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DATE: July 31, 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 construct ed steam generating EGUs under CAA section 111(b). The EPA finds the final standard of 1,400 lb CO 2 /MWh-g to be achievable over a wide range of variable conditions that are reasonably li kely to occur when the system is properly designed and operated. 1 As discussed elsewhere, the final standard reflect s the degree of emission limitation achievable through the applicat ion of the best system of emission reduction (BSER) which we have determined to be a highly effi cient supercritical pulverized coal (SCPC) unit implementing partial CCS at a level sufficient to achieve the final standard. A SCPC unit utilizing bituminous coal could achieve the BSER wi th partial capture of approximately 16 percent. In determining the predicted cost and perf ormance of such a system, the EPA utilized information contained in updated DOE/NETL studies t hat assumed use of bituminous coal and an 85 percent capacity factor. 2 Here we examine the effects of deviating from thos e 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 d emonstrated over a 12-operatingmonth average. The total CO 2 emissions (pounds of CO 2 ) over 12 operational months are summed and divided by the total gross output (in me gawatt-hours) over the same 12 operational months. Such a compliance averaging per iod 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 generat ing EGU – if constructed – would, most likely, be built to serve base load power demand an d 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 oc cur a few times during the course of a 12-operating-month compliance period. Malfunctions are unplanned and unpredictable events

1 “The DOE/NETL stated that ... ‘Actual average annual emissions from operating plants are likely to be h igher than the design emissions rates shown due to start-up, s hutdown, part-load operation, and performance degra dation through maintenance cycles. Lower design emissions rates to ensure adequate margins may be required fo r 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.’”

2 See ‘Cost and Performance Baselines for Fossil Ene rgy Plants’ reports available at http://www.netl.doe.gov/research/energy-analysis/en ergy-baseline-studies- 2 -

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 E GU can be restarted to operate properly. Short-term and rare excursions would not be expecte d 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 operat ing full CCS at commercial scale since October 2014. In evaluating results from the Mounta ineer slip-stream demonstration, AEP and Alstom reported robust steady-state operation durin g all modes of power plant operation including load changes, and saw an availability of the CCS system of greater than 90 percent. 3,4

Variations in coal type The use of specific coal types can affect the amoun t of CO 2 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 bitumi nous coal from the updated DOE/NETL report. 5 The emission value for the SCPC firing low rank co al came from the DOE/NETL cost and performance for low rank coal – s pecifically from the case of an ultrasupercritical PC (USCPC) burning subbituminous coal

. 6 The EPA then estimated the partial capture needed for the unit firing low rank coal (s ubbituminous coal and dried lignite 7 ) to achieve the 1,400 lb CO 2 /MWh-g standard by assuming that the performance cu rve for such a unit will follow the same slope as the bituminous c oal. The DOE/NETL has not completed a similar partial capture study for units using low r ank coal, but the equipment and configuration
to do so would be the same as the cases evaluated f or bituminous-fired units. Therefore, the EPA believes that this assumption is reasonable. Th e results are shown in Figure 1 and in Table
1 below.

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

4 “Cost and Performance Baseline for Fossil Energy P lants Volume 1a: Bituminous Coal (PC) and Natural Ga s to Electricity, Revision 3”, DOE/NETL-2015/1723 (July 2015) at p. 36 (“[t]he capture and CO 2 compression technologies have commercial operating experience w ith demonstrated ability for high reliability”).

5 “Cost and Performance Baseline for Fossil Energy P lants Supplement: Sensitivity to CO 2 Capture Rate in Coal-Fired Power Plants”, DOE/NETL-2015/1720 (June 2015), Exhi bit A-1, p. 16.

6 “Cost and Performance Baseline for Fossil Energy P lants, Volume 3 Executive Summary: Low Rank Coal and Natural Gas to Electricity”, DOE/NETL-2010/1399 (Se ptember 2011), Exhibit ES-3, p. 5.

7 For a summary of lignite drying technologies see “ Techno-economics of modern pre-drying technologies for lignite-fired power plants” available at www.iea-co al.org.uk/documents/83436/9095/Techno-economics-ofmodern-pre-drying-technologies-for-lignite-fired-po wer-plants,-CCC/241; “Drying the lignite prior to c ombustion in the boiler is thus an effective way to increase the thermal efficiencies and reduce the CO 2 emissions from lignitefired power plants.”- 3 -

Figure 1. CO 2 emission with partial carbon capture for highly ef ficient SCPC firing bituminous
coal and low rank coal

Table 1. CO 2 emissions for highly efficient SCPC with varying l evels 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 CO 2 /MWh-g) (lb CO 2 /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 1,280 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 2 below (Table 8 in the rule’s final preambl e), the predicted range of costs (accounting for uncertainty) remains within the estimated range of costs for the other principal base load, dispatchable non-NGCC generation technologies.

1000 1100 1200 1300 1400 1500 1600 1700 1800

0 5 10 15 20 25 30 35 40 45Emission, lb CO2/MWh-g

CO2 Capture, % bituminous low rank- 4 -

Table 2. Predicted Cost and CO 2 Emission Levels for a Range of Potential New Gener ation Technologies 8 (This is Table 8 in the rule preamble)

New Generation Emission LCOE* Technology lb CO 2 /MWh-g $/MWh SCPC - no CCS (bit) 1,620 76 - 95 SCPC – no CCS (low rank) 1,740 75 - 94

SCPC + ~16% partial CCS (bit) 1,400 92 - 117 SCPC + ~23% partial CCS (low rank) 1,400 95 - 121

Nuclear (EIA) 0 87 - 115 Nuclear (Lazard) 0 92 - 132

Biomass (EIA) 9 - 94 – 113 Biomass (Lazard) - 87 - 116

IGCC 1,430 94 - 120

NGCC 1,000 52 – 86**

The EPA also estimated the increase in capital cost to implement partial CCS to the degree sufficient to meet the final standard of per formance. Again, the EPA used information from the updated partial capture report for the bit uminous cases and adapted information from the report on use of low rank coal for those c ases and assumed that the increases in capital needed for varying levels of partial would follow the same slope for the low rank case as for the bituminous case (see Figure 2 below) 10 . Again, as mentioned earlier, the DOE/NETL has not completed a similar partial capture study for u nits using low rank coal, but the equipment

8 LCOE cost estimates for SCPC and IGCC cases come f rom “Cost and Performance Baseline for Fossil Energ y Plants Supplement: Sensitivity to CO 2 Capture Rate in Coal-Fired Power Plants” DOE/NETL- 2015/1720 (June 22, 2015). Cost and performance for low rank SCPC is adapted f rom “Cost and Performance Baseline for Fossil Energ y Plants Volume 3 Executive Summary: Low Rank Coal and Natura l Gas to Electricity”, DOE/NETL-2010/1399 (Septembe r 2011). LCOE cost estimates for nuclear and biomass are derived from “Levelized Cost and Levelized Avoi d Cost of New Generation Resources in the Annual Energy Outlo ok 2015”, June 2015, www.eia.gov/forecasts/aeo/pdf/electricity_generatio n.pdf. LCOE cost estimates for NGCC technology are EPA estimates based on a range of potential natural gas prices.

9 Table 8 includes LCOE figures for biomass-fired ge neration, a potential sources of dispatchable base load power that is not fueled by natural gas. The EPA includes this information for completeness, while noting th at biomassfired units in operation in the U.S. are smaller sc ale and thus are not as robust analogues as nuclear power. CO 2 emissions are not provided for biomass units becaus e different biomass feedstocks have different net C O 2 emissions; therefore a single emission rate is not appropriate to show in Table 8.

10 The cost of the lignite drying equipment is assume d to be low compared to the cost of the carbon capt ure equipment. Further, pre-drying of the lignite reduc es fuel, auxiliary power consumption and other O&M costs. www.iea-coal.org.uk/documents/83436/9095/Techno-eco nomics-of-modern-pre-drying-technologies-for-lignit efired-power-plants,-CCC/241- 5 -

and configuration to do so would be the same as the cases evaluated for bituminous-fired units. Energy and water use would be expected to be simila r as well since energy and water use are related to taking steam from the process and using it to regenerate the solvent and a similar amount of steam will be utilized regardless of coal type. Therefore, the EPA believes that this assumption is reasonable. The EPA determined that the increase of capital exp ense needed to implement partial capture (21% for the bituminous coal case and 23% f or 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 – incl uding those in the power sector.

Figure 2. Predicted increase in capital expense wit h varying levels of CO 2 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 e missions from operating plants are likely to be higher than the design emissions r ates shown due to start-up, shutdown, partload operation, and performance degradation through maintenance cycles. Lower design emissions rates to ensure adequate margins may be r equired for compliance with future regulations; however, given that the slope of the v ariation of [L]COE with CO 2 emission levels is not steep for either SC PC or IGCC plants (except a t low capture rates), designing for this margin does not have major cost implications.” 11 Because the DOE/NETL reports assume design emission rates for highly efficient SCPC units, the EPA compared those rates against the per formance of recently built units as a means of assessing the reasonableness of the reports’ ass umption. The EPA used emissions and output

11 “Cost and Performance Baseline for Fossil Energy Pl ants Supplement: Sensitivity to CO 2 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 100Increase in Capital, %

CO2 Capture, % bituminous
low rank- 6 -

data from the Clean Air Markets Division (CAMD) Aci d 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 un it 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 3 below. The best monthly emissi on rates (i.e., all CO 2 emissions for the month divided by all gross power output for the mon th) for both facilities are below the design rates used by NETL. The best 12-operating-month ave rages for both facilities are slightly higher than the NETL design rates (1.9 % higher for Longvi ew Power and 0.9 % higher for AEP Turk) which would result in only slightly higher complian ce costs than those provided in Tables 1 and 2 above and would still be within the range of disp atchable, base load generating technologies. The highest 12-operating-month averages for the Lon gview Power plant is about 11% higher than the NETL design – but the Longview Power plant utilizes different steam conditions than NETL assumes in the cost and performance report. Ne wly constructed, properly operated and well maintained bituminous-fired plants that do inc orporate ultra-supercritical technology would expect to achieve better performance than the Longview Power plant. In contrast, the AEP Turk’s highest 12-operating-mo nth average emission is only 4.6% higher than the NETL design – and AEP Turk does inc orporate 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 a chievable at a reasonable cost.

Table 3. 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 – fro m best (lowest) to the highest rate during the facilities’ operation. A comparison to the DOE/NETL design rat e is provide in parenthesis.