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 CO 2 

### /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 CO 2 

### , 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 “n th 

### -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 CO 2 

### 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 CO 2 

### 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 CO 2



### 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 2011Basis) 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 renewableresources. 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