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WORKING GROUP SUMMARY FOR DISCUSSION PURPOSES.     

DO NOT QUOTE OR CITE AS RESULTS ARE SUBJECT TO CHANGE.

       October 7, 2016

MEMORANDUM FOR: Ian Mead

Assistant Administrator for Energy Analysis

Jim Diefenderfer

Office Director

Office of Electricity, Coal, Nuclear, and Renewables Analysis

Paul Holtberg

Team Leader

Analysis Integration Team

FROM: Chris Namovicz

Team Leader for Renewable Electricity Analysis Team

SUBJECT: Summary of AEO2017 Electricity, Coal, Nuclear, and Renewables 2nd

Working Group Meeting held on October 3, 2016

PRESENTERS:    Chris Namovicz, Thad Huetteman, Greg Adams

ATTENDEES: 16 EIA, 76 external (list provided following meeting summary)

This working group meeting was the second of two for the upcoming Annual Energy Outlook (AEO2017).  

Presentation topics included a discussion of key updates to electricity, coal, nuclear and renewables

model assumptions.   

Renewables  

EIA reviewed the most significant modeling changes for renewables technologies that have been

completed – including better regional breakouts of solar costs and updated solar performance

assumptions.  DG modeling and solar curtailment algorithm updates are to be completed by mid‐

October.  Energy storage modeling has been postponed until AEO2018.

A participant asked what extent EIA had looked at updating wind learning.  EIA clarified that because

AEO2017 will be a shorter version, learning assumptions were not significantly revised.  Consistent with
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WORKING GROUP SUMMARY FOR DISCUSSION PURPOSES.     

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history, wind capital costs experience a low decline rate.  However, wind does receive additional

learning through capacity factors which leads to an opportunity for significant cost reduction.

A participant wondered if this was the case even without PV curtailment?  EIA noted that PV curtailment

will contribute even more.

A participant asked what renewables subsidies EIA is assuming.  EIA staff explained the renewable

subsidies that are current legislation are modeled (i.e., the production tax credit (PTC) and investment

tax credit (ITC)).  The ITC phases out from 30% reaching 10% by 2022. In addition, many states also have

renewable portfolio standards (RPS), but in the model, these are consolidated into larger regions.  New

for AEO2017, the Internal Revenue Service (IRS) rule for wind designating a four year construction

profile has been incorporated even though the model assumes a three year construction lead time.

Many in the industry state that it takes only six months to 2 years to construct a wind facility.  

Preliminary results show wind builds shifted out one year (compared to AEO2016) due to the May 2016

IRS ruling.  Wind builds subside after the PTC expires in 2022, but pick back up post‐2035.   

A participant commented that the relative contribution of wind‐to‐solar feels ‘off’.  Especially because

solar costs today are slightly more expensive.  Maybe for AEO2018, EIA could look at the forecast for

cost reduction assumptions and compare regional deployment?” EIA responded that we are trying to

get a better handle on this with PV curtailment modeling work currently underway.  Also, the near‐term

PTC‐expiration drives the front‐loading of wind builds.  Additionally, distributed solar generation is

included in these results.  The model does not include the Levelized Avoided Cost of Electricity (LACE).  

Solar is broadly available and has more room to grow – that is, it has more mid‐day value (when wind

doesn’t).   

Another phone participant inquired if there was a technological lifetime assumption for wind and

whether or not wind retirements would be expected as we approach 2050.  EIA noted that there is not a

technological lifetime assumption for wind.  There is not much historical experience with wind plants

after 30 years of operation.  In looking at wind plants from the 1980’s, some have retired, some have

repowered, and some have replaced equipment.   At this point, there’s no reason to believe that there

will be mass retirements of wind plants after 30 years of operation.  The implicit model assumption is

that it is cheaper to maintain infrastructure than build new facilities.  EIA plans to evaluate the impacts

of aging generating resources in the future.

A participant asked if there are any assumptions about energy storage.  EIA informed the group that

more detailed modeling of energy storage has been delayed until AEO2018.  Currently, the AEO

represents pumped storage as it currently operates (generally charging at night when electricity is

cheaper, and running during the day).  However, EIA does not currently model pumped storage as a

capacity expansion option for this AEO.

A participant posed two questions “With huge renewables expansion is there a transmission assumption

associated with that?” and “As market share grows in wind‐oriented areas, are you assuming that

transmission assumption goes away?” EIA clarified that transmission cost assumptions are included
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WORKING GROUP SUMMARY FOR DISCUSSION PURPOSES.     

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along with wind builds.  EIA is also looking to apply the higher‐resolution PV‐curtailment algorithm to

wind for AEO2018.

Another participant wondered if LACE was used for solar expansion.  EIA noted that LACE was derived

from the model results.

Another participant inquired as to how solar capacity expansion was calculated. EIA described that the

solar capacity expansion was determined using linear programming.

Natural Gas Prices

EIA clarified that natural gas price is a model result, not an assumption.  AEO2017 prices increase post‐

2040 perhaps because of a supply‐demand issue.  EIA doesn’t expect final results to be significantly

different from the preliminary results presented at this meeting.

Electricity Sales

EIA stated that post‐2040 electricity sales in AEO2017 generally follow the same trajectory and growth

rate as the sales for AEO2016 prior to 2040.

A participant on the phone asked if electricity sales included an offset from distributed generation. EIA

clarified that sales do not include self‐generated electricity.

A participant wondered why the slope of electricity sales was faster after 2035.  EIA explained that

sector growth overtakes any additional savings after 2035 because future efficiency standards aren’t

reflected yet.  Current efficiency standards are only being modeled for the near term (through 2035); we

only model federal equipment efficiency standards that are currently in effect or set to go into effect on

a specific date.  Standards are generally specified for 6‐year interval, and the latest standards that we

implement in our technology menus are in 2023.  Beyond specific standards, we do assume that there is

some efficiency improvement and/or cost reduction based on research and development trends

through the projection.  In addition, we assume improvements to building heating and cooling shell

efficiency with the continuing adoption of more recent building energy codes.

Electricity Generation Mix

A phone participant asked if EIA could talk about the oscillation between coal and gas share.  EIA

explained that gas prices and the Clean Power Plan (CPP) are driving fuel economics.  As gas prices rise,

coal recovers early in the projection, but when the CPP takes effect, gas generation surpasses coal.
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WORKING GROUP SUMMARY FOR DISCUSSION PURPOSES.     

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Another participant inquired why renewable and natural gas generation increase faster than the

decrease in nuclear generation.  EIA clarified that it is caused from a combination of demand increasing

as well as decreasing nuclear generation.  More renewable and gas generation occurs partly as a

replacement to nuclear generation but the increase in demand also contributes to the incremental

growth in these fuels sources.  It is important to distinguish between the capacity additions and the

resulting generation when discussing the growth of renewables and gas.

Nuclear  

A participant asked if nuclear retirements are evenly spread. EIA noted that most 60‐year licenses expire

around 2030.  The capacity decrement is applied evenly across all plants modeled as generic derates and

tied to license expiration dates to address the uncertainty of reactors achieving a subsequent license

renewal  from approximately 2030 onward, with most of the retirements occurring by 2040.   

A phone participant wondered how solar could replace retiring baseload nuclear capacity.  EIA explained

the preliminary results show solar and natural gas capacity come online as nuclear plants retire (less

natural gas capacity is needed relative to solar, since natural gas generation has a higher  capacity

factor).  The low natural gas prices allow for more gas additions, but these plants are also used more

intensively.  In addition, because of the modification to the model that allows coal plant’s heat rate to

change based on operating mode, coal plants may be fully utilized.  The capacity factor for solar is much

lower than for the other sources of generation.  Though the model builds the capacity, there is not

necessarily a commensurate increase in generation.  The model is not generating electricity from solar in

a 1:1 relationship with the generation lost from nuclear.

A participant asked how EIA accounts for the mismatch between regions where the nuclear retirements

occur and the regions where solar resources exist, stating that the locations where nuclear is threatened

are not necessarily the places with the best solar resources.  EIA clarified that solar economics are driven

by demand that ample solar resources exist.  Also, seasonal regional resource availability is accounted

for in the model.  Each region has solar potential and if the economics support solar it can be built.   

Another participant inquired if there were plans to make nuclear uprates endogenous.  EIA stated that

nuclear uprates are linked to specific regulatory actions and are specific to particular nuclear units.   

There are plans to develop an adjunct feeder model that may, in the future, drive retirements

endogenously.
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WORKING GROUP SUMMARY FOR DISCUSSION PURPOSES.     

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Coal

A participant wondered why CO2 emissions are lower but there are not as many coal retirements.  EIA

noted that the dip in CO2 emissions came from a combination of lower capacity factors coupled with

updated heat rates for coal plants.  

A phone participant asked if age was a factor when determining the retirement of coal plants.  EIA

clarified that age was not a factor and that model retirements were strictly based on economics

Another phone participant wanted more detail on the new heat rate operation mode such as, “Is

ambient temperature included?” and “Do you make any distinction between the type of coal used (e.g.

lignite or subbituminous)” EIA explained that there are six separate heat rate adjustments that can be

made in each season based on six different operating modes:  Max generation on 3 segments, Max

generation on 2 segments, Load following (cycling) on 3 segments, Load following (cycling) on 2

segments, Minimum generation (max spinning reserve) on 3 segments, Minimum generation (max

spinning reserve on 2 segments.  Also, effects of the change in ambient temperature among seasons are

reflected in the heat rate adjustments. However, the methodology does not explicitly take coal type into

consideration.

Attendees

Webex In person Last Name First Name Organization 

  Adams Greg EIA 

  Boedecker Erin EIA 

  Bowman Michelle EIA 

  Conti John EIA 

  Daniels David EIA 

Diefenderfer James EIA 

  DonohooVallett Paul DOE 

  Gulen Gurcan beg.utexas 

  Hodge Tyler EIA 

  Huetteman Thaddeus EIA 

  Jell Scott EIA 

  Johnson Elias EIA 

  Kearney Diane EIA 

  Khair Lauren NRECA 

  Macy Cara EIA 
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WORKING GROUP SUMMARY FOR DISCUSSION PURPOSES.     

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  Marmon Greg woodmac 

  Mayes Fred EIA 

  Mead Ian EIA 

  Peterson David EIA 

  Purdie Mike NEI 

  SlaterThompson Nancy EIA 

 Alfaro Jose alphanr 

 Angielski Shannon VNF 

 Arguello Ed CSU 

 Augustine Chad NREL 

 Baca Justin SEIA 

 Blumenfeld Andy archcoal 

 Bowles Mark C Entergy 

 Bowles Mark SBC global 

 Bratvold Delma leidos 

 Brewer John NETL 

 Caravaggio Michael EPRI 

 Clausen Scott ACORE 

 Cole Wesley NREL 

 Digiantommaso Jen OCFO 

 Dougherty Ryan Geothermal Exchange 

Organization 

 Evans Carolyn nscorp 

 Eyster Jerry GE 

 Fix John leidos 

 Goggin Michael AWEA 

 Gresham Lee brattle 

 Hanson Don ANL 

 Harrison Keith southernco 

 Hensley John AWEA 

 Herndon Whitney Rhodium 

 Hewson Tom evainc 

 Holmes Mike undeerc 

 Kislear Jordan DOE 

 Kwon Augustine EIA 

 Leff Michael Con Edison 

 Lewandowski Dave OneEnergyWind 

 Luckow Patrick Synapse 

 Lundgren Carl DOL 

 Mai Trieu NREL 

 Manzagol Nilay EIA 
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WORKING GROUP SUMMARY FOR DISCUSSION PURPOSES.     

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 Nethercutt Elliott NERC 

 Nichols Christopher NETL 

 Nowak Seth ACEEE 

 Park Brian EIA 

 Peters Jamie UP 

 Pierce Paul USGS 

 Reyes Jorge dep.nj 

 Roberts Ricky EPRI 

 Roche Madelyn NRECA 

 Rosner David DOE 

 Salmi Chris dep.nj 

 Satsangi Ann DOE 

 Sattler Sandra UCS 

 Schmalzer David ANL 

 Serpil Kayin EPA 

 Shawn Rumery SEIA 

 Shenk Brian USACE 

 Showalter Sharon On Location 

 Smith Alexander FERC 

 Somerday Michele firstenergycorp 

 Stansky Michael firstenergycorp 

 Steinberg Helen GE 

 Steinberger Kevin NRDC 

 Stevens Bill EPA 

 Strohfus Mark grenergy 

 Sutton Jim GE 

 Theis Joel NETL 

 Tsai Chenhao beg.utexas 

 Tucker Russell NRECA 

 Tusing Rich DOE 

 Venkatesh Boddu ICFI 

 Walsh Ken leidos 

 White Larry MHPowerSystems 

 Wise James dep.nj 

 Wiser Ryan LBL 

 Wos Thomas tristategt 

 Wright Evelyn SEE 

 Wyes Tesfaye OCFO 

 Zelek Charles NETL 

 Zhao Song leidos 
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WORKING GROUP SUMMARY FOR DISCUSSION PURPOSES.     

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 Zummo Paul publicpower