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July 22, 2013

MEMORANDUM 

TO: John Conti

Assistant Administrator for Energy Analysis

Alan Beamon

Director, Office of Electricity, Coal, Nuclear, and Renewables Analysis

FROM: Coal and Uranium Analysis Team

SUBJECT: AEO2014 Coal Working Group Meeting I Summary 

Attendees (41)

Name Affiliation

Greg Adams (Moderator) US DOE: EIA

Vlad Dorjets

Bob Eynon

Karen Freedman

Tyler Hodge

Paul Holtberg

Elias Johnson

Ayaka Jones

Diane Kearney

Mike Leff

Mike Mellish

Carrie Milton

Nick Paduano

Margaret Cook US DOE: HQ

Dave Schoberlein US DOE: HQ

Sikander Khan US DOE: FE/HQ

Jose Benitez US DOE: FE/NETL

Christopher Nichols US DOE: FE/NETL

Gavin Pickenpaugh US DOE: FE/NETL

Erich Eschmann US EPA

Brian Fisher US EPA

Cortney Higgins US OMB

Greg Moxness US DOL: MSHA

Maria Distasio US DOL: MSHA

Carl Lundgren US DOL: MSHA

Paul Pierce US DOI: USGS

Leslie Coleman National Mining Association

Paul Georgia National Mining Association

Jeremy Richardson Union of Concerned Scientists

Glenn Stoner Colorado Springs Utilities

Carolyn Evans Norfolk Southern Corporation

Natalie Biggs Wood Mackenzie

Greg Marmon Wood Mackenzie

Salem Esber PA Consulting Group

Jamie Heller Hellerworx, Inc.

Charlie Mann Energy Investors Advisors, LLC

John Scmitter KEP LLC

Seth Schwartz Energy Ventures Analysis, Inc.

James Staudt Andover Technology Partners

Boddu Venkatesh ICF International

Jack Ried Seminole Electric Cooperative, Inc.
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Comments on the Carbon Adder and Regional Haze

Several participants sought clarification of questions pertaining to the 3 percent adder to the cost of 

capital for coal capacity additions and retrofits, including the applicability of the adder to emission control 

retrofits, how the adder affects the cost of capital, the basis for the 3% value, and the impact of the adder. 

EIA staff clarified that the adder does apply to retrofits associated with MATS compliance but does not 

apply to carbon capture retrofit equipment. Staff also confirmed that the adder would increase the overall 

cost of capital on a hypothetical basis from 12 percent to 15 percent in the model, and that the original 

concept was derived from the “Carbon Principles” put forth by the financial community several years ago. 

Staff also noted that the 3 percent value is roughly equivalent – when levelized – to about $15 per ton of 

carbon dioxide, which generally corresponds to values many utility planners appear to be assuming in 

their planning decisions. Staff referred participants to the No Greenhouse Gas Concern case that 

removes this additional cost and the model projects more retrofits of FGD scrubbers, less dry sorbent 

injection (DSI), and additional coal plants.

One participant noted that EIA might consider dropping the 3 percent adjustment in future years once EIA 

begins modeling the proposed performance standards for coal plants. EIA will follow up on this issue 

during the review of AEO2015 assumptions once more is known about the EPA NSPS regulations.

Another participant asked if the model includes assumptions regarding the western region BART/regional 

haze regulations. Staff responded that while the regulations are not explicitly covered, any planned 

retrofits at affected plants associated with regional haze are included to the extent they are reported to 

EIA on their survey forms.

Comments on Planned Capacity Additions

Staff confirmed that the planned coal units for AEO2014 have been reported to EIA as under construction 

and are the same as in AEO2013. Several participants commented on the status of specific planned 

capacity additions. 

• Two Elk Power Plant: One participant suggested excluding this plant since it has been ‘under 

construction’ for ten years, and that although the plant has acquired its air permit, the company is

required to satisfy very minor construction requirements in order to maintain it. Staff mentioned 

that EIA did contact the owner of this proposed plant last year, and the owners continued to 

regard the plant as ‘under construction’ at that time. The plant will be included in AEO2014.

• Spiritwood Plant: One participant noted that the latest start date for this plant is 2014 with a 

capacity of 99 MW, rather than the 62 MW assumed by EIA. Staff responded that the plant 

appears to have secured a purchase power agreement for 62 MW. The participant replied that 

since the plant is a cogeneration plant, if EIA is only accounting for the electricity portion of the 

capacity, then the 62 MW capacity value could be correct. Staff will attempt to verify the 

contracted value.

• Taylorville: One participant noted that this plant was recently cancelled by Tenaska. Staff will 

follow up to verify this outcome.

• Medicine Bow: Staff inquired about the size of the Medicine Bow coal-to-liquids (CTL) facility 

of 350 MW. One participant questioned whether the plant planned to sell electricity to the grid, 

to which staff responded that the capacity should include both electricity sold to the grid but also 

electricity for self-use. Staff will attempt to verify the share to be sold to the grid.
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One participant noted that other CTL facilities should not be forced into the model despite the numerous 

press releases regarding such facilities.

Illinois Basin Coal Projections (vs. Northern Appalachia)

Several participants raised concerns about EIA’s projections for production from the Illinois Basin being 

too low based on their expectation of low prices for the commodity relative to coal from other regions and 

ample reserves, even as overall coal demand grows relatively little through 2040. Participants noted that 

plants in the Southeast have recently increased their purchases of Illinois Basin coal and that the region’s 

production could be expected to accommodate an additional 30 million tons per year of sustained 

production within the next 5-10 years. 

The participant then asked if there were limiting factors incorporated into the model with respect to 

Illinois coal. Staff responded that the model is not modeling chlorine or sulfur restrictions for Illinois 

Basin, but noted the possibility that some of the model’s transportation rates could be inadvertently 

prohibiting Illinois Basin growth. Though the staff is not currently aware of any specific limiting 

factors, they will review the model to identify any potential problems. 

Concerns were also raised about the general ability of production from Northern Appalachia to increase 

by the amounts in forecast in the AEO2013 projections. One participant wondered where the growth in 

Northern Appalachian coal could be attributed and stated that the Pittsburgh seam is fundamentally 

different in its cost structure, and it might even have difficulty sustaining its current levels of production. 

The participant stated that the productivity trends are not consistent with the production trends in the 

AEO2013 for Northern Appalachia and Illinois Basin. Another participant noted potential limits with 

regards to the geology and the adequacy of the resource base. The participant also commented that the 

effects of depletion has been outpacing technology trends have been moving in opposite directions in 

some basins including the Powder River Basin, and that longwalls in the Illinois Basin have resulted in 

improvements. 

Staff commented that the model may be opting for Northern Appalachian coal as opposed to the Illinois 

Basin, and the two potential problems may be related. Staff mentioned that we do have a relatively 

negative outlook for productivity in the Northern Appalachian region though not as pessimistic as Central 

Appalachia, and for Eastern Interior (Illinois Basin), we have the most optimistic assumptions. Staff will 

closely review our transportation rates and productivity assumptions for these two regions. 

Staff also acknowledged the large increase in longwalls in Illinois and wondered if anyone had any 

thoughts regarding the use of longwalls in other states in the Illinois Basin. One participant stated that the 

need for large contiguous blocks of coals means that this is a technology that will mainly be used in 

Illinois. Another participant concurred stating it is very unlikely that western Kentucky or Indiana will 

use longwalls, and that the depth of cover (overburden) is really the biggest issue as well as the size of the 

reserve. The participant also mentioned that the limited use of longwalls in these other states has less to 

do with seam thickness and that this does not mean other technologies will not be employed.

Aging Coal Fleet Performance and Replacement

One participant raised a concern regarding high coal capacity factors with a coal fleet whose average age 

is 60 years. The participant acknowledged that EIA models higher O&M costs for its aging coal fleet but 

wondered if more new replacement capacity may be required to meet future demand. In response, 
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another participant disagreed stating that there is no real reason that older units cannot support higher 

capacity factors, but that another problem may be the interaction of coal plants with a larger renewable 

portfolio – in particular wind. The participant explained that since wind runs harder in the off-peak 

periods, coal may expect to be displaced at those times. Staff commented that currently EIA staff is 

looking at updating the spinning reserves methodology in order to handle the intermittency issues.

Metallurgical Coal

One participant suggested that even though it has labor and other cost issues to contend with, Australia is 

geographically and geologically better-suited to supply international coking coal markets than the United 

States and thought that U.S. coking coal exports should decline over the projection rather than holding 

steady as Central Appalachia’s coking coal reserves have high production costs. Staff commented that a 

lot of Northern Appalachian coking coal is currently exported, and asked for comments regarding the 

quality of coal as a consideration since many coking coal consumers regard U.S. coal quality very 

favorably. No feedback was provided on this question.

One participant responded by stating that it was very important to make some sort of assumption 

regarding the future exchange rate even if it is an assumption that does not change, acknowledging that 

EIA would probably need to use some sort of official projection of exchange rates if one existed. Staff 

stated that exchange rates are not currently considered in our modeling of international coal trade, and 

that exchange rate projections are probably not available from the NEMS macroeconomic model.

Side Cases

Staff highlighted that EIA’s side cases in the AEO2013 include greenhouse gas cases and mentioned that 

we see the carbon capture technology preferred for natural gas plants before coal plants in these cases. 

One participant asked if EIA is still assuming that pulverized coal plants with carbon capture technology 

are cheaper than IGCC plants with carbon capture to which staff replied affirmatively. Staff also

responded to an inquiry regarding nuclear capital costs stating that nuclear costs are assumed to be about 

$5400/kW. The participant stated that these costs are based on brownfield sites and asked if staff regard 

these costs to be appropriate in the $25 carbon price case. Staff replied that we still think these costs are 

valid assumptions.