1 

### Medina, Dayana

From: Pettyjohn, Mary <PETTYJOHN@adeq.state.ar.us>

Sent: Monday, December 16, 2013 2:38 PM

To: Medina, Dayana

Subject: Domtar & AECC's concern on vendor quotes

Hi Dayana,

I requested Domtar and AECC to send me their concerns on EPA’s request for vendor quotes. Below are their concerns.

Please review.



## AECC Bailey & McClellan:

Mary,

Below is AECC’s draft comment to EPA’s Comment 10 in the August 29, 2013 comments.

This comment addresses the concern we discussed at the RH/BART meeting on Oct. 30, 2013 at ADEQ. The concern is

that AECC is unable to provide further information regarding the vendor quotes requested by EPA for the reasons listed

below.

Regards,

Stephen Cain

Manager

– Environmental Compliance

Arkansas Electric Cooperative Corporation

501.570.2420

NOx Control Case Emission Rates

Comment 10

Section 1.4.1.3 and Table 1

‐ 2 state that based on the estimate provided by Babcock Power Services, the NOx emission

rate expected from the combination of LNB/OFA/FGR is 0.15

– 0.20 lb/MMBtu for both natural gas and fuel oil firing

scenarios. However, the copy of the estimate from Babcock Power Services (Appendix C) indicates that the expected

emission rate is 0.15

– 0.20 lb/MMBtu for natural gas firing, and 0.35 lb/MMBtu for fuel oil firing. Please explain the

inconsistency. We also note that Table 1

‐ 2 indicates the baseline NOx emission rate for Bailey Unit 1 for fuel oil firing is

0.30 lb/MMBtu, which is actually lower than Babcock Power Services’s expected emission rate of 0.35 lb/MMBtu using

LNB/OFA/FGR. Please provide an explanation addressing this.

Response 10

To get an actual guaranteed emission rate from a vendor for an EGU emission control retrofit would take thousands of

dollars and two to three months of vendor analysis. This is because each boiler is different and the vendor must build

virtual models of a boiler and analyze it over multiple scenarios. Also, the vendor realizes that the likelihood of

installation of emission controls on a relatively small EGU with a low capacity factor (such as Unit 1 at Bailey or

McClellan) is very unlikely. So, the vendor has no incentive to spend time and money to develop models and provide

more exact emission limits and costs for a given unit.

With all of this in consideration, the vendor only provided AECC with a range of NOx emission values based on relatively

simple estimates (i.e., “back of the napkin” estimates). AECC has contacted the vendor to provide more information2 after receiving the August 29, 2013 EPA comments, and the vendor has not responded. AECC believes they have not

responded

– and likely will never respond

– due to the reasons listed above.

Regarding the NOx emission estimate for fuel oil firing at Bailey, as mentioned above, the 0.35 lb/MMBTU NOx emission

value is a simple estimate from the vendor. The 0.30 lb/MMBTU NOx emission value for the baseline rate is from several

years of certified CEMS data. The only explanation AECC can give for this discrepancy of the post

‐ controlled NOx

emissions estimates being higher that the pre

‐ controlled NOx emissions is that the vendor did not spend a lot of time

looking at the data AECC submitted to them. Again, the vendor is not going to spend much time on this issue because

they believe there is a very slim chance of controls being installed on units with such low capacity factors.



## Domtar:

Domtar has struggled from the beginning of this process to find controls vendors willing to provide a detailed level of

cost or emissions estimates. The information we have been able to obtain is largely incomplete and inaccurate.

(Example: Lundberg’s incorrect claim that no additional feed water would be necessary.) We assume this is the case

because they judge that it is not an efficient use of their time to consider the control options before us (listed below)

because they know that ultimately there is little to no chance of them completing a sale:

 Adding another scrubber downstream of an existing, well

‐ operating scrubber.

 Spending hundreds of hours (and money), not to mention months of delay, to find upgrades to an existing

scrubber to potentially squeeze another fraction of a percent of efficiency.

 Adding SNCR to a wood

‐ fired, swing

‐ load boiler.

................................................................................................................ Jeremy Jewell, CM

Principal and Manager of Consulting Services for Oklahoma

Best wishes,

Mary

Mary Pettyjohn

Epidemiologist

Arkansas Department of Environmental Quality

Air Division

5301 Northshore Drive

North Little Rock, AR 72118

‐ 5317

Phone: 501

‐ 682

‐ 0070

Email: pettyjohn@adeq.state.ar.us