From: Frey, Nathan J.

To: Culligan, Kevin

Cc: Hutson, Nick; Wayland, Robertj

Subject: Re: uncertainty language

Date: Wednesday, September 18, 2013 9:07:07 PM

Thanks Kevin - let's touch base in the morning.

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

Sent: Wednesday, September 18, 2013 07:37 PM

To: Frey, Nathan J. 

Cc: Hutson, Nick <Hutson.Nick@epa.gov>; Wayland, Robertj <Wayland.Robertj@epa.gov> 

Subject: uncertainty language 

Nathan,

Here is our shot at revisions. Note that there are a couple small placeholders related to

the year dollars used and the methodology for escalating. We will work with our econ folks

first thing tomorrow to get those right. I think that even without them, DOE will be able to

judge whether we've hit the mark and if not suggest edits. I'll be checking e-mail and can

also be reached at 240-426-1025.

- Kevin
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 projected 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 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 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 studies lies not in the absolute accuracy of the individual 

 

6

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

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

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-a-kind”. 

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 

 

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”). 
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 

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. 

 

8 (http://ghgnews.com/index.cfm/summit-even-without-uk-demofunding-project-will-move-forward/?mobileFormat=true).
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 somewhat 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 

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. 

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

 

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

grid for the installed capacity.