesser extent,

methane (CH 4 )) 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 (NO X ) control. The EPA is

not proposing separate N 2 O or CH 4 emission limits or an equivalent CO 2 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 CO 2 /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 units solid fossil

‐ fired EGUs

, which can be met over a 60

‐ operating month

rolling average basis. The alternative emission limit will be between 1,000 950 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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‐ 7 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 GHG emissions

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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- 1 CHAPTER 4

ELECTRIC POWER SECTO R 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 propos al

, 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 pro jections 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 proces s 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 1 8 ,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 commerci al, industrial, and

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

produced (see Table 4

- 2). Some of these uses are highly variable, such as heating and air

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

as industrial processes that operate 24 hours a day.

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- 2 Table 4

- 1

. Existing Electricity Generating Capacity by Energy Source, 20 11

Energy Source Number of

Generators Generator

Nameplate

C apacity (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 201 1 (Billion kWh)

Sales/Direct Use

(Billion kWh) Share of Total

End Use

Retail Sales Residential 1,4 23 37. 9 %

Commercial 1,3 28 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 20 1 1 , 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 g as, with coal accounting for the largest single share (see

Table 4

- 3).

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- 3 Table 4

- 3

. Electricity Net Generation in 20 1 1 (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 suppl ied “base

- load” electricity, the portion

of e lectricity 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 gene ration 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 busine sses 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, i n 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 o f this rule on these new sources are discussed in more detail in

Chapter 5 of this RIA.

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- 4 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 subst ations 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 frequency synchronously

. 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

Interconnec t Region, and ERCOT, respectively.

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- 5 generation, transmission, and distribution systems to balance their common generation and

load needs.

Figure 4

- 1

. Fossil Fuel

- Fired Electricity Generating Facilities, by Size

S ource: National Electric Energy Data System (NEEDS ) 4.10

Note: This map displays facilities in the NEEDS 4.10 IPM frame. NEEDS reflects available capa city on

- line by the

end of 2011. T his includes planned new bu ilds 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 fr om 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

lin es running from the electricity generating sources to substations or from substations to

residences and business es

.

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- 6 Transmission has generally been developed by the larger vertically integrated utilities

that typically operate generation and distribution n etworks. Often d istribution 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 t ransmission 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, includin g

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

deliver power to consumers. In many state s

, such efforts ha ve also included separating

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

Transmission and distribution remain price

- regulated throughout the countr y based on the cost

of service.

4 .3 Deregulation and Restructuring

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

has cha nged 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 histo rically

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, inclu ding

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 activ e 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 combustio n 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 el ectric power industry slowed significantly in response

to market volatility in California and financial turmoil associated with bankruptcy filings of key

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- 7 energy companies

. By the end of 2001, restructuring had either been delayed or suspended in

eight stat es 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 regul atory

activity in 2001 (EIA

, 2003) (“Not Active” in Figure 4

- 2 below). Currently, there are 15 states

where price deregulation of generation (restructuring) ha s occurred (“Active” in Figure 4

- 2

below). Power sector restructuring is more or less at a stands till; 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 CO 2 in particular, but also contributes to emissions of sulfur hexafluoride (S F 6 ), CH 4 , and N 2 O

.

In 20 11 , the power sector accounted for 33 percent of total nationwide greenhouse gas

emissions, measured in CO 2 equivalent

, a slight increase from its 30 percent share in 1990

.

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- 8 Table 4

- 5 and Figure 4

- 3 show the contributions of the powe r sector relative to other major

economic sectors. Table 4

- 6 and Figure 4

- 4 show the contributions of CO 2 and other GHGs from

the power sector.

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- 9 Table 4

- 5

. Domestic Emissions of Greenhouse Gases, by Economic Sector (million metric

ton ne s of CO 2 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, 2 011 (million metric ton ne s of CO 2 equivalent)

Sou rce: EPA 2013 

### Other

4,501

67% Electricity

Generation

2,201

33%

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- 10 Table 4

- 6

. Greenhouse Gas Emissions from the Electricity Sector (Generation, Transmission

and Distribution)

, 20 11 (million metric ton ne s of CO 2 equivalent)

Source Total Emissions

CO 2 2,175.5

CO 2 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

CH 4 0.4

Stationary Combustion* 0.4

Incineration of Waste +

N 2 O 18.3

Stationary Combustion* 17.9

Incineration of Waste 0.4

SF 6 ** 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.

** SF

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

+ Does not exceed 0.05 Tg CO

2 Eq. or 0.05 percent.

The amount of CO 2 em itted 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 CO 2 during combustion. C oal

e mits 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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- 11 Figure 4

- 4

. GHG Emissions from the Power Sector Relative to Total Domestic GHG Emissions

(20 11 )

Source: EPA 2013

Table 4

- 7

. Fossil Fuel Emission Factor s 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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- 12 Municipal Solid Waste 91.9

Source: Documentation for IPM Base Case v.4.10

. See also Table 9.9 of IPM Documentation.

Note: CO 2 emissions presented here for biomass account for combustion only and do not reflect lifecycle

emissions from initial photosynthesis (carbon sink) or harvesting activities and transportat ion (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 CO 2 emissions of new fossil fuel combustion sources intended for

intermediate and baseload operations. These include the use of: CO 2 capture and storage ( CCS )

,

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

gasifi cation 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 CO 2 emis sion 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 p ercent (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 p roduce a MWh of electricity than a combined

- cycle unit. Thus,

when burning natural gas its CO 2 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 fossil

fired 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 t he 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 non

GHG emitting baseload technologies tha t

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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- 13 generators. Additionally, with g asification, some of the syngas can be converted into other

marketable products such as fertilizer, and CO 2 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

- c ombustion or post

- combustion

capture of CO 2 from a gas stream associated with the fuel combusted. Furthermore, CCS can be

designed and operated for full capture of the CO 2 in the gas stream (i.e., above 90 percent) or

for partial capture (below 90 percent)

. the amount of CO 2 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, CO 2 is stripped from the flue gas by passing the flue g as

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 CO 2 back to gaseous form. The

absorbe nt 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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- 14 Source: Interagency Task Force on Carbon Capture and Storage 2010

Pre

- combustion capture is mainly applicable to I G CC 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 CO 2

removal

– from a “partial capture” percentage to 90 percent “full capture.” Pre

- combustion CCS

typically has a lesser impact on net energy out put 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 CO 2 Capture for a Pulverized Coal Power Plant

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- 15 Source: Interagency Task Force on Carbon Capture and Storage 2010 Figure 4

- 6

. Pre

- Combustion CO 2 Capture for an IGCC P ower Plant

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- 16 4 .6 Geologic Sequestration

4.6.1 Availability of Geologic Sequestration

Geologic storage potential for CO 2 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 Laborator y (NETL) estimates the current total CO 2 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 geolog ic

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

ability to store CO 2 , and DOE is currently evaluating their potential future storage capacity.

Potential sequestration sites must undergo appropriate site c haracterization to ensure that the

site can safely and securely store CO 2 . Estimates of CO 2 storage resources by state/province

from the DOE report are provided in Table 4

- 8 9 . These state and province level estimates are

obtained from DOE’s National Carbo n 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 CO 2

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

Estimates for Carbon Dioxide” in Appendix B of the Carbon Utilization and Storage Atlas 3 (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 technicall y 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 CO 2 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 a nd 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 car bon 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

a ssessment and USGS assessment

described below, it would also be helpful

to know whether the range of the NETL

estimates r eflect only technically

accessible potential, or economic

potential, or a combination.

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- 17 United States

. For comparison, this amount is 500 times the 2011 annual U.S. energy

- related

CO 2 emissions of 5.5 Gigatons (Gt) 5 Areas that were assessed by the USGS for CO 2 storage

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

assessment provides f urther evidence of the widespread availability CO 2 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 CO 2 Storage Resource 7

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, 2 013, 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 Departmen t 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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- 18 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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- 19 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 CO

2 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 CO 2 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 decre ased 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 di oxide ‘flooding’ or CO 2 - 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 CO 2 mixture is produced, and sent to a separator where the crude

oil is separated from the gaseous hydrocarbons and CO 2 . The gaseous CO 2 - rich stream then is

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

oil or na tural 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 CO 2 storage potential in oil and gas reservoirs across over 30 states. 8

CO 2 - 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 CO 2 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 CO 2 sto rage 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 (NET L).

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- 20 billion metric tons), oil and gas reservoirs are currently estimated to have 226 billion metric

tons of CO 2 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

CO 2

.

4 .6.3 Trends in CO 2 - EOR

Carbon dioxide EOR ( CO 2 - 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 C O 2 - 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 CO 2 - EOR is utilized are Alabama, Colorado, Illinois, Kansas, Louisiana, Michigan,

Mississippi, New Mex ico, Oklahoma, Utah, and Wyoming. A well

- established and expanding

network of pipeline infrastructure supports CO 2 - EOR in these areas (Figure 4

- 8 9 ). The CO 2

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

contain CO 2 . While natural sources of CO 2 comprise the majority of CO 2 supplied for EOR

operations, recent developments targeting anthropogenic sources of CO 2 (e.g., ethanol plants,

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

existing infrastructure related to CO 2 - EOR. 12 Several hundred miles of dedicated CO 2 pipeline is

under construction, planned, or proposed that would all ow continued growth in CO 2 supply for

EOR (see Figure 4

- 8 9 ).

Anthropogenic sources of CO 2 for EOR continue to increase as new projects are being

planned or implemented. Based on an evaluation of publicly available sources 13 , 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 Emission s 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

- 2 013

- XXXX EPA

- HQ

- OAR

- 2013

- 0495 )

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

sources of industrial source CCS projects

.

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- 21 currently twenty

- two three ( 2 2 3 ) industrial source CCS projects in twelve ( 12 ) states that are

either operational, under

- construction, or actively being pursued which are or will supply

captured CO 2 for the purposes of EOR. This demonstrates that CCS projects associated with

large point sources are occurring due to a demand for CO 2 by EOR operations. Nationally,

according to EPA’s Greenhouse Gas Reporting Program, over 64 million metric tons of CO 2 was

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

found that the market for captured CO 2 emissions from power plants created by economically

feasible CO 2 - EOR projects would be sufficient to permanently store the CO 2 emissions from 93

l arge (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 CO 2 - E OR operations for geologic

storage to continue to increase.

Based on a recent resource assessment by DOE, the application of next generation CO 2 -

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

geographic extent and accessibility of CO 2 - 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 CO 2 utilization.

As demonstrated in this RIA, the use of CO 2 for EOR can significantly lower the cost of

implementing CCS. The opportunity to sell the captured CO 2 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 CO 2 creates a role for CO 2 - EOR to continue CCS deployment. According

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

s tage of planning, 70% intend to use captured CO 2 to improve recovery of oil in mature fields

(enhanced oil recovery, CO 2 - EOR). 17 Further, smaller, non

- geologic sequestration markets exist

for CO 2 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 Do mestic 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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- 22 Figure 4

- 7. 8: Growth of U.S. Oil Production from CO

2 - based EOR

Source: NETL 2010

Figure 4

- 9: U.S. CO 2 Storage Capacity and CO 2 - EOR operations

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- 23 Figure 4

- 8. 9: U.S. CO 2 Storage Capacity and CO 2 - 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

CO 2 which creates CO 2 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 mi neralization of CO 2 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 ther e are several factors for determining the viability of CO 2 reuse, and

there are currently significant technical barriers to large scale commercial

- scale reuse. First,

rates of conversion must be comparable to rates of CO 2 capture. Second, energy requirem ents

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 long

term fate of CO 2 and its lifecycle emissions. 18 The CCS Task Fo rce also notes there are other

potential commercial uses for captured CO 2 , 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 CO 2 and

the degree to which the method permanently isolates the CO 2 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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- 24 4

. 7 GHG and Clean Energy Regulation in the Power Sector

4.7.1 State Policies

Several states have als o 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 Northea st

and Mid

- Atlantic inviting the m n to participate in the development of a regional cap

- and

- trade

program addressing power plant CO 2 emissions. This program, known as the Regional

Greenhouse Gas Initiative (RGGI), began in 2009 and sets a regional CO 2 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 CO 2

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% annual ly in

from 2015 to 2020

.

I n September 2006, California Governor Schwarzenegger signed into law Senate Bill

1368. The law l imits 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 Commi ssion 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 CO 2 /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 an d 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, whet her or not that generation serves load located within the state.

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- 25 Baseload generation facilities must initially comply with an emission limit of 1,100 lb CO 2 /MWh.

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

faciliti es generating baseload electricity, whether gas

- or coal

- fired, must have emissions equal

to or less than 1,100 lb CO 2 /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 Yor k Governor Cuomo signed the Power NY Act of 2011

. This

regulation establishes CO 2 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

CO 2 standar d of 925 lb/MWh or 120 lb/MMBtu, and peaking facilities must meet a CO 2

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

Additionally, most states have implemented Renewable P ortfolio S tandards (RPS), or

R enewable E lectricity S tandards (RES) . These programs ar e 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 conti ngent 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 s tage 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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- 26 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 vehicl es 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 leve ls must monitor and report

emi ssions.

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 CO 2

. The EPA acknowledged the Supreme Court decision, but found

that decision alone did not require PSD permits to include limits on CO 2 emissions. Sierra Club

challenged the Deseret permit. In November 20 08, the Environmental Appeals Board (EAB)

remanded the permit to the EPA to reconsider “whether or not to impose a CO 2 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 wa s not an established EPA interpretation of the regulatory phrase

“subject to regulation.”

In December 2008, the Administrator issued a memo indicat ing 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 CO 2 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 perm itting 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 sc heduled 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 endange rment finding indicated that

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- 27 current and projected concentrations of the six key well

- mixed greenhouse gases

— CO 2 , CH 4 ,

N 2 O, hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and SF 6 — in the atmosphere

threaten the public health and welfare of current a nd 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 homogeneo usly 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 regu late greenhouse gases under the CAA (see preamble section II.E for regulatory

background)

. T his action was a prerequisite to implementing the EPA's proposed greenhouse

gas emission standards for light

- duty vehicles , which was finalized in January 2010

. Onc e 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 S ource Review and T itle 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 requi rements 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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- 28 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 prov ided 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 agreement s 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 affectin g 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 7 th

, 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 o f 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 increasing ly 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 a nd 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 cost s 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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- 29 Section 316(b) of the CWA, 33 U.S.C. 1326(b), requires that standards applicable to

point sources under section s 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 n ew

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 withd rawing 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 wate r 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 r egulations 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 th e 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 wo uld 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 th e 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 th e ELG requirements that the Agency may promulgate, and the

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- 30 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, E xpenses, and Prices

Due to lower retail electricity sales, total utility operating revenues declined in 2011 to

$2 81 billion from a peak of almost $300 billion in 2008. Despite revenues not returning to 2008

levels in 201 1

, operating expenses were apprecia bly lower and as a result, net income also rose

in compar ison to both 200 9 and 20 10 (see Table 4

- 9 ). Recent economic events have put

downward pressure on electricity demand, thus dampening electricity prices and consumption

(utility revenues), but have als o 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 ro ughly $3 59 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 20 11

. Based on EIA's Annual Energy Outlook 2013 , Table

4

- 10 shows that the power sector is projected to derive revenues of $3 59 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 fac t, the

real price of electricity today is lower than it was in the ear ly 1960s and 1980s (see Figure 4

- 7 9 ).

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- 31 Figure 4

- 9 7

. National Average Retail Electricity Price (1960

– 20 11 )

Source: EIA 2013

Table 4

- 9 8

. Revenue and Expense Statistics for Major U.S. Investor

- Owned Electric Utilities

for 20 10 ($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 2010cents/KWh (2011$)

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- 32 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

- 10 9

. Projected Revenues by Service Category in 2015 for Public Power and Investor

Owned Utilities (billions)

Generation $207

Transmission $40

Distribution $111

Total $3 59

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 201 3

(Electricity Supply, Disposition, Prices, and Emissions)

.

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4

- 33 Figure 4

- 7

. National Average Retail Electricity Price (1960

– 20 11 )

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 tho se of other states (see

Figure 4

- 10 8 )

. 0 2 4 6 8 10 12 14

1960 1970 1980 1990 2000 2010cents/KWh (2011$)

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- 34 Figure 4

- 10 8

. Average Retail Elec tricity Price by State (cents/kWh), 20 11

Source: EIA 20 12 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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- 35 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 / mmB tu on an an nual average basis

(see Figure 4

- 11 9 ). 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 discov ered 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 substantial ly 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 est imate.

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 regu larly

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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- 36 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 cr ude oil, which

have a higher value in energy equival ent 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 a ctual 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 a ddress 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_brie f/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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4

- 37 Figure 4

- 11 9

. Natural Gas Spot Price , Annual Average (Henry Hub)

Source: EIA 2010 d , 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

– GDP GDP ) per unit of energy input, with per capita energy use fairly constant over the

past 30 years (EIA, 2010 e )

. T he growth rate of electricity demand ed has also been in overall

decline for the past sixty years (see Figure 4

- 12 10 ), 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 20402011 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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- 38 ener gy

- 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 tha t 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 201 3

Source: EIA 2009 , EIA 201 3

Energy efficiency initiatives have become more common, and investments in energ y

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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- 39 management provided actual peak load reductions of 33.3 GW in 20 10

. 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 typic ally 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 reduct ion 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 a nticipated for a rulemaking

. Note that this NSPS is not anticipated to

create compliance costs for projected new EGU sources

.

4

. 1 1 0 References

Interagency Task Force on Carbon Capture and Storage

. Report of the Interagency Task Force on

Carbon Capture a nd 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

.

Nati onal Energy Technology Laboratory (NETL). Reducing CO 2 Emissions by Improving the

Efficiency of Existing Coal

- fired Power Plant Fleet . July 2008. Available online at:

ht tp://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

onl ine 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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4

- 40 U.S. Energy Information Administration (U.S. EIA). Electric Power Annual 2 003. 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 . 2010 d

. Available online at: http://www.eia.gov/oiaf/archive/aeo10/index.html

.

U.S. Energy Infor mation Administration (U.S. EIA). Annual Energy Review 2010 . 2010 e . 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 201 2 (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 201 3 . 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 onl ine at: http://www.epa.gov/nsr/ghgdocs/electricgeneration.pdf

.

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- 41 U.S. Environmental Protection Agency (U.S. EPA). Inventory of U.S. Greenhouse Gas Emissions

and Sinks: 1990

– 20 11 . April 201 3 . Available online at:

http://www.epa.gov/climatechange/Downloads/ghgemissions/US

- GHG

- Inventory

- 2013

-

Main

- Text.pdf

.