October 24, 2012

MEMORANDUM FOR: John Conti

Assistant Administrator for Energy Analysis

Alan Beamon

Office Director

Office of Electricity, Coal, Nuclear, and Renewables Analysis

Paul Holtberg

Team Leader

Analysis Integration Team

FROM: Electricity Analysis Team

SUBJECT: Summary of the 2nd AEO2013 Electricity Working Group 

Meeting, held on October 11, 2012 

ATTENDEES: Michelle Adams (EIA OEA)

Alan Beamon (EIA OEA)

*Aaron Bergman (DOE: PI)

Bill Booth (EIA OES)

*Erin Boyd (DOE: PI)

Gwen Bredehoeft (EIA OEA)

*Thomas Cochran (NRDC)

*Jarad Daniels (DOE: FE)

Jim Diefenderfer (EIA OEA)

Vlad Dorjets (EIA OES)

Bob Eynon (EIA OEA)

Tyler Hodge (EIA OEA)

*David Hunter (EPRI)

Ayaka Jones (EIA OEA)

Jeffrey Jones (EIA OEA)

Diane Kearney (EIA OEA)

*Sikander Khan (DOE: FE)

*Jordan Kislear (DOE: FE)

Mike Leff (EIA OEA)

*Jennifer Li (DOE: PI)

Laura Martin (EIA OEA)

Carrie Milton (EIA OEA)

Chris Namovicz (EIA OEA)

Sam Napolitano (EIA OEA)

*Chris Nichols (NETL)
Marie Rinkoski Spangler (EIA OEA)

*David Shoeberlein (DOE: PI)

WEBEX

ATTENDEES: *Justin Adder (DOE: NETL)

*John Brewer (DOE: NETL)

*Dan Chartier (EEI)

*Kyler Gates (Westinghouse)

* Gürcan Gülen (University of Texas)

*Eric Holdsworth (EEI)

*Jennifer Macedonia (BPC)

*David Schmalzer (Argonne)

*Sharon Showalter (OnLocation)

*Bill Stevens (EPA)

*Glenn Stoner (City of CO Springs Dept. of Utilities/ NCTA)

*Frances Wood (OnLocation)

*Evelyn Wright (DecisionWare)

*David Young (EPRI)

*Non-EIA Attendees

Presenter: Carrie Milton

Topics covered included key changes in AEO2013 compared to the AEO2012 reference case, 

including coal plant retirements, planned capacity additions for all technology types, generation 

shares by fuel types, fuel prices, and electricity demand growth. The key modeling assumptions 

for AEO2013 were addressed, including (1) full replacement of CSAPR with CAIR and the 

corresponding impacts on the coal fleet and natural gas generation, (2) extending the projection 

through 2040, (3) incorporation of updated capital costs for new technologies in the model and 

the resulting impact on endogenous capacity additions, (4) nuclear uprates and retirements 

assumed in addition to reported uprates and retirements, (5) and reported nuclear planned 

additions included in the forecast. Carrie Milton presented the preliminary results via 

PowerPoint to those in attendance and via WebEx.

 

Specific discussion relevant to electricity markets:

1. Carrie Milton explained the main assumptions in place for the AEO 2013 that have the 

biggest impact on the forecast as compared to the AEO 2012 reference case. These included 

the implementation of MATS in 2016 and updated capital costs for new technologies. 

Capital costs for generating technologies decreased by more than 10% for wind, solar 

photovoltaic, and natural gas combined cycle and increased more than 10% for IGCC and 

IGCC with carbon capture and sequestration.

2. After viewing the AEO 2013 total electricity demand compared to the AEO 2012 electricity 

demand, a participant asked, “Do you have confidence limits around your input 

assumptions? Why do you present no confidence limits or uncertainties around your 

projections?” Alan Beamon responded that this is something that EIA considers, and is why 
EIA analyzes side cases. Side cases are developed to effectively describe such uncertainties. 

The AEO Early Release, published later this year, will include the Reference case, while the 

full AEO will be released in the spring, with all of the side cases. 

3. Carrie Milton demonstrated how the fuel price changes for natural gas (lower throughout the 

AEO 2013 forecast) and coal (higher throughout the AEO 2013 forecast) for the electric 

power sector led to lower coal generation and higher gas generation, in general, throughout 

the AEO 2013 forecast. This led to a larger discussion on the gas prices, which came up 

repeatedly throughout the presentation. A participant argued that gas prices should not be 

increasing at the rate seen in the forecast, and that if one hundred years of historical price 

information were evaluated we would see that fuel prices in general remain constant in real 

terms. Chris Namovicz pointed out that if we were to look at the past twelve years, there has 

been a tremendous drop in gas prices, but the same participant replied that twelve years is 

not long enough to develop a trend in prices. The participant again suggested that EIA 

should use 100 year averages for fossil fuel commodities. Alan Beamon responded that EIA 

would take that into consideration.

4. Two participants questioned what the main drivers were for the higher gas prices throughout 

the forecast and Alan Beamon replied that over time current gas plays become less 

productive and that plays available in the future may be more expensive to develop. He 

mentioned that there is a lot of uncertainty in this area, and that EIA will be running several 

sensitivity cases with gas prices for the full AEO 2013 report. Alan Beamon mentioned that 

prices in 2012 were at record low levels. One of those participants did not have a problem 

with upward price projections, given that the current low prices were not sustainable from a 

producer’s prospective. Alan Beamon recommended that the natural gas team could provide 

more insight, since the electricity team receives the gas prices from their model. Mike Leff 

added that EIA sees increased demand from the electric power and industrial sectors which 

contributes to the upward push on prices.

5. Carrie Milton explained how removing CSAPR from the assumptions led to a shift in the 

timing of coal plant retirements between AEO2012 and AEO2013. She illustrated that in the 

reference case for the AEO 2012, a large amount of coal capacity was retired in 2013, when 

CSAPR was assumed to go into effect. In the AEO 2013, in general, the same amount of 

coal capacity is retired throughout the forecast, but 2016 is the year that most retirements 

occur, coincident with the assumed implementation year for MATS. Carrie pointed out that 

a combination of factors led to the coal plant retirement decisions, including the lower gas 

prices, higher coal prices, and reduced demand, in addition to the environmental regulations. 

Alan Beamon emphasized that EIA is not claiming that CSAPR was specifically responsible 

for the coal plant retirements, but rather it influenced the timing of owners’ decisions 

concerning whether to continue to operate or retire the plants. Alan Beamon pointed out that 

switching from CSAPR to CAIR did not result in more or less actual retirements, but pushed 

back retirements to the MATS compliance deadline. Since CSAPR was more costly to 

comply with in the short term, Alan postulated that including CSAPR in the assumptions for 

the AEO2012 resulted in some instances of plants retiring earlier, prior to making 

investments to comply with MATS in the future. 

6. A participant asked, “When looking at coal retirements, do you consider equipment at 

individual plants?” Jim Diefenderfer affirmed that EIA does look at each individual unit and 

its corresponding environmental controls. He explained that EIA attaches individual types

of equipment to the generators to obtain a very precise unit-level equipment configuration 
for each individual generator. The same participant pointed out that a recent Brattle Group 

assessment projects higher coal retirements—59 GW by 2020 and wanted to know how that 

compared to EIA’s model. Mike Leff answered that EIA has seen the Brattle study and that 

EIA analysts are currently working to compare the results and assumptions of the study with 

those of the AEO 2013 reference case. In broad strokes, it appears that EIA’s assumptions 

match Brattle Group’s “low” case. Alan Beamon mentioned that EIA often compares its

results with other studies; however that exercise can be frustrating because the level of detail 

supporting the underlying study assumptions that EIA would like to evaluate is typically not 

available.

7. A participant asked how EIA models reliability requirements and reserve margin targets. 

Jeff Jones answered that reserve margins—the percentage of capacity required in excess of 

peak demand needed for unforeseeable outages—are determined within the model through 

an iterative approach that compares the marginal cost of capacity and the cost of unserved 

energy. The target reserve margin is adjusted in each model cycle until the two costs 

converge. 

8. In response to a slide indicating the compliance actions taken in the MATS year in the AEO 

2012 as compared to the AEO 2013, a question was asked why there are fewer DSI and FGD 

installations in the AEO 2013 as compared to the AEO 2012. Carrie Milton had pointed out 

earlier that in the AEO 2012, there were fewer retirements in the MATS implementation year

(2015), because more plants had retired in an earlier year, due to the assumed 

implementation of CSAPR in 2013. Alan Beamon noted that in the AEO 2012, which 

included CSAPR, retirement decisions were being made in an earlier year with MATS in 

mind, although retirement decisions are based on several factors, only one of which is 

environmental regulations. Since more retirements are occurring in the MATS 

implementation year for AEO 2013, fewer scrubbers and DSI retrofits are needed to bring 

the approximately 90 GW of unscrubbed capacity into compliance. 

9. A participant asked, “What are the new assumptions around possible MATS compliance 

actions?” Jeff Jones mentioned that they are the same as last year, and that a fabric filter is 

still required in tandem with DSI to comply with the rule. Mike Leff added that if a plant 

has no scrubber, it can either retire, install an FGD, or install DSI. A follow-up question was

asked as to whether EIA allows wet and dry scrubbers or only dry scrubbers. Mike Leff 

replied that for compliance EIA only allows for wet scrubbers. Jim Diefenderfer mentioned 

that there is also a difference in how EIA treats MATS compliance actions for petroleumfired generating units for AEO2013. Some petroleum-fired units will be installing 

electrostatic precipitators (ESP) while others will switch from burning residual fuel oil to 

distillate fuel oil. Carrie Milton further added that for AEO2013 petroleum coke plants also 

need to install a dry scrubber in order to comply with MATS.

10. A participant questioned whether there are any changes in the DSI cost assumptions, to 

which Mike Leff replied that EIA is using the same cost assumptions as for the AEO 2012. 

One attendee inquired whether coal plants could comply without installing a DSI or 

scrubber, for instance by burning coal with a lower chlorine content. Jeff Jones indicated 

that while EIA does not currently consider this in the model, it is certainly something that 

EIA could consider for AEO 2014. Another attendee wondered whether EIA requires fabric 

filters with DSI. Jeff Jones replied that, “Yes, we require fabric filters to be added with the 

DSI compliance option. Activated carbon injection can be used to reduce mercury without a 
fabric filter, but is not as economic.” EIA requires the fabric filter to reduce other pollutants 

that are not explicitly modeled in NEMS, namely HCl and PM2.5. 

11. Carrie Milton discussed how the renewable generation by specific technology type varied 

between the forecast in 2035 for the AEO 2012 and AEO 2013, as well as how it changed 

significantly between 2035 and 2040 in the current forecast. Chris Namovicz added that 

wind generation this year has been particularly sensitive to changes in gas prices and that 

NEMS runs completed since the 10/4 run ( presented for this meeting) have shown greater 

wind generation. A participant questioned whether the AEO 2012 also assumed the 

expiration of the renewable technology production and investment tax credits, to which Mike 

Leff responded that it did. Another participant asked whether there will be a side case on 

extended tax credits. Alan Beamon affirmed that there would be. A participant asked 

whether the solar in the chart represented both rooftop and utility-scale projects, to which 

Chris Namovicz replied that it did.

12. During the discussion on capacity additions in the AEO 2013 compared to the AEO 2012, 

Carrie Milton pointed out that during the last five years of the forecast EIA sees a lot of 

natural gas and renewable technology additions. Alan Beamon indicated that when gas 

prices hit about $7/MMBtu, i.e. in the last 5-6 years of the projection period, other 

technologies become economic to build even without incentives. A participant asked 

whether the natural gas additions were mainly combined cycle. Alan Beamon replied that 

the natural gas additions are largely to support baseload, but there are also some peakers 

added as well. Natural gas capacity additions are split between combined cycle and 

combustion turbines, with the turbines mainly added for reserve purposes, and not to meet 

demand growth. A participant inquired as to how EIA models the interaction between 

natural gas prices and capacity additions, specifically in order to understand why the higher 

gas prices toward the end of the forecast did not stimulate more coal additions. Alan 

Beamon answered that gas plants are the most flexible source of new capacity in that they 

can meet intermediate and peak loads that might be needed, as well as baseload. Mike Leff 

added that the capital cost of a new coal plant is approximately $2,900/kW while a natural 

gas combined cycle plant is approximately $1,000/kW. Therefore, even with the higher fuel 

prices, gas still may be cheaper on a levelized basis. Alan Beamon indicated that the 

competition for capacity additions between coal and natural gas may become quite 

interesting in the 10-15 year range after the projection period.

13. Questions pertaining to the 111(b) regulation (New Source rule that would limit new coal 

builds to those with CCS) were brought up. A participant asked whether EIA assumes this 

in the reference case. Mike Leff and Jeff Jones explained that since the rule has not yet been 

finalized, it is not part of the reference case. The same participant followed up by asking 

whether it will be part of the AEO if the rule is finalized before the full release of the AEO

2013. Alan Beamon said that it likely would not, since only 1 GW of coal is being built in 

2039.

14. A participant asked how EIA is handling the 316(b) rule. Mike Leff answered that EIA is not 

including it in the AEO 2013 reference case, and will likely not include it in any side cases.

15. The last discussion slide, which illustrated the CO2 emissions over the forecast in AEO 2013 

as compared to AEO 2012, opened a discussion as to what assumptions are made around the 

CO2 regulations. Laura Martin indicated that EIA includes the Regional Greenhouse Gas 

Initiative (RGGI) and California Assembly Bill 32 (AB32), as well as a 3 percentage point 
cost of capital adder on new coal plants without sequestration. Because the New Source 

Rule is not finalized, it is not included. 

16. A participant asked about some of the electricity demand drivers. Alan Beamon mentioned 

that efficiency gains in appliances and larger households play a role, and that the ResidentialCommercial Demand team could answer in more detail. The same participant followed up 

with a question about EIA’s assumptions regarding electric vehicles and demographic shifts, 

to which Alan Beamon responded that transportation and end-use demand are modeled 

outside of the electric power modules. Alan indicated that EIA models electric vehicles, but 

the uptake is small, and that EIA also models an increasing number of people per household 

over the forecast. The participant followed up with a question as to whether EIA’s numbers 

for electric demand growth are national. Mike Leff and Jeff Jones explained that EIA 

models demand regionally, by census division.