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EPA Assessment of the Oregon Department of Environmental Quality Determination of Best Available Retrofit Technology for the PGE Coal F ired

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 no t 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 o n 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 W heeler dry bottom opposing wall fired design with first generation low NO x 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 pre ssure 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 EP A Clean Air Markets Division, the maximum heat input capacity of the Boardman unit is 6438 million Btu per hour.2

Critique of the DEQ BART Determination

Capital Cost Estimates

As explained in Appendix D

- 1, DEQ contracted with ERG to review the costs pr ovided by PGE for the various control technologies. Although t he 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 OAQ PS Control Cost Manual which Appendix Y of the EPA guidelines for BART states should be used wh ere possible (Appendix Y, II.A.4.a.5). The net effect of these decisions i s that the estimated capital cost s are likely at the high end of the range for capital cost estimates.

NO x Controls

In Appendix D

- 7 (page D

- 169) DEQ determined that new (upgrad ed) low NO x 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 no n

- catalytic reduction (SNCR) was cost effective ($1816/ton of NO x 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 emis sions (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 NO x emission reduction attribu ted 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 NO x emission reduction than 17%, with a 25% NO x emission reduction a reasonable expectation. However, even at 25% NO x 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 a chieve 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.

SO 2 Contr ols

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 SO 2 removed) and will provide significant visibility improvement (>0.5 dV) in at least the Mt. Hood wilderness area. In the earlier3

DEQ BART analyses (Appendix D

- 1 and D

- 6) DEQ determined that semi

- dry flue gas desulfurization (SDFGD) represented BART for SO 2 . The cost effectiveness value that DEQ calculated for SDFGD was $5535/ton of SO 2 removed. The incremental cost effectiveness of SDFGD compared to DSI is about $7200/ton of SO 2 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 S DFGD 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 SO 2 reduc tion (DSI

- 1) is 0.4 dV. If the DSI

- 2 option can achieve a SO 2 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 effectivene ss 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 SO 2 removed. If the control effectiveness of th e 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 SO 2 removed

. Th e second sensitivity calculation assumes that the SDFGD option could achieve 90% SO 2 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 effe ctiveness value for the purpose of the sensitivity test. A cost effectiveness value less than $5000/ton of SO 2 removed may well be considered reasonable for a BART determination. If visibility improvement is directly proportional to the emission rate, th en the incremental visibility improvement between the 90% SDFGD4

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. Howev er, 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 typ os 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.