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DATE: July 21, 2015

SUBJECT: Achievability of the Standard for Newly Constructed Steam Generating EGUs

TO: Rulemaking Docket ID: EPA-HQ-OAR-2013-0495

This memorandum describes the achievability of the final standard of performance for 

greenhouse gas (GHG) emissions from newly constructed steam generating EGUs under CAA 

section 111(b).

The EPA finds the final standard of 1,400 lb CO2/MWh-g to be achievable over a wide 

range of variable conditions that are reasonably likely to occur when the system is properly 

designed and operated. As discussed elsewhere, the final standard reflects the degree of 

emission limitation achievable through the application of the best system of emission reduction 

(BSER) which we have determined to be a highly efficient supercritical pulverized coal (SCPC) 

unit implementing partial CCS at a level sufficient to achieve the final standard – for such a unit 

utilizing bituminous coal that would be approximately 16 percent. In determining the predicted 

cost and performance of such a system, the EPA utilized information contained in updated 

DOE/NETL studies that assumed use of bituminous coal and an 85 percent capacity factor.1

Here we examine the effects of deviating from those assumed operational parameters on the 

achievability of the final standard of performance. 

Operational fluctuations, start-ups, shutdowns, and malfunctions

Importantly, compliance with the standard must be demonstrated over a 12-operatingmonth average. The total CO2 emissions (pounds of CO2) over 12 operational months are 

summed and divided by the total gross output (in megawatt-hours) over the same 12 

operational months. Such a compliance averaging period is very forgiving of short-term

excursions that can be associated with non-routine events such as start-ups, shutdowns, and 

malfunctions. A new fossil fuel-fired steam generating EGU – if constructed – would, most 

likely, be built to serve base load power demand and would not be expected to routinely startup or shutdown or ramp its capacity factor in order to follow load demand. Thus, planned startup and shutdown events would only be expected to occur a few times during the course of a 

12-operating-month compliance period. Malfunctions are unplanned and unpredictable events 

and emission excursions can happen at or around the time of the equipment malfunction. But a 

malfunctioning EGU that cannot be operated properly should be shut down until it the 

malfunctioning equipment can be addressed and the EGU can be restarted to operate properly. 

 

1

See ‘Cost and Performance Baselines for Fossil Energy Plants’ reports available at 

http://www.netl.doe.gov/research/energy-analysis/energy-baseline-studies
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Short-term and rare excursions would not be expected to affect a 12-operating-month rolling 

emission average.

The post-combustion capture systems that have been utilized have proven to be 

reliable. The Boundary Dam facility has been operating full CCS at commercial scale since 

October 2014. In evaluating results from the Mountaineer slip-stream demonstration, AEP and 

Alstom reported robust steady-state operation during all modes of power plant operation 

including load changes, and saw an availability of the CCS system of greater than 90 percent. 2,3

Variations in coal type

The use of specific coal types can affect the amount of CO2 that is emitted from a new 

coal-fired power plant. The EPA utilized studies by the DOE/NETL to predict the cost and 

performance of new steam generating units. 

The EPA used emission values for SCPC firing bituminous coal from the updated 

DOE/NETL report.4The emission value for the SCPC firing low rank coal came from the 

DOE/NETL cost and performance for low rank coal – specifically from the case of an ultrasupercritical PC (USCPC) burning subbituminous coal.5

The EPA then estimated the partial 

capture needed for the unit firing low rank coal (subbituminous coal and dried lignite6) to 

achieve the 1,400 lb CO2/MWh-g standard by assuming that the performance curve for such a 

unit will follow the same slope as the bituminous coal. The DOE/NETL has not completed a 

similar partial capture study for units using low rank coal, but the equipment and configuration 

to do so would be the same as the cases evaluated for bituminous-fired units. Therefore, the 

EPA believes that this assumption is reasonable. The results are shown in Figure 1 and in Table 

1 below.

 

2

http://www.alstom.com/press-centre/2011/5/alstom-announces-sucessful-results-of-mountaineer-carboncapture-and-sequestration-ccs-project/. 

3

“Cost and Performance Baseline for Fossil Energy Plants Volume 1a: Bituminous Coal (PC) and Natural Gas to 

Electricity, Revision 3”, DOE/NETL-2015/1723 (July 2015) at p. 36 (“[t]he capture and CO2 compression 

technologies have commercial operating experience with demonstrated ability for high reliability”).

4

“Cost and Performance Baseline for Fossil Energy Plants Supplement: Sensitivity to CO2 Capture Rate in Coal-Fired 

Power Plants”, DOE/NETL-2015/1720 (June 2015), Exhibit A-1, p. 16.

5

“Cost and Performance Baseline for Fossil Energy Plants, Volume 3 Executive Summary: Low Rank Coal and 

Natural Gas to Electricity”, DOE/NETL-2010/1399 (September 2011), Exhibit ES-3, p. 5.

6

For a summary of lignite drying technologies see “Techno-economics of modern pre-drying technologies for

lignite-fired power plants” available at www.iea-coal.org.uk/documents/83436/9095/Techno-economics-ofmodern-pre-drying-technologies-for-lignite-fired-power-plants,-CCC/241; “Drying the lignite prior to combustion in 

the boiler is thus an effective way to increase the thermal efficiencies and reduce the CO2 emissions from lignitefired power plants.”
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Figure 1. CO2 emission with partial carbon capture for highly efficient SCPC firing bituminous 

coal and low rank coal

Table 1. CO2 emissions for highly efficient SCPC with varying levels of partial capture – for 

units firing bituminous coal and low rank coal 

Capture Bituminous Low Rank Bituminous Low Rank

% LCOE LCOE Emission Emission

($2011/MWh) ($2011/MWh) (lb CO2/MWh-g) (lb CO2/MWh-g)

0 82.3 80.8 1,618 1,737

16 99.1 98.0 1,400 1,504

22 103.7 101.7 1,300 1,417

23 103.9 102.4 - 1,400

29 107.5 106.0 1,200 1,316

35 111.4 109.7 1,100 1,228

39 113.3 112.1 1,050 1,170

The EPA has evaluated those costs and finds them to remain reasonable. As shown in 

Table 8 in the rule’s final preamble, the predicted range of costs (accounting for uncertainty) 

remains within the estimated range for the other principal base load, dispatchable non-NGCC 

generation technologies. 

The EPA also estimated the increase in capital cost to implement partial CCS to the 

degree sufficient to meet the final standard of performance. Again, the EPA used information 

from the updated partial capture report for the bituminous cases and adapted information 

from the report on use of low rank coal for those cases and assumed that the increases in 

capital needed for varying levels of partial would follow the same slope for the low rank case as 

1000

1100

1200

1300

1400

1500

1600

1700

1800

0 5 10 15 20 25 30 35 40 45

Emission, lb C

O2/M

Wh-g

CO2 Capture, %

bituminous

low rank
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for the bituminous case (see Figure 2 below)7. Again, as mentioned earlier, the DOE/NETL has 

not completed a similar partial capture study for units using low rank coal, but the equipment 

and configuration to do so would be the same as the cases evaluated for bituminous-fired units. 

Energy and water use would expect to be similar as well. Therefore, the EPA believes that this 

assumption is reasonable.

The EPA determined that the increase of capital expense needed to implement partial 

capture (21% for the bituminous coal case and 23% for the low rank coal case) is reasonable 

because, as discussed in the final preamble for the rule, these costs are reasonably consistent 

with capital cost increases in previous NSPS – including those in the power sector.

Figure 2. Predicted increase in capital expense with varying levels of CO2 capture (%) a highly 

efficient SCPC firing bituminous and low rank coal

Comparison to Emission Rates from Existing EGUs

The DOE/NETL stated that ... “Actual average annual emissions from operating plants 

are likely to be higher than the design emissions rates shown due to start-up, shutdown, partload operation, and performance degradation through maintenance cycles. Lower design 

emissions rates to ensure adequate margins may be required for compliance with future 

regulations; however, given that the slope of the variation of [L]COE with CO2 emission levels is 

not steep for either SC PC or IGCC plants (except at low capture rates), designing for this margin 

does not have major cost implications.”8

 

7

The cost of the lignite drying equipment is assumed to be low compared to the cost of the carbon capture 

equipment. Further, pre-drying of the lignite reduces fuel, auxiliary power consumption and other O&M costs. 

www.iea-coal.org.uk/documents/83436/9095/Techno-economics-of-modern-pre-drying-technologies-for-lignitefired-power-plants,-CCC/241

8

“Cost and Performance Baseline for Fossil Energy Plants Supplement: Sensitivity to CO2 Capture Rate in CoalFired Power Plants”, DOE/NETL-2015/1720 (June 2015) at p. 4.

0

10

20

30

40

50

60

70

80

0 20 40 60 80 100

Increase in Capital, %

CO2 Capture, %

bituminous

low rank
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Because the DOE/NETL reports assume design emission rates for highly efficient SCPC 

units, the EPA compared those rates against the performance of recently built units as a means 

of assessing the reasonableness of the reports’ assumption. The EPA used emissions and output 

data from the Clean Air Markets Division (CAMD) Acid Rain Program database and identified 

Longview Power’s Plant (a 700 MW SCPC unit in West Virginia that began operations in 2011) 

and AEP’s John W. Turk Jr. Plant (a 609 MW USCPC unit in Arkansas that began operations in 

2012) as the best performing units using bituminous and low rank coal respectively. The results 

are given in Table 2 below. The best monthly emission rates (i.e., all CO2 emissions for the 

month divided by all gross power output for the month) for both facilities are below the design 

rates used by NETL. The best 12-operating-month averages for both facilities are slightly higher 

than the NETL design rates (1.9 % higher for Longview Power and 0.9 % higher for AEP Turk) 

which would result in only slightly higher compliance costs than those provided in Table 1 

above (and in Table 8 jn the final rule preamble) and would still be within the range of 

dispatchable, base load generating technologies. The highest 12-operating-month averages for 

the Longview Power plant is about 11% higher than the NETL design – but the Longview Power 

plant does not utilize the ultra-supercritical steam conditions that NETL assumes in the cost and 

performance report. Newly constructed, properly operated and well maintained bituminousfired plants that do incorporate ultra-supercritical technology would expect to achieve better 

performance than the Longview Power plant. 

In contrast, the AEP Turk’s highest 12-operating-month average emission is only 4.6% 

higher than the NETL design – and AEP Turk does incorporate the ultra-supercritical steam 

conditions assumed in the NETL reports. Therefore, even over the range of operating 

conditions for these best performing actual plants, the EPA finds the final standard of 

performance of 1,400 lb/MWh-g is achievable – and achievable at a reasonable cost.

Table 2. Best performing recently constructed SCPC EGUs 

Best Best Highest

Monthly 12-Month Avg 12-Month Avg

Unit Coal-type Rate* Rate* Rate*

Longview Power bituminous 1,578 1,648 (1.9%) 1,801 (11.3%)

John W. Turk Jr. subbituminous 1,725 1,753 (0.9%) 1,817 (4.6%)

* The rates are given in lb CO2/MWh-g. The range of 12-operating-month average rates are provide – from best 

(lowest) to the highest rate during the facilities’ operation. A comparison to the DOE/NETL design rate is provide in 

parenthesis.