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EPA Assessment of the Oregon Department of Environmental Quality 

Determination of Best Available Retrofit Technology for the PGE Coal Fired 

Power Plant in Boardman, Oregon

Introduction

As part of the Oregon Regional Haze Plan, the Oregon Department of 

Environmental Quality (DEQ) made a Best Available Retrofit Technology (BART) 

determination for the PGE coal-fired power plant in Boardman, Oregon. EPA 

promulgated guidelines for BART determinations under the regional haze rule in 

Appendix Y of 40 CFR Part 51. The Appendix Y guidelines are required to be 

followed for BART determinations for fossil fuel fired power plants having a 

capacity in excess of 750 megawatts (MW) [40 CFR § 51.308(e)(1)(ii)(B)]. Since 

the capacity of the Boardman power plant does not exceed 750 MW, DEQ was 

not specifically required to follow the Appendix Y guideline. However, DEQ 

stated that they opted to follow the guidelines for the sake of national 

consistency. 

This EPA assessment of the Boardman BART determination is based on 

the document entitled “Oregon Regional Haze Plan for Implementing Section 308 

(40 CFR § 51.308) of the Regional Haze Rule” adopted by the Environmental 

Quality Commission June 19, 2009, Revised December 9, 2010. The Boardman 

BART reports prepared by DEQ are contained in Appendix D of this document. 

The EPA assessment focused on Appendix D-7 which contains the Addendum to 

the DEQ BART Report for the Boardman Power Plant (November 30, 2010). 

The Appendix D-7 Addendum provides DEQ’s BART analysis for the proposal

made by PGE that includes closure of the plant no later than December 31, 

2020.

The PGE coal fired power plant near Boardman, Oregon commenced 

construction in 1975 and began operation in 1980. The single unit at the 

Boardman plant is a Foster Wheeler dry bottom opposing wall fired design with 

first generation low NOx burners and overfire air. To date only low sulfur (~0.3% 

by weight) sub-bituminous coal from the Power River Basin in Wyoming has 

been burned in the boiler. The coal is delivered by train, unloaded to a coal pile, 

conveyed to pulverizers, blown into the furnace with heated combustion air and 

burned in the furnace. The heat from combustion is transferred to water in boiler 

tubes within the furnace and economizer to produce high pressure steam that is 

used to drive a steam turbine connected to a generator to produce electricity. 

The unit is designed to burn 350 tons of coal per hour to produce approximately 

617 MWe of electricity (gross). According to data reported by PGE to the EPA 

Clean Air Markets Division, the maximum heat input capacity of the Boardman 

unit is 6438 million Btu per hour.
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Critique of the DEQ BART Determination

Capital Cost Estimates

As explained in Appendix D-1, DEQ contracted with ERG to review the 

costs provided by PGE for the various control technologies. Although the ERG 

cost estimates were lower than the estimates provided by PGE, DEQ concluded 

that the two estimates were close enough to accept the higher PGE cost 

estimates for the purpose of conducting the cost effectiveness analyses. In 

addition, the PGE cost estimates included two capital cost line items that are not 

normally included when using the EPA OAQPS Control Cost Manual which 

Appendix Y of the EPA guidelines for BART states should be used where 

possible (Appendix Y, II.A.4.a.5). The net effect of these decisions is that the 

estimated capital costs are likely at the high end of the range for capital cost 

estimates.

NOx Controls

In Appendix D-7 (page D-169) DEQ determined that new (upgraded) low 

NOx burners with overfire air technology (LNB) is considered BART because the 

technology is cost effective and provides significant visibility improvement (>1 dV 

in Mt. Hood wilderness area). Although the technology option of LNB plus 

selective non-catalytic reduction (SNCR) was cost effective ($1816/ton of NOx

removed), DEQ rejected this technology option because it only provided an 

additional 0.18 dV of visibility improvement compared to LNB alone and because 

of concerns about excess ammonia emissions (commonly referred to as 

ammonia slip) which may result in increased rates of secondary particulate 

matter in the form of ammonium sulfate. As shown in the Control Effectiveness 

table on page D-168 of Appendix D-7, the NOx emission reduction attributed to 

SNCR was only 17% (0.19 lb/MMBtu for LNB plus SNCR compared to 0.23 

lb/MMBtu for LNB alone). SNCR is capable of achieving a higher NOx emission 

reduction than 17%, with a 25% NOx emission reduction a reasonable 

expectation. However, even at 25% NOx emission reduction, the incremental 

visibility improvement will not exceed 0.5 dV, the value that appears to be the 

criterion used by DEQ to justify requiring a cost effective control option beyond 

LNB. However, in the event that the LNB alone can not achieve the BART 

emission limit of 0.23 lb/MMBtu, the DEQ rules include a contingency to comply 

with the limit by 7/1/2013 instead of 7/1/2011 to allow time for PGE to install a 

SNCR system to reduce the emissions to the presumptive BART limit. 

SO2 Controls

In Appendix D-7 (page D169) DEQ determined that dry sorbent injection

(DSI) is considered to meet the BART requirements because it is cost effective

($2295 -$3370/ton of SO2 removed) and will provide significant visibility 

improvement (>0.5 dV) in at least the Mt. Hood wilderness area. In the earlier 
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DEQ BART analyses (Appendix D-1 and D-6) DEQ determined that semi-dry flue 

gas desulfurization (SDFGD) represented BART for SO2. The cost effectiveness 

value that DEQ calculated for SDFGD was $5535/ton of SO2 removed. The 

incremental cost effectiveness of SDFGD compared to DSI is about $7200/ton of 

SO2 removed. DEQ stated that SDFGD is not considered to meet the BART 

requirements because it is not cost effective considering closure of the plant in 

2020. This is a different conclusion than in Appendix D-6 for the same 2020 

closure date. 

Although not specifically highlighted in the Appendix D-7 report 

addendum, two other factors appear to have contributed to the change in 

conclusion regarding whether SDFGD represents BART. One factor is that the 

SDFGD option requires a capital investment of over $270 million compared to a 

much lower capital investment of about $23 million for DSI. Even though the 

capital cost is factored into the cost effectiveness value calculation (through the 

use of a capital recovery factor based on a 7% interest rate and the life of the 

project), the acquisition of and deployment of capital is an important factor for 

PGE. Given a plant closure date of 2020 and the fact that a SDFGD system 

could not be implemented until 2014, the commitment of $270 million would be a 

significant deterrent for PGE. The second factor is that the incremental visibility 

improvement between the SDFGD option and the DSI option with the lower SO2

reduction (DSI-1) is 0.4 dV. If the DSI-2 option can achieve a SO2 limit of 0.30 

lb/MMBtu, the incremental visibility improvement between SDFGD and DSI-2 is

0.26 dV. In both cases the incremental visibility improvement is less than 0.5 dV, 

the value which is marginally detectable by human observers and the value 

which DEQ appears to have used as a criterion for whether a control option 

should be chosen instead of the next most effective control option.

In order to test the sensitivity of the cost effectiveness value for SDFGD, 

EPA calculated the cost effectiveness value for SDFGD after reducing the capital 

cost by eliminating the two line items not normally included by the OAQPS 

Control Cost manual method. The two line items are owner’s cost and allowance 

for funds used during construction. The cost effectiveness calculation is shown 

in Figure 1. Making this revision to the capital cost reduced the cost 

effectiveness value for the SDFGD option to $4810/ton of SO2 removed. If the 

control effectiveness of the SDFGD control option is increased from 80% (the 

value used in the DEQ analysis) to 90% (a value that represents the highest 

expected control effectiveness for this technology), the cost effectiveness value 

for the SDFGD option is further reduced to about $4300/ton of SO2 removed. 

The second sensitivity calculation assumes that the SDFGD option could achieve 

90% SO2 removal at the same capital cost as that used for the DEQ analysis. 

This may not be a valid assumption, but will result in a lower cost effectiveness 

value for the purpose of the sensitivity test. A cost effectiveness value less than 

$5000/ton of SO2 removed may well be considered reasonable for a BART 

determination. If visibility improvement is directly proportional to the emission 

rate, then the incremental visibility improvement between the 90% SDFGD 
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control option and DSI-1 would be marginally greater than 0.5 dV. The 

incremental visibility improvement between the 90% SDFGD control option and 

DSI-2 would still be less than 0.5 dV. However, as discussed above the 

magnitude of the required capital cost and the relatively small incremental 

visibility improvement, may influence the BART decision in favor of the DSI 

control option.

Other comments on Appendix D-7

There appears to be two typos related to the plant closure date on pages 

D-167 and D-169 where the text reads December 31, 2010 instead of December 

31, 2020.

In the table titled “Cost Effectiveness” on page D-168, the capital and total 

annualized cost for the SDFGD control option do not agree with the values in the 

BART COST DATA – 2020 CLOSURE table on page D-179. The capital cost 

should be $270,218,000 and the total annualized cost should be $66,349,000. 

The total annualized cost for the three DSI control options should be $17,482,000 

instead of $17,541,000. The cost effectiveness values shown in the table on 

page D-168 correctly correspond to the values for the total annualized costs 

stated above.