Summary	of	Interagency	Working	Comments	on	Draft	Language	under	

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

Incentives for EGU Modification and Reconstruction

Pages: ES-4 and 6-2, and throughout document

Page ES-4 States: “Historically, the EPA has been notified of very few EGU NSPS modifications (for 

criteria pollutants) or reconstructions. As such, the EPA anticipates few covered units will trigger the 

reconstruction or modification provisions in the period of analysis. Therefore, based on the analysis 

presented in Chapter 4 of this RIA, the EPA anticipates that the EGU New, Modified, and Reconstructed 

Source GHG Standards will result in negligible CO2 emission changes, energy impacts, quantified 

benefits, costs, and economic impacts by 2022. Accordingly, the EPA also does not anticipate this rule 

will have any significant impacts on the price of electricity, employment or labor markets, or the US 

economy.” (Restated on 1-1 and 1-4)

Page 6-2 states: “The EPA does not have sufficient information at this time to predict the full array of 

actions that existing steam generating units may undertake, including those in response to applicable 

requirements under an approved CAA section 111(d) plan.”

Some commenters are concerned that using historical data on modifications and reconstructions may 

not be an accurate way to assess future decisions about reconstruction or modifications because 

incentives in the future may differ from historical incentives. Specifically, the commenters believe that 

forthcoming 111 (d) power sector regulations may change incentives that could cause historical data on 

EGU modifications and reconstructions to underestimate the number of future modifications and 

reconstructions that could occur.

On page 6-2, EPA acknowledges that it does not have sufficient information to predict how existing units 

will respond to the disparity between standards for existing and new/modified/reconstructed plants. 

However, EPA does not discuss the possibility that if proposed 111 (d) standards for existing units are 

finalized at more stringent levels than the 111 (b) standards for modified/reconstructed units, there 

would be a new incentive to trigger NSPS provisions that has not existed historically. This could result in 

motivation for existing steam units to make modifications that trigger them to be subject to a less 

stringent standard (e.g. a modification or reconstruction). 

Commenters would appreciate seeing the data on which units have qualified as reconstructed and 

modified under NSPS section 111(b) and the PSD/NSR program, what actions those units took to qualify 

as modified or reconstructed, and the hourly CO2 emission data if it is available.

If EPA is unable to predict the range of actions that an existing unit might take, then in turn it does not 

seem plausible for EPA to be able to estimate that the magnitude of the change in emissions due to 

these unknown actions is less than 10 percent. 
Summary	of	Interagency	Working	Comments	on	Draft	Language	under	

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

Page 2 of 9

Consideration of Enhanced Oil Recovery

Pages: 2-35 and 5-9 (second instance)

“Although the regulatory impact analysis for this rule relies on GS in deep saline formations, the EPA also 

recognizes the potential for securely sequestering CO2 via EOR.”

“Furthermore, EPA believes the opportunity to engage in EOR opportunities is not significantly limited by 

the location of those opportunities or the current CO2 pipeline infrastructure (12 states currently have 

existing or under construction CO2 pipelines). Provision of electric power does not require coal-fired 

facilities to be co-located with the demand it is intended to serve.”

In the preamble, EPA uses this same reasoning to show that geologic storage can be considered 

universally available since all facilities are either located in an area favorable to geologic storage or the 

electricity can be generated somewhere that is favorable to geologic storage. The electricity can then be 

used to meet demand elsewhere. In the preamble, the cost for storage is taken into account for all CCS 

units. Therefore, based on the quote above it is reasonable to assume EOR is universally available in the 

same way that geologic storage is, and therefore the revenue from CO2 sold for use in EOR should be 

taken into account for all CCS units.

TECHNICAL COMMENTS

Page: 2-8, Footnote

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

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

network operating in most of Texas. These are commonly referred to as the Western Interconnect 

Region, Eastern Interconnect Region, and ERCOT, respectively.”

Suggest revising to clarify how the interconnections are defined. See edits that follow:

“These three network interconnections are the Western Interconnection, comprising the western parts 

of both the US and Canada (approximately the area to the west of the Rocky Mountains), the Eastern 

Interconnection, comprising the eastern parts of both the US and Canada (except those part of eastern 

Canada that are in the Quebec Interconnection), and the Electric Reliability Council of Texas (ERCOT) 

Interconnection, comprising most of Texas.” [Also suggest adding link to map of the interconnections, 

e.g., http://www.nerc.com/AboutNERC/keyplayers/Documents/NERC_Interconnections_Color_072512.jpg]

Page: 2-9

The statement “Transmission has generally been developed by the larger vertically integrated utilities 

that typically operate generation and distribution networks” is not entirely accurate. Commenters

suggest revising the following paragraph as indicated below for accuracy with respect to changes in the 

industry.
Summary	of	Interagency	Working	Comments	on	Draft	Language	under	

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

Page 3 of 9

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

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

Historically, the transmission system had been developed by vertically integrated utilities, establishing 

much of the existing transmission infrastructure. However, as parts of the country have restructured the 

industry, transmission infrastructure has also been developed by transmission utilities, electric 

cooperatives, and merchant transmission companies, among others. Distribution, also historically 

developed by vertically integrated utilities, is now often managed by a number of utilities that purchase 

and sell electricity, but do not generate it. As discussed below, electricity restructuring has focused 

primarily on efforts to reorganize the industry to encourage competition in the generation segment of 

the industry, including ensuring open access of generation to the transmission and distribution services 

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

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

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

service.”

Page: 2-23

“Table 2-5 and Figure 2-17 show the CO2 emissions from the power sector relative to other major 

economic sectors.”

Also, the table and figure refer to GHG emissions rather than CO2 emissions—please clarify. Also, the 

figure numbering (e.g. Figure 2-17) appears to be incorrect. 

Page: 2-30

“The only other industrial-scale electricity power sector CCS project currently under construction is the 

W.A. Parish Petra Nova CCS Project near Houston, Texas.”

Please clarify if this is the only other project in the U.S. or in the world.

DOE suggests revising as follows:

“The only other industrial-scale electricity power sector CCS project currently under construction in the 

United States is the W.A. Parish Petra Nova CCS Project near Houston, Texas.”

Page: 2-35

Commenters recommend that EPA update its IPM input assumptions on CO2 storage costs and CO2

transportation costs.
Summary	of	Interagency	Working	Comments	on	Draft	Language	under	

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

Page 4 of 9

In comments submitted to EPA on the on the Draft Rule, the Clean Air Task Force (CATF) provided a 

possible methodology for estimating CO2 storage costs that may better reflect the value of CO2 used for 

EOR in different regions. 1Commenters recommend that EPA consider a similar approach. 

Specifically, the value of CO2 used for EOR ranges from 1.25% to 2.5% of the price of a barrel of crude oil

is cited in the literature (i.e. the CO2 price in $/MCF is approximately 2% of the price of a barrel of crude 

oil), and this approach is also supported by a number of sources referenced in the CATF comments. In 

addition, Advanced Resources International produced a 2011 report for NETL that provides an 

approximation of the relationship between crude oil prices and CO2 market prices.

Finally, commenters also recommend that EPA update the CO2 transportation cost assumptions in IPM. 

A NETL spreadsheet model for CO2 transportation costs is available at the following location:

http://www.netl.doe.gov/research/energy-analysis/analytical-tools-and-data/co2-transport

Page: 2-36

“An additional 23 states are within 150 miles of current EOR operations.”

commenters suggest explaining why 150 miles is used as the metric to identify states that are near 

current EOR operations. For example, are there currently a significant number of CO2 pipelines that 

transport CO2 at least 150 miles from source to sink?

Page: 3-2, paragraph 2 

Consider providing an example of research that makes a direct connection between climate change 

directly and human health and impacts. For example, consider adding the following sentence to the 

paragraph that cites the National Climate Assessment:

“Impacts on human health could include increased mortality and morbidity due to excessive heat, as 

well as a decline in labor capacity as a result of human heat stress in a warming world.”

Potential references below:

Fischer, E. M., and R. Knutti (2015), Anthropogenic contribution to global occurrence of heavyprecipitation and high-temperature extremes, Nature Climate Change, 5(6), 560–564, 

doi:10.1038/nclimate2617.

Dunne, J. P., R. J. Stouffer, and J. G. John (2013), Reductions in labour capacity from heat stress under 

climate warming, Nature Climate Change, 3(4), 1–4, doi:10.1038/nclimate1827.

Page: 3-7, Table 3-1 

 

1

See, Clean Air Task Force, “Comments and Technical Appendices for the Clean Power Plan - Carbon Pollution 

Emissions Guidelines for Existing EGUs, 79 Fed. Reg. 34,830,” P. 4, available at: 

http://www.catf.us/resources/filings/EGU_GHG_NSPS_Rule/CCS%20Assumptions%20Appendix%20A.pdf.
Summary	of	Interagency	Working	Comments	on	Draft	Language	under	

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

Page 5 of 9

Commenters request that EPA check the 95% numbers presented in Table 3-1. It appears that the 

rounding may have been slightly off when these numbers were converted to 2011 year dollars. In 

addition, were these numbers converted from 2008 to 2011 year dollars or from 2007 to 2011 year

dollars? DOE recommends explaining what year dollar conversion was employed given the correction 

that will be released on these estimates in the near future.

Pages: 4-2 to 4-3

“The natural gas combustion turbine standard, however, will only apply to units that will exceed a sales 

threshold on the amount of electricity generated that is sold to the electric grid. The purpose of the sales 

threshold criterion is to permit gas-fired combustion turbines that will operate as a combined heat and 

power (CHP) unit and only sell a small portion of the gross electricity generated to the grid to not have to 

meet the same emission standard as a combustion turbine unit designed primarily to generate electricity 

to be sold to the grid.”

The commenter’s understanding of the Final Draft Rule preamble was that the sales threshold criterion 

is also intended to exempt simple cycle peakers. 

Suggested edit: “The purpose of the sales threshold criterion is to permit gas-fired simple cycle 

combustion turbines and gas-fired combustion turbines that will operate as a combined heat and power 

(CHP) unit and only sell a small portion of the gross electricity generated to the grid to not have to meet 

the same emission standard as a combustion turbine unit designed primarily to generate base and 

intermediate levels of electricity to be sold to the grid.”

In addition it is unclear how the formula used for applicability ensures that CHP units described are 

excluded from the standard. Commenters request further clarity on how the applicability criteria 

achieve the purpose described here – specifically, how a unit designed primarily to generate electricity 

to be sold to the grid will meet the criteria but other units will not. 

Page: 4-1

Commenters note that new builds for power plants tend to take 2 to 10 years to complete, depending 

on the technology and other issues, such as the time needed to site and permit the project. This analysis 

looks out 8 years into the future. 

Pages: 4-1 and 4-7

“Some new coal-fired units with federally-supported carbon capture and storage (CCS) are forecast to be 

constructed, though these units are expected to be compliant with their standards under this rule.”

Suggest clarifying that these new units are not entirely federally funded. 

Page: 4-8
Summary	of	Interagency	Working	Comments	on	Draft	Language	under	

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

Page 6 of 9

“This has been a consistent finding in the AEO, which led EIA to conclude that “the low capital expense, 

technical maturity, and dispatchability of natural gas generation are likely to dominate investment 

decisions under current policies and projected prices.”

This sentence contains a quote attributed to EIA. However, the footnote accompanying the quote cites 

the DOE’s 2011 Quadrennial Technology Review, rather than an EIA document. The commenters suggest

attributing this quote to DOE, as the quote appears to be a DOE characterization of EIA’s projection. 

Further, the commenters note that the study referenced was published in 2011. 

Pages: 4-9 to 4-13

If results are available, consider showing scenario modeling results through 2040 as this is the horizon 

for the EIA’s Annual Energy Outlook (AEO). 

Page: 4-9 Table 4-1 

Consider explaining the major differences in cumulative capacity additions comparing EPA (2020) and 

AEO 2014 reference case at 2020. 

Comments: AEO 2014 defines “distributed generation” as “primarily peak-load capacity fueled by 

natural gas” whereas this term is sometimes also used to refer to residential and commercial sector 

renewable energy capacity such as rooftop photovoltaic generation. Commenters recommend defining 

“distributed generation” in a footnote for clarity. 

The commenter also recommends defining in footnote 15 the technologies covered under the 

“Renewables” category for both IPM and AEO and indicating that this does not include residential and 

commercial scale renewable deployment. 
Summary	of	Interagency	Working	Comments	on	Draft	Language	under	

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

Page 7 of 9

The commenter believes that, unlike the AEO, IPM does not model distributed generation capacity 

expansion. If this is the case we recommend replacing the zero under EPA 2020 distributed generation 

with an “N/A” or a “–“ with text in the table footnote that reads: “IPM v5.14 does not model distributed 

generation capacity additions”.

Page 4-11

“These measures, in conjunction with Federal financial incentives, are among the key drivers of the 

significant growth in new renewable energy seen over the past few years and expected over the next 

decade.”

The commenter suggests editing text as indicated above. RPS and Federal incentives are not the only key 

drivers of renewable growth and projected growth. Capital cost decreases and increases in performance 

of renewable technologies are also a major factor. Recommend adding text indicated above.

Page 4-12

A significant decrease in the capital cost of wind and solar power since 2010 has also been a key factor 

contributing to the current unfavorable coal deployment environment. Commenters recommend adding 

a fourth bullet point:

“Renewable Cost and Performance Improvements – Significant decreases in capital costs have occurred 

for both wind and solar photovoltaic (PV) technologies in recent years. Since 2009 capital costs have 

fallen by over a third since 2009 for utility-scale PV,244–50% for distributed PV,3and 28% for wind.4In 

addition, improvements in wind technologies has resulted in increased capacity factors for wind projects 

deployed in lower quality wind resource areas.3These trends have contributed to the increased 

deployment of renewables over the last few years and will continue to drive renewable power to be 

more competitive with coal than in the past.”

Page: 4-13

 

2 M. Bolinger and S. Weaver, "Utility-Scale Solar 2013," Lawrence Berkeley National Laboratory, Berkeley, CA, 2014. 

http://emp.lbl.gov/publications/utility-scale-solar-2013-empirical-analysis-project-cost-performance-and-pricing-trends

3

G. Barbose, S. Weaver and N. Darghouth, "Tracking the Sun VII: A Historical Summary of the Installed Price of Photovoltaics in the United 

States from 1998 to 2013," Lawrence Berkeley National Laboratory, Berkeley, CA, 2014. http://emp.lbl.gov/publications/tracking-sun-viihistorical-summary-installed-price-photovoltaics-united-states-1998-20

4

R. Wiser and M. Bolinger, "2013 Wind Technologies Market Report," Lawrence Berkeley National Laboratory, Berkeley, CA, 2014. 

http://emp.lbl.gov/publications/2013-wind-technologies-market-report
Summary	of	Interagency	Working	Comments	on	Draft	Language	under	

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

Page 8 of 9

Comments: The AEO 2014 numbers for the “Non-Hydro Renewables” row represent numbers that do 

include hydroelectric capacity additions. The commenter recommends changing the name of this 

column to “Renewables” and adding a footnote to indicate which technologies are covered. 

Page: 4-24

It appears that SCPC and IGCC do not receive consistent treatment in figure 4-3. IGCC is presented in one 

case without a CUA and without CCS. However, SCPC is not presented in these same terms. Consider 

showing each fossil steam generating technology with a consistent set of CUA and CCS assumptions. 

Page 5-1 (first instance of the page number)

“As explained previously, the power sector has moved away from the construction of coal-fired power 

plants in favor of natural gas-fired power plants and renewable energy facilities due, in part, to the 

significant cost differential.”

The commenters suggest editing text as indicated above. This harmonizes with the reasoning 

recommended on page 4-12. 

Page: 5-3 (first instance of the page number)

In Table 5-1, the emission rate for new NGCC is given as 800 lbs/MWh-net. This is significantly lower 

than the standard of 1,000 lbs/MWh-gross (or 1,080 lbs/MWh-net) in the preamble. 

Page: 5-5 (second instance of the page number)

In footnote 11, the projected natural gas price for 2022 is taken from the reference scenario for 

AEO2013. The commenters suggest using AEO2014 if possible since those are the EIA runs that are 

compared to IPM runs elsewhere in the RIA.

Pages: 5-9 to 5-10
Summary	of	Interagency	Working	Comments	on	Draft	Language	under	

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

Page 9 of 9

“There are two EOR opportunities evaluated in this section – ‘High’ and ‘Low.’ The high EOR opportunity 

assumes a CO2 sale price of $40 per metric ton; the low EOR opportunity assumes a CO2 sale price of $20 

per metric ton based on assumptions used by NETL in evaluating potential EOR opportunities. For either 

opportunity, it is assumed that the facility is only responsible for the costs of transmitting the captured 

CO2 to the fence line, as is currently the practice. Costs for the transportation, storage, and monitoring 

(TSM) of CO2 are included in this analysis. For non-EOR applications, TSM costs of ~$5-$15 dollars per ton 

of CO2 are applied based on the level of capture.”

Are these the cost estimates used in the IPM model?