Atmospheric Sciences Group

1

MEMORANDUM

To: Jeff Peltola, CENRAP

From: Gregory Stella, Alpine Geophysics, LLC

Re: Cost Curve Comments and Action Taken

Date: 9 February 2007

On Thursday, January 25, 2007, I received seven State submitted comments from you and Lee 

regarding the control cost curves “no control” spreadsheet I provided to you on Tuesday, January 

16, 2007. Through the course of the next week, additional revisions and comments were

submitted with the final arriving on Thursday, February 8. The following States provided 

comments:

ÿ Iowa

ÿ Kansas

ÿ Louisiana

ÿ Minnesota

ÿ Missouri

ÿ Nebraska

ÿ Oklahoma

ÿ Texas

Although the original intent of the spreadsheet was for States to review the source list and 

identify (1) which units identified with a control efficiency (CE) of 0% would be subject to 

incremental control or (2) those units with a positive CE are assigned appropriate reduction 

values, comments not relevant to either of these two intents were submitted. To the extent that 

those additional comments are relevant to this control cost curve application project, they are 

addressed here.

Iowa

Matthew Johnson submitted a commented version of the original spreadsheet for consideration. 

On the SO2 table, only one modification was noted, the assignment of a CE to the

MIDAMERICAN ENERGY CO. - COUNCIL BLUFFS unit CBEC4. Matthew notes that this 

unit is already controlled with lime spray dryer flue gas desulfurization and therefore should 

have a high CE value assigned. For SO2, a 90% will be assigned to this unit in the 2018 Base 

Case consistent with the application of controls during the original Alpine Control Cost 

Analysis1 (Table 6-6 of that document). This unit also has a number of combustion and postcombustion controls (SCR) which would indicate a high CE for NOx, as well. For NOx, a 90% 

value will be assigned consistent with Alpine’s earlier assignment (Table 6-7).

Three additional units were commented upon for augmentation of NOx CE values based on 

engineering judgment. Using Table 6-7 of the Alpine report, a 60% reduction will be assigned to 

 

1

 “CENRAP REGIONAL HAZE CONTROL STRATEGY ANALYSIS PLAN,” prepared by Alpine Geophysics, 

LLC, May 9, 2006.
 Atmospheric Sciences Group

2

IPSCO STEEL, INC., unit 147508, and a 94% reduction will be assigned to EMERY STATION 

points #11 and #12. 

Kansas

Lynn Deahl submitted a commented version of the original spreadsheet for consideration.

This spreadsheet provided a list of 2005 emissions, expected BART units, and other

identification information related to the units on the originally distributed list. No modifications 

requests were present in the e-mail transmittal or in the spreadsheet itself although one unit 

(Kansas City P&L in Linn County) was identified to be installing SCR in 2007 (note – under 

BART). This modification was made per the section “BART Subject Units” below. Other units 

identified as “Subject to BART” were reviewed for purposes of modification to allow

incremental controls to be applied, but no identifiable changes were found to include them in the 

incremental cost curves. No action was taken on units in Kansas.

Louisiana

Darlene Dosher-Collard submitted a commented version of the original spreadsheet for

consideration.

On the SO2 table, no comments were provided which appeared to require control efficiency 

modification to units in the State. Some of the comments listed as “Our EI shows this as a retired 

NEDS” had the intent of requiring a retirement of this unit from the 2018 Base Case (i.e., make 

all emissions = 0). This comment was assigned by Louisiana to twelve (12) units in the table. 

Follow up exchanges with Ms. Dosher-Collard clarified that only a select number of the units 

identified by this comment should be retired and for the list below, NOx and SO2 emissions in 

the file used to generate the cost curve spreadsheets were zeroed out.

Cabot Corporation/Canal Plant, units 15, 16, 22, 23, 28, 29, 31, 32, 45, 47, & 48

Lyondell Chemical Co/ Lake Charles unit 43

American Iron Reduction unit 02

On the NOx table, two comments were provided which appeared to require modification; both 

comments indicated rescinded permits and facility closures. These two facilities and all

points/units located at them (AMERICAN IRON REDUCTION/AIR DRY and LYONDELL 

CHEM CO/LAKE CHARLES PLNT) will be removed from the file from which the control cost 

curves will be derived. Other comments provided in the spreadsheet indicated uncertainty in 

specific unit existence (“This point source is not present in our EI data and can not id in a 

permit”). No action was taken on these comments.

Minnesota

Mary Jean Fenske submitted a commented version of the original spreadsheet for consideration.

On the SO2 table, two units were identified as having control in the 2018 Base Case, both which 

are currently reflected as having no control. These two units, US Steel Corp – Minntac, point id 

EU225 and Keewatin Taconite Operations, point id EU030 will be assigned control efficiencies 

of 30% per the comments provided. A question was posed by May Jean “Why is a CE of 90% 
 Atmospheric Sciences Group

3

assumed? Existing efficiency of 1st generation FGD is 74%,” and my response is that this is the 

CE value that EPA assigns to units receiving scrubbers in the IPM runs and was assigned to 

these units for this analysis.

On the NOx table, two units were identified as having SNCR control in the 2018 Base Case, but 

were assigned a zero CE in the emission table. These two units, COVANTA HENNEPIN

ENERGY RESOURCE CO LP point ids EU001 and EU002 will be assigned CE values of 90% 

per Table 6-7 of the Alpine report. A third unit was identified as having Multiple Cyclone w/o 

Fly Ash Reinjection but comments indicate that a zero CE should be retained unless the facility 

can provide evidence of NOx reduction as a result of the technology modification. No action was 

taken on this comment.

Missouri

Wendy Vit submitted an e-mail stating that Missouri reviewed the information for their facilities 

and has confirmed that there are no existing NOx or SO2 controls for those units marked with 

control efficiencies of zero. No action was taken on units in Missouri.

Nebraska

Sara Speser submitted an e-mail providing two comments for consideration.

The first comment was related to two NPPD Sheldon Station units and the fact that as a coalfired electric system, these units would appear to be appropriate for incremental NOx and SO2 

controls although it is identified (as being part of the spreadsheet) as having no incremental 

control options available to it. Further review of the originating emissions inventory shows that 

one of the units (NPPD Sheldon Station, unit 001) is coded (by SCC) as a subbituminous coalfired, wet-bottomed cyclone boiler. This particular SCC (10100223) is one not associated in 

AirControlNET as having applicable control strategies. Because there is no reason to believe that 

this unit could not receive the same controls as a bituminous coal-fired, wet-bottomed cyclone 

boiler (SCC 10100203), we will recode the AirControlNET modified scripts to include this

particular SCC to receive the same control options as its bituminous counterpart.

The second NPPD Sheldon Station is coded as a natural gas fired combustion turbine (SCC 

20100201). This unit should be assigned incremental control and further review of the modified 

AirControlNET code identified an error in the scripts which omitted this SCC and other units 

from incremental control application. The code has been corrected and the NPPD Sheldon

Station, point id #1 will be included in potential incremental NOx control. Because this unit fires 

natural gas, no SO2 control options are available. 

The second facility in question (Ash Grove, point id 002) has CE values of 98% for both SO2 

and NOx in the 2018 Base Case scenario. These values appear to be carried over from the 2002 

base year emissions inventory and may be incorrect efficiencies for this unit. I have confirmed 

with Will Adler (e-mail February 7, 2007) that this indeed is the case and that values should both 

be set to zero.
 Atmospheric Sciences Group

4

Oklahoma

Lee Warden submitted a commented version of the original spreadsheet for consideration.

Comments were submitted both for NOx and SO2 controlled sources. The NOx controlled 

source spreadsheet listed five units where control efficiency assumptions should be changed in 

the 2018 base case estimates; these units were all modified per the revised values. PUBLIC SVC 

CO OF OK units 8747 and 8746 were modified to reflect a 70% control, BARLOW

OPERATORS OF TULSA LLC unit 18470 was modified to reflect an 85% control, KIAMICHI 

ENERGY FACILITY unit 19117 was modified to reflect a 95% control, and ASSOC ELEC 

COOP INC unit 17126 was modified to reflect an 85% control for NOx.

SO2 modifications were made to the CONOCOPHILLIPS PONCA CITY REFINERY unit 5379 

by revising 2018 emission to 65 tons per year reflective of a 95% control and GRAND RIVER 

DAM AUTH unit 9258 was modified to reflect an 85% control, consistent with current operating 

conditions.

Texas

Jim Price submitted an e-mail stating that Texas reviewed the information for their facilities and 

has confirmed that they do not have specific controls to suggest be added to the tables linking 

emission controls and emission units in Texas. No action was taken on units in Texas.

BART Subject Units

In the original EGU data files provided by Lee Warden, a number of units were identified as 

subject to BART and included emission estimates and percent reduction associated with the 

application of these technologies. In cases where control efficiency was present for both the 2018 

Base Case and for the incremental application of BART controls, a replacement was conducted 

to insert the greater of the two percent reductions into the CE fields prior to the cost curve 

calculations.