United States Forest Pacific Regional Office, Region 6 

Department of Service Northwest P.O. Box 3623 

Agriculture Region Portland, OR 98208-3623 

 

1 

January 7, 2008 

David Collier 

Air Quality Planning Manager 

Oregon Department of Environmental Quality 

811 sw Sixth Ave 

Portland, OR 97204-1390 

Re: Forest Service Comments on PGE Boardman BART analysis 

Dear David: 

The USDA Forest Service is pleased to see progress being made toward the selection and 

implementation of air pollution controls at the PGE Boardman power plant. The reductions in 

emissions from this facility are a critical component of reducing haze in 14 federal Class I areas 

in the Pacific Northwest and the Columbia River Gorge National Scenic Area (CRGNSA). In 

addition to reducing haze, the reductions in NOx and SO2 from this facility will help mitigate the 

adverse effects of excess nitrogen and acid deposition already occurring in the CRGNSA. 

The Forest Service has reviewed the PGE Boardman BART analysis. While we found the 

document well thought and presented, we have discrepancies with several components. Our 

comments are included as an attachment. As always, please feel free to contact me directly with 

any questions. 

Best regards, 

Rick Graw 

Air Resource Management Specialist 
Comments on the PGE Boardman BART Analysis – USDA Forest Service 

1 

Description of Unit 

Portland General Electric (PGE) operates the Boardman Power Plant (Boardman), which 

includes one Electric Generating Unit (EGU), near Boardman, OR. The plant is located 

within 300 km of 14 Class I areas, and the Columbia River Gorge National Scenic Area. 

The Boardman Plant includes a BART-eligible, wall-fired boiler which burns pulverized 

Powder River Basin (PRB) sub-bituminous coal (up to 1.0 %S) and is rated at 617/584 

MW (gross/net). The EGU is equipped with a cold-side Electrostatic Precipitator (ESP) 

to control particulate matter (PM10), first generation low-NOx Burners (LNB), and OverFire Air (OFA) to reduce nitrogen oxides (NOx). Low-sulfur coal is used to minimize 

sulfur dioxide (SO2). Baseline emission rates proposed by PGE are 0.017 lb Filterable 

PM10/mmBtu, 0.614 lb SO2/mmbtu, and 0.426 lb NOx/mmbtu 

Identification of All Available Retrofit NOx Emission Control Technologies

Oxygen-enhanced combustion is missing from the list of NOx control technologies. This 

technology was developed by the U.S. Department of Energy (DOE) and one of its 

partner’s - Praxair, Inc. As background, the U.S. Department of Energy’s National 

Energy Technology Laboratory’s Advanced NOx Emission Control Technology R&D 

program

1

 has the short-term goal to develop advanced in-furnace technologies for coalfired power plants capable of controlling NOx emissions to a level of 0.15 pounds per 

mmbtu heat input by 2007 and 0.10 lb/mmbtu by 2010, while achieving a levelized cost 

savings of at least 25% compared to state-of-the-art selective catalytic reduction (SCR) 

control technology. Three advanced in-furnace technologies: (1) ultra-low NOx burner 

systems, (2) oxygen-enhanced combustion, and (3) rich reagent injection, have lead to 

successful commercial demonstrations. While there is mention of advanced low NOx 

burner technology and rich reagent injection technology in the PGE BART analysis, there 

is no mention of oxygen-enhanced combustion. Oxygen Enhanced Combustion is 

described below and should be included in the list of NOx Control Technologies. 

• Oxygen-Enhanced Combustion – Praxair, Inc. and its partners developed a novel oxygenenhanced combustion (OEC) technology that can reduce NOx emissions from pulverized 

coal-fired (PC-fired) boilers, while improving combustion characteristics such as loss-onignition (LOI).This novel technology replaces a small fraction of the combustion air with 

oxygen. Praxair is also developing an oxygen transport membrane (OTM) process that 

uses pressurized ceramic membranes for separation of oxygen from air. Pilot-scale testing 

conducted using a commercially-available wall-fired burner with OEC demonstrated less 

than 0.15 lb/mmbtu NOx emissions could be achieved while firing Illinois No. 6 

bituminous coal. 

Control Effectiveness

In the BART Guidelines2, EPA states (page 39166), “Many control techniques...can 

perform at a wide range of levels...It is important, however, that in analyzing the 

technology you take into account the most stringent emission control level that the 

technology is capable of achieving.” An examination of the 2006 EPA Clean Air Markets 

 

1

http://www.netl.doe.gov/technologies/coalpower/ewr/nox/index.html

2

 Federal Register/ Vol. 70. No. 128 /Wednesday, July 6, 2005 
Comments on the PGE Boardman BART Analysis – USDA Forest Service 

2 

emissions database3 for each emissions control technology revealed that lower emission 

rates are achievable for wall-fired, dry bottom boilers burning coal. Additionally, the 

proposed control efficiencies used in the analysis are in some cases less efficient than 

those described in EPA’s Control Technology Center Fact Sheets for individual air 

pollutant control technologies. These items are discussed in more detail below. 

Clarification is also needed regarding the averaging times of the emission rates identified 

for each control technology. The baseline emission rates are annual average actual 

emissions. The BART guidelines state that a 30-day rolling average is to be used as the 

basis for enforceable limits for Electrical Generating Units (EGUs). However, for the 

modeling analysis, typically the 24-hour maximum emission rate is used to assess haze 

impacts. PGE should clarify the averaging period whenever one is stated in the analysis. 

Low NOx Burners with Over-Fired Air 

 

PGE documents that the low NOx burners (LNB) with over-fire air (OFA) would reduce 

NOx from 0.43 lbs/mmbtu (pounds per million British thermal unit) to 0.28 lb/mmbtu. In 

the memorandum to PGE from Black and Veatch, at the end of the BART analysis, the 

lowest emission rate for this control technology is reported for the Bridgeport 3, CT 

facility (0.16 lbs/mmbtu 30 day rolling average, and 0.13 lbs/mmbtu annual average). 

The low NOx emission rate is dismissed because it occurs at a tangentially-fired boiler. 

In our review of the EPA’s Clean Air Markets 2006 database, similarly low emission 

rates were found to occur at wall-fired boilers. The lowest reported NOx emission rate 

for LNB with OFA reported is 0.152 lbs NOx/mmbtu, which occurred at the Big Cajun 2 

facility in LA. Preliminary results from the 2007 Clean Air Markets database reports that 

the Neil Simpson Unit 1 PC boiler in Wyoming is able to achieve 0.15 lbs/mmbtu. LNB 

alone was able to achieve 0.143 lbs/mmbtu of NOx at the S.A. Carlson Unit 11 boiler in 

NY. 

The U.S. DOE NETL 2005 database documents 12 PC boilers which are opposed-firing, 

subbituminous and using low-NOx burners and/or OFA for NOx control. Eight of the 12 

units were achieving 0.25 lbs/mmbtu using LNB alone. Five units were identified as 

using both LNB and OFA, of which four were less than 0.25 lbs/mmbtu. The best 

performance was 0.153 lbs/mmbtu. 

Low NOx Burners with Over-Fired Air and Non-Selective Catalytic Reduction 

PGE assumed that the LNB with OFA and SNCR would reduce NOx from 0.43 

lbs/mmbtu to the presumptive limit of 0.23 lbs/mmbtu. NOx reductions levels using 

SNCR technology can achieve a 30 to 50% control4. Hence, if applied to the best 

performing PC boiler with LNB and OFA as identified from NETL, NOx emissions as 

low as 0.08 lbs/mmbtu are achievable. 

 

3

 http://www.epa.gov/airmarkets/ 

4

 Air Pollution Control Technology Fact Sheet – Selective Non-Catalytic Reduction. EPA-452/F-03-031. 

http://www.epa.gov/ttn/catc/dir1/fsncr.pdf 
Comments on the PGE Boardman BART Analysis – USDA Forest Service 

3 

The 2006 EPA Clean Air Market database documents that 0.14 lbs NOx/mmbtu have 

been achieved for wall-fired, dry bottom boiler burning coal with LNB with OFA and 

SNCR at Salem Harbor, MA Units 2 and 3. Unit 2 was able to achieve 0.134 lbs 

NOx/mmbtu as preliminary reported in the 2007 Clean Air Markets database. 

Such emission reductions are further supported by the U.S. Department of Energy’s 

National Energy Technology Laboratory’s Advanced NOx Emission Control Technology 

R&D program5. The program demonstrated that the Ultra Low-NOx (ULNB) pulverized 

coal burner technology (B&W’s DRB-4ZTM) plus urea-based, selective non-catalytic 

reduction system (Fuel Tech's NOx OUT) can achieve NOx emission limits of 0.15 lbs 

NOx /mmbtu for a variety of coals, including Powder River Basin. 

Selective Catalytic Reduction 

PGE estimates that combustion controls plus Selective Catalytic Reduction (SCR) can 

achieve 0.07 lb/mmbtu. The 2006 EPA Clean Air Market database documents that 0.05 

lbs NOx/mmbtu have been achieved for 3 wall-fired, dry bottom boiler burning coal with 

LNB with OFA and SCR; two of these are located at W A Parish (units 5 & 6) in Texas, 

at one unit (unit 9) is located at the Havana Power Plant in IL The lowest NOx emission 

rate reported in the 2007 Clean Air Markets database (preliminary) is 0.04 lbs/mmbtu 

(LNB and SCR). 

SCR retrofits are capable of and have been commercially demonstrated of controlling up 

to 90% of NOx emissions6,7. BART is to be based upon the most stringent control 

efficiency available. PGE is estimating that the SCR system will only control 75% of 

the NOx. What is the justification for using less than 90% control? 

Flue Gas Desulfurization 

The BART guidelines specify that SO2 from utility boilers be controlled at either at 95% 

or 0.15 lbs/mmbtu. When discussing control efficiencies expressed as a percent, a 

baseline emission is needed, and care must be taken not to use the baseline resulting from 

existing controls when calculating the new emission rate based upon percent control. In 

the case of PGE Boardman, low sulfur coal is the only SO2 “control” currently 

implemented. Because no additional SO2 controls exist, the baseline of 0.614 lbs 

SO2/mmbtu is used. Hence, 95% control would achieve an SO2 emission rate of 0.031 

lbs/mmbtu, substantially less than 0.15 lbs/mmbtu. Rather than assuming the higher 

emission rate of the two, a careful look at what is achievable via modern control 

technology is warranted. 

 

5

http://www.netl.doe.gov/technologies/coalpower/ewr/nox/index.html

6

 http://www.epa.gov/ttn/catc/dir1/fscr.pdf 

7

 http://www.babcock.com/library/tech-environmental.html#1694 
Comments on the PGE Boardman BART Analysis – USDA Forest Service 

4 

PGE states that its baseline SO2 emissions are 0.61 lbs/mmbtu and that semi-dry flue gas 

desulfurization (FGD) SO2 will be controlled to 0.15 lbs/mmbtu (75% control) and with a 

wet FGD system, SO2 will be controlled to 0.10 lbs/mmbtu (84%) control. 

However, the EPA Clean Air Technology Center has documented that more stringent 

control efficiencies are typically achieved. In its Air Pollution Control Technology Fact 

Sheet for FGD8

 states that SO2 control efficiencies for wet systems are between 90 and 

95%, depending upon whether limestone or lime is used as the sorbent material. SO2

control efficiencies for spray dry scrubbers (i.e., semi-dry systems) are slightly lower 

than wet systems, between 80 and 90%. When applied to the Boardman plant, wet FGD 

could achieve 0.031 lbs/mmbtu, and semi-dry FGD could achieve 0.061 lbs/mmbtu 

(assuming 90% control). 

Unfortunately, the Clean Air Markets Database does not report baseline SO2 emissions. 

Hence, only the emission rates can be reviewed. The lowest reported SO2 emission rate 

for a dry-bottom, wall-fired pulverized coal boiler utilizing wet flue-gas desulphurization 

is 0.04 lbs/mmbtu at the Bonanza power plant in Utah, as indicated in the EPA 2006 

Clean Air Markets database. The preliminary reports from 2007 indicate that 0.045 

lbs/mmbtu are achieved at the Asheville Power Units 1 & 2 in NC. These levels are 

substantially less than the 0.10 lbs/mmbtu that PGE has proposed. 

Similarly, the lowest reported SO2 emission rate using dry FGD is 0.091 lbs/mmbtu at the 

Hawthorne Power Plant, Unit 5A, in Missouri. This differs from the value reported for 

the same emission unit in the Black & Veatch memorandum, which reports emission 

rates for 2001. Preliminary results from 2007 indicate that 0.072 lbs SO2/mmbtu were 

achieved at the Holcomb Power SGU1 unit in KS. Again, these are substantially less 

than the 0.15 lbs/mmbtu SO2 emission rate proposed by PGE. 

Emission Rates use in the Visibility Modeling 

The emission rates used in the BART modeling are not reflective of the most stringent 

emission limits, as noted above. Specifically, the control efficiency for wet FGD, dry 

FGD, NLNB/OFA/SNCR, and NLNB/OFA/SCR are all to low. As such any conclusions 

drawn based upon the modeling are potentially affected. 

Analysis of Control Technologies in the Visibility Modeling

The analysis presents a comparison of modeled impacts for wet and dry FGD based upon 

SO2 controls alone, NOx emissions were modeled at their baseline value (according to 

Table E-1 in the report). Because ammonia preferentially reacts with sulfuric acid (of 

which SO2 is a precursor) as compared with nitric acid (of which NOx is a precursor), 

both the NOx and SO2 emissions reductions must be modeled together to get a more 

accurate depiction of ammonium sulfate and ammonium nitrate, the two primary haze 

causing pollutants. As modeled, any reduction in SO2 between wet and dry FGD, could 

simply free up the residual ambient ammonia to react with the nitric acid, thereby only 

resulting in a shift from one haze causing pollutant to the other, effectively causing no 

change in model-predicted impacts. The visibility impacts for both wet and dry FGD 

 

8

 http://www.epa.gov/ttn/catc/dir1/ffdg.pdf 
Comments on the PGE Boardman BART Analysis – USDA Forest Service 

5 

impact analysis needs to be remodeled using NOx emissions representative of BART to 

more accurately assess the impacts. 

Visibility Modeling Results

The PGE Boardman facility represents a unique emission source in the Pacific 

Northwest, in that no other facility affects so many federal Class I areas. Table 1 presents 

the cumulative impacts for all 14 federal Class I areas and the CRGNSA for the three 

years modeled (2003-2005). Model-predicted impacts are shown for the baseline and the 

two contending NOx control technologies. The modeled impacts incorporate both SO2

and NOx control technologies. SO2 is assumed to be controlled with semi-dry FGD with

an emission rate of 0.15 lbs/mmbtu. NOx is assumed to be controlled using a 

combination of combustion and post-combustion technologies. Both scenarios assume 

new LNB and modified OFA NOx combustion control. However, one technology 

utilizes SNCR where the other incorporates SCR. By looking at the cumulative impacts 

rather than just looking at the Class I area with the highest impacts (as presented by 

PGE), one can better understand the regional implications of the existing and proposed 

control technologies. 

Table 1. Cumulative Impacts 

Control Technologies Number of Days > 1.0 dv Number of Days > 0.5 dv 

2003 2004 2005 2003 2004 2005 

Existing 466 532 433 851 960 821 

Semi-dry FGD with 

NLNB/MOFA/SNCR

91 106 87 382 344 265 

Semi-dry FGD with 

NLNB/MOFA/SCR 

11 21 29 101 138 98 

Difference 

(SNCR – SCR) 

80 85 58 281 206 167 

Based upon PGE’s modeling, this facility may contribute to a combined total of 960 days 

of adverse haze impacts in these areas (i.e., 960 days with impacts > 0.5 dv) and cause up 

to 532 days of impacts in a single year using their existing control technology. 

Should PGE implement new LNB with OFA and SCR, Boardman may only contribute up 

to 138 days (a decrease of 822 days/yr across the region.). If SNCR is utilized instead of 

SCR, Boardman would contribute up to 344 days/yr of haze. Hence, by selecting SCR 

instead of SNCR, 281 days/yr region-wide may be reduced from Boardman contributing 

to haze. The Forest Service views this as a substantial difference. 

Cost Analysis – General

Does Oregon allow for any sales tax relief as was done for the FGD retrofit for the 

Centralia power plant in Washington State? If so, was this included in the cost analysis? 

NOx Cost Analysis

The Forest Service was not able to replicate the capital costs associated with the SCR 

control option (new LNB with modified OFA and SCR) using independent screening-
Comments on the PGE Boardman BART Analysis – USDA Forest Service 

6 

level cost analyses. Comparisons with estimates from the World Bank for SCR retrofit9

and LNB with OFA10 show a large discrepancy in costs. SCR retrofits are estimated 

between $80 to 100/kW (post FGD). Adding in the capital cost associated with a retrofit 

LNB and OFA ($10-25/kW), and applying this to the gross output at Boardman (617 

MW), results in a cost $56 to 77 million in capital expenses. This is substantially less 

than the $223 million estimated by PGE. 

As confirmation, another method used by EPA11 was used to estimate costs for SCR 

retrofits. Using this method, we estimate capital costs to be $56/kW to control NOx at 

90% efficiency at PGE’s estimated post-combustion level of 0.28 lbs/mmbtu (i.e., 

combustion controls only). Again, these costs are substantially lower than that proposed 

by PGE. 

SO2 Cost Analysis

The capital cost of the wet FGD retrofit ($382 million) is nearly double the $200 million 

capital costs for the wet FGD at the Centralia power plant12. The World Bank states that 

“recent cost estimates (1995-1997) of FGD systems in both OECD and developing 

countries indicate a general reduction of costs”13. It is unclear why the estimated cost for 

this technology is so much more than the Centralia plant, if costs of FGD systems are still 

decreasing. 

Selection of Best Alternative

The table above only illustrates the impact on haze in federal Class I areas and the 

CRGNSA. It should be reiterated that in addition to the reduction in haze in these locals, 

haze will be reduced elsewhere as well. Additionally, the reductions in emissions will no 

doubt help to diminish the adverse ecological effects already occurring in the CRGNSA. 

Considering the benefits across the entire region, rather than looking solely at a single 

Class I area, heightens the implications of the selected control technology. 

Selection of SO2 BART

The dismissal of wet FGD based upon the visibility modeling is not substantiated due to 

the issues identified previously. The model must be run using the BART-controlled NOx 

emission rate, and the most stringent SO2 emission rate for each the wet and dry FGD 

scenario, before one can quantify the differences in visibility (see the section on

“Visibility Impacts – Control Technologies” for issues associated with the atmospheric 

chemistry). Additionally, the costs of the wet-FGD process are in question. Hence, it is 

premature to dismiss wet FGD at this time. 

 

9

http://www.worldbank.org/html/fpd/em/power/EA/mitigatn/aqnoscr.stm

10 http://www.worldbank.org/html/fpd/em/power/EA/mitigatn/aqnolow.stm 

11 Cost of Selective Catalytic Reduction (SCR) Application for NOx Control on Coal-fired Boilers. 

EPA/600/R-01/087, October 2001. http://www.epa.gov/nrmrl/pubs/600r01087/600r01087.pdf 

12 Centralia Power Plant Bart-like Control Technology Analysis. Al Newman, Washington Department of 

Ecology. Presentation to westar. 

http://www.westar.org/05%20Tech%20Conference/Newman,%20Centralia%20RA%20BART%20Process.

ppt 

13 http://www.worldbank.org/html/fpd/em/power/EA/mitigatn/aqsowet.stm 
Comments on the PGE Boardman BART Analysis – USDA Forest Service 

7 

Selection of NOx BART

The selection of new low NOx burners with modified overfire air and non-selective 

catalytic reduction (NSCR+) as BART is based in part on the dismissal of new low NOx 

burners with overfire air and selective catalytic reduction (SCR+). Although SCR+ 

results in lower NOx emissions, PGE argues that this technology was not selected 

because of economics, hazardous material disposal, additional energy requirements, with 

only slightly better visibility improvements. However, when visibility is considered 

across all 14 federal Class I areas and the CRGNSA, the difference in impacts is 

substantial. Additionally, the capital costs associated with the SCR control technology 

are in question. Hence, SCR+ should not be dismissed based upon these arguments.