Oklahoma DEQ BART Analyses - FWS thoughts about OK 's final 

determinations

Meredith_Bond to: Joe Kordzi 07/19/2010 03:47 PM

Cc: "Copeland, Scott", Bret A Anderson, jlogan, John_Bunyak, 

Patricia_F_Brewer, Don_Shepherd, Tim_Allen, Dean_Gillam

History: This message has been replied to.

Joe,

Per the conversations you have had with me and others in my office, I am providing the following observations 

regarding the final BART determinations contained in the Oklahoma Regional Haze SIP (as posted on the State’s 

website, and submitted to EPA earlier this year – the BART determinations are cited as January, 2010). We note as 

an overarching comment that the State’s BART determinations for the OG&E units identified below changed 

considerably from the versions that the State shared with the Federal Land Management agencies during Fall, 2009.

We have specifically looked at the SO2 BART determinations for the following coal-fired electric generating units: 

OG&E’s Muskogee Units #4 and #5, OG&E’s Sooner Units #1 and #2 and AEP-PSO’s Northeastern Units #3 and 

#4. Our comments relate only to the Dry Flue Gas Desulfurization (Dry FGD) – Spray Dry Absorption (SDA) SO2

control alternative, since in all cases it was deemed to be more cost-effective than the Wet FGD alternative. 

In all cases the control efficiency of Dry FGD – SDA was underestimated, with the final determinations identifying 

0.1 lb/MMBtu for the OG&E units, and 0.153 for the AEP-PSO units. This technology can attain an emission rate 

of 0.065 lb/MMBtu on a 30-day rolling average (example: achieved by Newmont Nevada Energy Investment, LLC 

in Eureka County, Nevada and permitted by the State of Nevada with an emission limit of 0.065 lb. SO2/MMBtu 

when burning Powder River Basin Coal, the same fuel used by all of these Oklahoma facilities). 

We recalculated cost per ton estimates using the achievable emission rate for Dry FGD - SDA technology applied to 

Powder River Basin coal. For the Muskogee and Sooner units the costs originally ranging from $6,348 - $7,493 

(per the final BART determination) now become $5,715 - $6,521. This may still be somewhat high for BART. 

However, for AEP-PSO’s Northeastern combined Units #3 and #4 the cost was reduced from $3,294/ton to 

$2,939/ton. This cost-effectiveness might be considered to be in the reasonable range. Note that these figures only 

account for the emission rate correction – the discussion that follows concerns the cost figures that go into that 

calculation, and may further reduce the $/ton results for these units.

The second consideration is that the total capital investment for the units seems excessive. More definitive 

information should be provided as to how the cost estimates were developed and the timeframe during which they 

were developed. According to the POWER magazine survey of “What’s That Scrubber Going to Cost?” (

http://www.powermag.com/business/Update-Whats-That-Scrubber-Going-to-Cost_1743.html) costs of flue gas

desulfurization unit construction increased an average of 28% from the survey of 2006 costs to the survey of 2008

costs. But, since 2008 there have been decreases in world carbon steel, copper and energy prices and in the

Department of Labor Employment Cost Index. For these reasons, it is expected that costs of current construction of

FGD units would have decreased significantly since 2008. 

That said, even in 2008, when the costs for these units peaked, the Total Capital Investment for scrubber units 

ranged from $359 - $471/kW. However, the Total Capital Investment contained in Oklahoma’s final BART 

determinations is substantially higher: Muskogee – $555/kW, Sooner – $514/kW, and Northeastern –$ 582/kW. 

The final BART determinations lacked any presentation of unique circumstances or extraordinary constraints that 
would explain why the Oklahoma units were far more expensive in terms of capital cost. 

We were also unclear as to why the total tons of SO2 reduced for the units changed significantly between the 

9/28/2009 Oklahoma DEQ BART Application Analysis and the 1/15/2010 BART Application Analyses, while the 

total capital investment costs only declined slightly. As an example, the September, 2009, report for OG&E 

Muskogee identified 15,122 and 16,202 tons SO2 per year reduced for units 4 and 5, respectively. The January, 

2010, BART report showed the two units reducing 6,953 and 6,846 tons SO2 per year. This represents a 56% 

change in the tons per year projected to be controlled. But, both used per-unit capital investment cost that declined 

less than 15%, from $372M to $317M, between the two versions. Changing the tons of SO2 controlled with little 

change in the control cost significantly increases the resulting cost per ton calculations. The OG&E Sooner data 

parallels this same shift between the September, 2009, and January, 2010, BART Application Analyses.

Though adjustments would be needed to account for different unit sizes, some comparable units that have estimated 

Dry FGD costs are: Great River Energy – Coal Creek North Dakota, Great River Energy – Stanton North Dakota, 

PacifiCorp – Dave Johnston #3 & #4 Wyoming and PacifiCorp – Wyodak Wyoming. We can provide information 

about these facilities’ BART analyses and control cost estimations if it would be helpful.

If you would like to discuss our thoughts further, please give me a call, or contact Dean Gillam directly 

(303-914-3805). 

 -- Meredith

______________________________

CAPT Meredith Bond, P.E., USPHS

 Deputy Chief

U.S. Fish and Wildlife Service

Branch of Air Quality

7333 W Jefferson Ave., Suite 375

Lakewood, CO 80235

 303-914-3808

 303-969-5444 fax

Meredith_Bond@fws.gov

______________________________