U.S. Energy Information Administration Independent Statistics & Analysis www.eia.gov

NEMS Modeling of Coal Plants

Office of Electricity, Coal, Nuclear, and Renewable Analysis

Laura Martin

June 14, 2016 Washington, DC
2

EMM Structure

EFD

ECP

EFP

ELD

Laura Martin

Washington, DC, June 14, 2016

Electricity Load 

and Demand 

Submodule

Liquid Fuels 

Market Module
Model inputs for coal plants

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• Existing coal plants – plant specific inputs 

– Fixed and variable operating and maintenance costs, annual capital additions

– Retrofit costs (capital and O&M) – FGD, DSI, SCR, SNCR, CCS, FF

– Cost to convert to natural gas-fired steam plant

– Cost to implement heat rate improvement

– Average heat rate and capacity factor, based on historical data

• All existing coal plants are assumed to have same annual 

cost adder after 30 years to address aging

• New coal plants – only one new technology that is 111(b) 

compliant is modeled for AEO2016

– Overnight cost, heat rate, operating costs, carbon removal (30%)

Laura Martin

Washington, DC, June 14, 2016
Existing coal configurations

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Laura Martin

Washington, DC, June 14, 2016

Sulfur dioxide Particulate NOX post-combustion control

Existing 

capacity 

(MW)

none baghouse Any (or none) 16,308

wet FGD baghouse Not SCR 19,758

wet FGD baghouse SCR 15,774

dry FGD baghouse Any (or none) 28,655

none cold-side ESP Any (or none) 67,305

wet FGD cold-side ESP Not SCR 38,722

wet FGD cold-side ESP SCR 89,823

dry FGD cold-side ESP Not SCR 3,808

none other (i.e. hot-side ESP) or none Any (or none) 6,212

wet FGD other/None Not SCR 3,902

wet FGD other/None SCR 2,847

- No plants are assumed to have existing dry-sorbent injection (DSI), but after 2016 in the model, 

any plant remaining in the 'unscrubbed' category will have had a DSI added. 

- Plants will switch configurations during a model run as equipment is projected to be added.

- Additional plant types representing adding supplemental fabric filter or carbon capture are also 

modeled.
Capacity Factor and Capital Cost Assumptions

Laura Martin

Washington, DC, June 14, 2016 5

• Maximum Capacity Factor Assumptions

– In the first model year, the maximum capacity factor a coal unit may run at is set to the 

greater of either the actual, previous 5-year average capacity factor or 60%

– If the maximum capacity factor in the first year is less than or equal to 75%, it increases 

linearly each year towards 75% by 2025, where it remains through 2040

– If the actual, previous 5-year average capacity factor is already at or above 75%, the 

maximum capacity is set to that value and stays there throughout the forecast

• Annual Capital Cost Assumptions (in 2015 dollars) 

– The average annual capital additions for existing plants are $20 per kilowatt (kW)-year for 

coal plants, $8 per for oil and gas steam plants, and $23 for nuclear plants regardless of 

age

– Beyond 30 years of age an additional $7 per kW-year capital charge for fossil plants and 

$34 for nuclear plants is included in the retirement decision to reflect further investment to 

address the impacts of aging
Environmental rules modeled in AEO2016

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• Mercury and Air Toxics Standard (MATS)

– Enforced in 2016, model requires coal plants to have a scrubber or a DSI/FF 

combination to meet HCl and particulate controls

– Combinations of environmental controls and/or activated carbon injection can 

be used to meet mercury removal requirements

– If plants do not have sufficient equipment, or it is uneconomic to invest in 

required equipment, they are retired

• Cross State Air Pollution Rule

– Regional SO2 and NOX constraints, generally non-binding due to MATS

• Regional greenhouse gas rules

– RGGI – Northeast states

– AB32 - California

Laura Martin

Washington, DC, June 14, 2016
Clean Power Plan included in AEO2016

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• Clean Power Plan is implemented in the EMM at the 

electricity region levels, assuming cooperation within a region

• Model can implement either EPA’s average emission 

standard (rate-based) targets or mass-based targets; 

AEO2016 Reference case assumes all regions use massbased targets, including new sources to avoid leakage

• Alternative cases will be available in final AEO2016 that use 

rate-based standard, assume greater cooperation among 

regions, and that vary the allowance allocation assumption

Laura Martin

Washington, DC, June 14, 2016
Electricity model components

Laura Martin

Washington, DC, June 14, 2016 8

• Electricity Capacity Planning (ECP) – multi-year linear programming 

structure

– Solves each model year, optimizing over 30 years for planning of long term investment decisions

– Makes build, retrofit and retirement decisions for next future year

– Includes expectations for future demand, fuel prices and environmental regulations if appropriate

– Uses plant specific inputs, but can aggregate into larger groups to minimize model size

• Electricity Fuel Dispatch (EFD) – single year linear program

– Solved every iteration of every model year, to respond to changes in demand, fuel prices and 

other information passed from other parts of NEMS

– Models dispatch at more detailed plant level than ECP

– Environmental regulations that are heavily dependent on re-dispatch options are modeled directly 

in both the EFD and ECP (CPP, regional CO2 and SO2)

– Rules that are more reliant on build/investment decisions are modeled as constraints only in the 

ECP, and costs are passed to the EFD (renewable portfolio standards, NOX constraints)

– Provides final projections for generation and consumption
ECP – Objective Function

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• Minimizes total discounted present value of construction, operating 

(fuel/O&M), and transmission costs of meeting demand while complying 

with environmental regulations for a given model year. The objective 

function is in millions of nominal dollars

• Construction costs evaluated over 30 year economic life, assuming 

financing with 45% debt/55% equity; roughly 8% nominal discount rate

• Retrofit costs are evaluated over 20 year economic life, using regulated 

cost of capital inputs that can vary by region

• Annual operating costs and capital additions are fixed over time, other than 

the one time increase for aging (which is then held constant)

• Fuel price expectations based on previous model run are used for fuel 

costs in projected years

Laura Martin

Washington, DC, June 14, 2016
ECP retirement decision

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• MATS compliance – in 2016 the ECP must determine whether a plant is 

compliant with MATS, and if not, what controls or level of activated carbon 

injection must be used; alternate model vectors are created for each 

configuration of the plant, with the appropriate costs added to the objective 

function. If a MATS compliant configuration is not chosen by the LP 

solution, then the plant is retired.

• In later projection years, the ECP continues to evaluate plant retirements 

based on economics. The ECP contains constraints for demand, capacity 

reserve margins and operating reserves, and coal plants can contribute to 

each. If an existing coal plant is no longer needed to meet these 

constraints (i.e. enough other lower-cost capacity is available or it is 

cheaper to build something new), then it is retired. The plant must also 

have been marked by the EFD in the previous year as not covering costs 

with revenues.

Laura Martin

Washington, DC, June 14, 2016
EFD – Objective function and demand requirements

Laura Martin Washington, DC, June 

14, 2016 11

• Minimizes total operating (fuel and variable O&M) costs of meeting annual demand 

while complying with environmental regulations for a given model year. 

– Fixed costs and investment costs are not included in the EFD linear program

– Available capacity and plant configurations are updated each model year based on the 

ECP decisions

• Demand is characterized by a load curve of 9 time slices, solved simultaneously

– Three seasons, of four months each

– Each season contains three segments of varying lengths of time to represent both peak, 

intermediate and baseload demand periods

– Coal plants cannot operate in peak-only time slice, but may be dispatched in the peak / 

intermediate, or peak / intermediate / base combinations

– Additional operating modes created to contribute to spinning reserves that can result in 

load-following behavior or minimum generation output

– Current operating costs and heat rate is constant for a plant regardless of operating mode, 

this is being evaluated for future modification
EFD – Dispatch decisions

Laura Martin Washington, DC, June 

14, 2016 12

• Demand: electricity demand must be met in each time slice and region, through allocating 

existing plants in the region or trading with neighboring regions

• Spinning reserves: specific levels of operating plants must be available to provide spinning 

reserves in each time slice and region

• Emission constraints – SO2 and CO2: Emission caps on these pollutants are modeled as strict 

constraints in the EFD. Detailed fuel supply curves are incorporated in the LP to allow for fuel 

switching between coal types, or from coal plants to natural gas-fired plants, as needed to meet 

the constraint. Costs of complying with the constraints will flow through directly to the energy cost 

of meeting demand.

• Emission constraints - NOX: Because complying with NOx is primarily a capital cost decision, the 

EFD does not model NOx caps directly. The allowance price calculated by the ECP is passed to 

the EFD, and the cost is added to the operating cost of a plant, based on its emission rate.

• Renewable portfolio standards: Similarly, the ECP builds renewable capacity to meet RPS 

requirements, and passes the EFD the credit price, which is added to the operating costs for 

plant types that need to purchase credits
NEMS EMM operating mode-variant heat rate feature 

(currently under development)

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Laura Martin

Washington, DC, June 14, 2016

• NEMS EMM is not capable of capturing performance impacts associated with cycling behaviors 

exhibited by many coal plants today under various operating modes, which can affect projections 

of capacity factor, fuel consumption, and emission. NEMS uses generator specific five-year 

averaged annual heat rates which do not vary over different operating modes available.

• A study was conducted in 2015 by Leidos to develop a methodology to calculate operating modevariant heat rates based on thermal efficiency in conjunction with studying actual hourly data 

found in data source such as the EPA CEMS database.

– The study was focused on 35 coal units in Georgia and New York, and found that daily cycling modes for 

individual units was evident in data from 2011-2014

– The study found that the effect of daily average gross load on the predicted inverse heat rates is relatively 

clear

• A follow-up task with OnLocation has been started to implement algorithms to calculate heat rate 

adjustment factors for the different operating modes within the EMM

– Likely implementation level will be by EMM region and coal plant configuration
AEO2016 electricity results

14

Laura Martin

Washington, DC, June 14, 2016
Laura Martin 

Washington, DC, June 14, 2016

Natural gas generation falls through 2021; both gas and renewable generation 

surpass coal by 2030 in the Reference case, but only natural gas does so in the 

No CPP case

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0

500

1,000

1,500

2,000

2,500

1990 2000 2010 2020 2030 2040 2020 2030 2040

AEO2016 Reference No CPP

History 2015 2015

Nuclear

Petroleum

Natural gas

Coal

Renewables

net electricity generation

billion kilowatthours

Source: EIA, Annual Energy Outlook 2016
annual capacity retired, gigawatts

Laura Martin 

Washington, DC, June 14, 2016

The Mercury and Air Toxics rule (MATS) rule and low natural gas prices are 

the main near-term driver of coal plant retirements; CPP increases near-term 

coal plant retirements modestly and adds more retirements in later years 

0

10

20

30

40

50

2000 2005 2010 2015 2020 2025 2030 2035 2040

History Projections

No CPP 

AEO2016 Reference

History Projections

0

10

20

30

40

50

2000 2005 2010 2015 2020 2025 2030 2035 2040

Coal Natural Gas/oil

Source: EIA, Annual Energy Outlook 2016

16
Average capacity factor for coal-fired generating units falls by 15 percentage 

points by 2030 in the Reference case when compared with the No CPP case 

capacity factor of central station coal-fired electricity generating units

percent utilization

Source: EIA, Annual Energy Outlook 2016

Laura Martin 

Washington, DC, June 14, 2016

0%

10%

20%

30%

40%

50%

60%

70%

80%

2005 2010 2015 2020 2025 2030 2035 2040

No CPP

AEO2016 Reference

History 2015 Projections

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18

Cumulative coal capacity (GW) versus age (years)

Source: EIA, Annual Energy Outlook 2016

Laura Martin

Washington, DC, June 14, 2016

Average age of coal fleet increases significantly between 2015 and 2040

0

10

20

30

40

50

60

70

80

90

100

0 50 100 150 200 250 300

2015 average age = 39

2040 average age = 57

Age 

(years)

Cumulative coal capacity
For more information

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Laura Martin

Washington, DC, June 14, 2016

Annual Energy Outlook www.eia.gov/aeo

Assumptions to the AEO http://www.eia.gov/forecasts/aeo/assumptions/index.cfm

NEMS Model Documentation 

http://www.eia.gov/reports/index.cfm?t=Model%20Documentation