From: Culligan, Kevin 

Sent: Tuesday, September 17, 2013 5:34 PM 

To: 'Jarad.Daniels@hq.DOE.GOV' 

Cc: 'Frey, Nathan J.'; Wayland, Robertj; Hutson, Nick 

Subject: next steps on uncertainty

 

 

Jarad

After talking with you, the others at DOE and Nathan, we better understand the points you’ve

made.  We agree that it is very important that we do not confuse people with the fact that the ranges in

the NETL numbers and the EIA numbers in fact represent two different things while still making them

understand that there are ranges and they are important.  We think that the point DOE made about the

inconsistency in having ranges for the EIA numbers in the table, while discussing the ranges for NETL

numbers was a good one.  However because of the other very important point you made, that the

ranges represent different things, we think it is even more appropriate to have that discussion in the

text highlighting the differences, rather than in the table where these differences could easily be glossed

over.  We’ve suggested some edits that we believe will accomplish both of our goals of explaining the

importance of and differences in the two sets of ranges.

If you think this approach is workable, we’d be happy to work with you to arrive at mutually acceptable

language.  If you continue to have concerns, I am happy to have Joe follow up with Jonathan.

We appreciate the time that you and others at DOE have taken to help make this rule package as good

as possible.  DOE has offered a number of very good suggestions that have helped to improve the

package.

‐          Kevin (202)564‐0611

See below – RED language is what we previously added in response to OMB/Interagency

comments and was in the language we sent to Nathan Friday night.  The BLUE language is what

we’ve added in response to today’s conversation.  Note that we have change the EIA non‐fossil

LCOE values to be single point costs values

1. Cost estimates for implementation of partial CCS

The EPA has examined costs of new power generation options. 

These options are shown in Table 6. The table shows the costs of 
new NGCC technology 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 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 Electric Generating 

Technologies, Excluding Transmission Costs

Technology

Levelized Cost of 

Electricity 

($2011/MWh)[1],[2],[3]

NGCC @ $6.11/MMBtu 59 

NGCC @ $10.0/MMBtu 86 

SCPC w/o CCS[4] 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 

Nuclear 107

Biomass 110

Geothermal 88

Combustion Turbine 101

Onshore Wind 83

Offshore Wind 216

Solar PV[5] 140

Solar Thermal 256

The cost estimates from the DOE/NETL studies (those for the 

SCPC and IGCC cases listed in Table 6) carry an accuracy of -15% 

± 30%, consistent with a “feasibility study” level of design 

engineering applied to the various cases shown (i.e., the LCOE 

values can range from 15% less to as much as 30% higher than 

those provided in Table 6). The value of the 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.

The LCOE estimates for non-fossil fuel technologies in 

Table 6 come from EIA AEO 2013 cost estimates for new generation 

technology.[6] The costs can also be 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 nondispatchable 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.

It is important to note that, while levelized costs are a 

convenient summary measure of the overall competiveness of 

different generating technologies, actual plant investment 

decisions are affected by the specific technological and 

regional characteristics of a project, which involve numerous 

other considerations.

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 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 

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. 

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.

[1] 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/NELT-2010/1397 (Nov 2010); (2) Updated Costs (June 2011 

Basis) for Selected Bituminous Baseline Cases” DOE/NETL341/082312 (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.

[2] 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 nondispatchable 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. 

[3] These costs do not include the impact of subsidies that may 

potentially be available to developers of new projects that 

include CCS.
[4] SCPC LCOE includes a 3% increase to the weighted average cost 

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

[5] Costs are expressed in terms of net AC power available to the 

grid for the installed capacity.

[6] http://www.eia.gov/forecasts/aeo/electricity_generation.cfm

and 

http://www.eia.gov/forecasts/aeo/pdf/electricity_generation.pdf

[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”).

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