From: Frey, Nathan J.

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

Cc: Tsirigotis, Peter

Subject: RE: EGU NSPS -- Summary of Interagency Comments under EO 12866 13563

Date: Thursday, September 19, 2013 3:29:14 PM

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

Please see attached for the latest summary of interagency comments under EO 12866 13563.

Please let me know if you would like to discuss.

From: Frey, Nathan J. 

Sent: Thursday, September 19, 2013 11:50 AM

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

Cc: Tsirigotis, Peter

Subject: RE: EGU NSPS -- Summary of Interagency Comments under EO 12866 13563

Thanks – I have a minor suggestion if you second to give me a quick call. Almost there!

From: Culligan, Kevin [mailto:Culligan.Kevin@epa.gov] 

Sent: Thursday, September 19, 2013 11:26 AM

To: Frey, Nathan J.; Hutson, Nick; Wayland, Robertj

Cc: Tsirigotis, Peter

Subject: RE: EGU NSPS -- Summary of Interagency Comments under EO 12866 13563

Nathan,

After we spoke, I got further direction from Peter. We believe that the text starting with “despite

the application.....” should be deleted because it is conjecture and not factual (and ignores the

other side of the story, because it is often shown that projections like this are un-necessarily

pessimistic and costs

- Kevin

From: Frey, Nathan J. [mailto:Nathan_J._Frey@omb.eop.gov] 

Sent: Thursday, September 19, 2013 9:44 AM

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

Subject: EGU NSPS -- Summary of Interagency Comments under EO 12866 13563

Hello all,

Attached please find a summary of interagency comments under EO 12866 and 13563 regarding

the issue(s) discussed yesterday. Please let me know ASAP if you would like to arrange a call to

discuss.

Thanks,

Nathan
1. Cost estimates for implementation of partial CCS 

The EPA has examined costs of new fossil fueled power 

generation options. These options are shown in Table 6 below. 

The costs in Table 6 table shows are projected for the costs of

new fossil generation with and without various carbon capture 

options. The costs for new NGCC technology are provided at two 

different natural gas prices: at $6.11/MMBtu, which is 

reasonably consistent with current and projected prices; and at 

$10/MMBtu, which would be well above current and projected 

natural gas prices. We also show projected costs for SCPC and 

IGCC units with no CCS (i.e., units that would not meet the 

proposed emission standard) and for those units with partial 

capture CCS installed such that their emissions would meet the 

proposed 1,100 lb CO2/MWh standard. We have also included costs 

for those same units when EOR opportunities are available. We 

have included a “low EOR” case assuming a low EOR price of $20 

per ton of CO2, and a “high EOR” of $40/ton. (These EOR prices 

are net of the costs of transportation, storage, and monitoring 

(TSM). We also show the projected costs for implementation of 

full capture CCS (i.e., 90 percent capture). 
Table 6. Levelized Cost of Electricity for Fossil Fuel Electric 

Generating Technologies, Excluding Transmission Costs1,2

Technology 

Levelized Cost of 

Electricity 

($2011/MWh)3,4,5

NGCC @ $6.11/MMBtu 59 

 

1

 These costs come from the following DOE/NETL studies: (1) Cost 

and Performance Baseline for Fossil Energy Plants Volume 1: 

Bituminous Coal and Natural Gas to Electricity, Rev 2, DOE/NETL2010/1397 (Nov 2010); (2) Updated Costs (June 2011 Basis) for 

Selected Bituminous Baseline Cases” DOE/NETL-341/082312 (Aug 

2012); (3) Cost and Performance of PC and IGCC Plants for a 

Range of Carbon Dioxide Capture, DOE/NETL-2011/1498 (May 2011).

Capacity factor are assumed at 85 percent.

2

 These costs do not include the impact of subsidies that may 

potentially be available to developers of new projects that 

include CCS.

3 Data for fossil fuel-fired generation comes from DOE/NETL: (1) 

Cost and Performance Baseline for Fossil Energy Plants Volume 1: 

Bituminous Coal and Natural Gas to Electricity, Rev 2, DOE/NELT2010/1397 (Nov 2010); (2) Updated Costs (June 2011 Basis) for 

Selected Bituminous Baseline Cases” DOE/NETL-341/082312 (Aug 

2012); (3) Cost and Performance of PC and IGCC Plants for a 

Range of Carbon Dioxide Capture, DOE/NETL-2011/1498 (May 2011). 

Data for non-fossil fuel-fired generation comes from DOE Energy 

Information Administration (EIA) Annual Energy Outlook (AEO)

2013. Levelized Cost of Electricity (LCOE) estimates come from 

http://www.eia.gov/forecasts/aeo/electricity_generation.cfm. To 

maintain consistency with DOE/NETL estimates, EIA estimates 

provided in this table do not include transmission investment. 4 LCOE point estimates are provided for coal-fired capacity 

types; all other LCOE estimates are presented as a range that 

reflects EIA’s view on the regional variation in local labor 

markets, cost and availability of fuel, and renewable resources. 

The capacity factor ranges for renewable non-dispatchable 

technologies are as follows: Wind – 30% to 39%, Wind Offshore –

33% to 42%, Solar PV- 22% to 32%, and Solar Thermal – 11% to 

26%. Capacity factors for dispatchable technologies are as 

follows: Coal and NGCC – 85%, Nuclear – 90%, Biomass – 83%, 

Geothermal – 92%, and Combustion Turbine – 30%. There is no 

capacity credit provided to dispatchable resources. 

5 These costs do not include the impact of subsidies that may 

potentially be available to developers of new projects that 

include CCS.
NGCC @ $10.0/MMBtu 86 

 

SCPC w/o CCS6 92 

SCPC (1,100 lb/MWh; no EOR) 110 

SCPC (1,100 lb/MWh; low EOR) 96 

SCPC (1,100 lb/MWh; high EOR) 88 

SCPC (full, 90 percent CCS) 147 

 

IGCC w/o CCS 97 

IGCC (1,100 lb/MWh; no EOR) 109 

IGCC (1,100 lb/MWh; low EOR) 101 

IGCC (1,100 lb/MWh; high EOR) 97 

IGCC (full, 90 percent CCS) 136 

 

The cost estimates from the DOE/NETL studies carry an 

accuracy of -15% ± 30%, consistent with a “feasibility study” 

level of design engineering applied to the various cases in this 

study The DOE/NETL reports cite an accuracy range of -15% to +30% for the central point 

estimates shown in Table 6, which are based on many assumptions, including: an EPCM 

contracting methodology, ISO ambient conditions, Midwest merit-shop labor costs, and a level 

greenfield site in the United States Midwest with no unusual characteristics (e.g., flood plain, 

seismic zones, environmental remediation). For specific sites that differ from this generic 

description, plant costs could exceed the quoted range.DOE/NETL explain that there 

are a range of future potential costs that are up to 15% below, 

or 30% above a central estimate. We have presented that central 

estimate above. Also note that the DOE/NETL studies were not 

generally calculated in year (x) dollars. We have adjusted them 

 

6

 SCPC LCOE includes a 3% increase to the weighted average cost 

of capital to reflect EIA’s climate uncertainty adder (CUA). 

Comment [A1]: This looks like a revision 

artifact. 
all to year y dollars using Bureau of Economic Indicator 

factors, to make consistent with other costs used throughout 

today’s preamble. (i.e., the LCOE values can range from 15 

percent less to as much as 30 percent higher than the value 

provide in Table 6). The value of the DOE/NETL studies lies not 

in the absolute accuracy of the individual case results but in 

the fact that all cases were evaluated under the same set of 

technical and economic assumptions. This consistency of approach 

allows meaningful comparisons among the cases evaluated. 

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 research, development and 

demonstration projects.7

 The estimates provided in Table 6 for a 

new NGCC unit and for a SCPC plant without CO2 capture are based 

on mature technologies and are thus NOAK costs. For plants that 

utilize technologies that are not yet fully mature and/or which 

have not yet been serially deployed in a commercial context, 

 

7

 Elsewhere in this preamble, we describe the evidence that as 

technology matures, its costs decrease. Note also that EPA 

regulations of mobile source air emissions incorporate the 

decreasing costs of technology over time. See, e.g., “2017 and 

Later Model Year Light-Duty Vehicle Greenhouse Gas Emissions and 

Corporate Average Fuel Economy Standards – Final Rule,” 77 Fed. 

Reg. 62624, 62984/1 to 62985/1 (October 15, 2012) (incorporating 

“cost reductions, due to learning effects”). 
such asthe IGCC or any plant that includes CO2 capture, the cost 

estimates in Table 4 6 represent a plant that is somewhere 

between FOAK and NOAK, sometimes referred to as “next-of-akind”, or “next commercial offering”. These cost estimates for 

next commercial offerings do not include the unique cost 

premiums associated with first-of-a-kind (FOAK) plants that must 

demonstrate emerging technologies and iteratively improve upon 

initial plant designsand rectify the initial iterations of 

emerging technologies. However, these costs do utilize 

currently available cost bases for emerging technologies 

with associated process contingencies applied at the 

appropriate subsystem levels. Despite the application of 

process contingencies and other best efforts 

to realistically project the cost of emerging technologies, it 

should be noted that such cost projections are often shown to be 

optimistic when actual costs are realized. Accordingly, the 

"next commercial offering" cost estimates in Table 6, while 

intended for plants that lie somewhere between FOAK and NOAK in 

the maturity spectrum, are expected to be closer to NOAK plant 

costs given the inherent "technology optimism" associated with 

projecting costs for emerging technologies.

It should be noted that there is often “technology optimism” 

associated with early cost estimates for emerging technologies, 

Formatted: Highlight
and successful RD&D can lead to lower costs for future 

technology generations.

 

Because there are a number of projects currently under 

development, the EPA believes it is reasonable to focus on the 

next-of-a-kind costs provided in Table 6. The lessons learned 

from design, construction and operation of those projects, as 

well as for that of Duke Energy’s Edwardsport IGCC (which does 

not include CCS) will help lower costs for future gasification 

facilities implementing CCS. The TCEP project and the HECA 

project are both in advanced stages of design and 

development. Summit Power, the developer of TCEP, is also 

pursuing a number of additional projects that would benefit from 

lessons learned from TCEP. These include the Captain Clean 

Energy Project in the United Kingdom (UK) and another polygeneration project in Texas.8

 For a new conventional PC plant 

implementing post-combustion CCS, the Boundary Dam project will 

perhaps represent a FOAK project while the W.A. Parish project 

may represent a second-of-a-kind project - or perhaps even a 

next-of-a-kind project. 

Further, as discussed elsewhere in this preamble, many of 

the individual components of a new generation project with CCS 

 

8 (http://ghgnews.com/index.cfm/summit-even-without-uk-demofunding-project-will-move-forward/?mobileFormat=true).
have been previously demonstrated. For example, capturing CO2

from a coal gasification syngas stream has been occurring for 

more than ten years at the Dakota Gasification facility. 

Experience gained at that facility can inform design and 

operational choices of a new IGCC implementing partial CCS. 

For all these reasons, the next IGCC and SCPC facilities 

with CCS can be expected to be less expensive than the current 

FOAK projects, if somewhatbut more expensive than the NOAK 

facilities with CCS that construct when CCS has become a fully 

mature technology. The costs in Table 6 reflect those next-of-akind costs.

The EPA has also examined costs of new non-fossil fueled 

power generation options. These options are shown in Table 6

below.

Table 7. Range of Levelized Cost of Electricity for Non-Fossil 

Fuel Electric Generating Technologies, Excluding Transmission 

Costs9,10

 

9

 Data for non-fossil fuel-fired generation comes from DOE Energy 

Information Administration (EIA) Annual Energy Outlook (AEO)

2013. Levelized Cost of Electricity (LCOE) estimates come from 

http://www.eia.gov/forecasts/aeo/electricity_generation.cfm. To 

maintain consistency with DOE/NETL estimates in Table 6, the EIA 

estimates provided in this table do not include transmission 

investment.

10 The LCOE estimates in Table 7 are presented as a range that 

reflects EIA’s view on the regional variation in local labor 

markets, cost and availability of fuel, and renewable resources. 

The capacity factor ranges for renewable non-dispatchable 

technologies are as follows: Wind – 30 to 39 percent, Wind 

Formatted: Indent: First line: 0.5"
Technology

Levelized Cost of 

Electricity 

($2011/MWh)

Nuclear 103 - 114

Biomass 97 - 130

Geothermal 80 – 99

Combustion Turbine 87 – 116

Onshore Wind 70 – 97

Offshore Wind 177 – 289

Solar PV11 109 – 220

Solar Thermal 184 – 412

Nuclear 103 - 114

Biomass 97 - 130

Geothermal 80 – 99

 

Offshore – 33 to 42 percent, Solar PV- 22 to 32 percent, and 

Solar Thermal – 11 to 26 percent. Capacity factors for 

dispatchable non-fossil fueled technologies are as follows: 

Nuclear – 90 percent, Biomass – 83 percent, and Geothermal – 92

percent. There is no capacity credit provided to dispatchable 

resources. 

11 Costs are expressed in terms of net AC power available to the 

grid for the installed capacity.