United States Forest Pacific Regional Office, Region 6

Department of Service Nor thwest 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 analy sis

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 compone nt of reducing haze in 14 federal Class I areas

in the Pacific Northwest and the Columbia River Gor ge National Scenic Area (CRGNSA). In addition to reducing haze, the reductions in NOx an d SO 2 from this facility will help mitigate the adverse effects of excess nitrogen and acid deposit ion already occurring in the CRGNSA.

The Forest Service has reviewed the PGE Boardman BA RT analysis. While we found the document well thought and presented, we have discre pancies 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 SpecialistComments on the PGE Boardman BART Analysis – USDA F orest Service

1 Description of Unit Portland General Electric (PGE) operates the Boardm an Power Plant (Boardman), which includes one Electric Generating Unit (EGU), near B oardman, 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-f ired 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-sid e Electrostatic Precipitator (ESP) to control particulate matter (PM 10 ), first generation low-NO

x Burners (LNB), and OverFire Air (OFA) to reduce nitrogen oxides (NO

x ). Low-sulfur coal is used to minimize sulfur dioxide (SO 2 ). Baseline emission rates proposed by PGE are 0.0 17 lb Filterable

PM 10 /mmBtu, 0.614 lb SO 2 /mmbtu, and 0.426 lb NO

x /mmbtu

Identification of All Available Retrofit NOx Emissi on 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. D epartment of Energy’s National Energy Technology Laboratory’s Advanced NOx Emissio n 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 emiss ions 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-ar t selective catalytic reduction (SCR) control technology. Three advanced in-furnace tech nologies: (1) ultra-low NOx burner systems, (2) oxygen-enhanced combustion, and (3) ri ch reagent injection, have lead to

successful commercial demonstrations. While there i s mention of advanced low NOx burner technology and rich reagent injection techno logy in the PGE BART analysis, there is no mention of oxygen-enhanced combustion. Oxyg en 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 ox ygenenhanced combustion (OEC) technology that can reduc e NOx emissions from pulverized coal-fired (PC-fired) boilers, while improving comb ustion 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 transp ort membrane (OTM) process that uses pressurized ceramic membranes for separation o f 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 Guidelines 2 , 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, Jul y 6, 2005Comments on the PGE Boardman BART Analysis – USDA F orest Service

2 emissions database 3 for each emissions control technology revealed tha t lower emission rates are achievable for wall-fired, dry bottom boi lers 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 di scussed in more detail below.

Clarification is also needed regarding the averagin g 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 Generat ing Units (EGUs). However, for the modeling analysis, typically the 24-hour maximum em ission rate is used to assess haze impacts. PGE should clarify the averaging period w henever one is stated in the analysis.

Low NOx Burners with Over-Fired Air

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

NO

x from 0.43 lbs/mmbtu (pounds per million British th ermal 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, an d 0.13 lbs/mmbtu annual average).

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

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

rates were found to occur at wall-fired boilers. T he lowest reported NOx emission rate for LNB with OFA reported is 0.152 lbs NOx/mmbtu, w hich 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 abl e 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 boi lers 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 tha n 0.25 lbs/mmbtu. The best performance was 0.153 lbs/mmbtu.

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

PGE assumed that the LNB with OFA and SNCR would re duce NO

x from 0.43 lbs/mmbtu to the presumptive limit of 0.23 lbs/mmbt u. NOx reductions levels using SNCR technology can achieve a 30 to 50% control 4 . 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 – Sele ctive Non-Catalytic Reduction. EPA-452/F-03-031. http://www.epa.gov/ttn/catc/dir1/fsncr.pdfComments on the PGE Boardman BART Analysis – USDA F orest Service

3 The 2006 EPA Clean Air Market database documents th at 0.14 lbs NOx/mmbtu have been achieved for wall-fired, dry bottom boiler bur ning 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 t he U.S. Department of Energy’s National Energy Technology Laboratory’s Advanced NO x Emission Control Technology R&D program 5 . The program demonstrated that the Ultra Low-NOx (ULNB) pulverized coal burner technology (B&W’s DRB-4ZTM) plus urea-ba sed, 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 Selecti ve Catalytic Reduction (SCR) can

achieve 0.07 lb/mmbtu. The 2006 EPA Clean Air Marke t 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 databas e (preliminary) is 0.04 lbs/mmbtu (LNB and SCR).

SCR retrofits are capable of and have been commerci ally demonstrated of controlling up

to 90% of NOx emissions 6,7 . BART is to be based upon the most stringent cont rol 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 SO 2 from utility boilers be controlled at either at 95 % or 0.15 lbs/mmbtu. When discussing control efficien cies 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 on ly SO2 “control” currently implemented. Because no additional SO2 controls ex ist, the baseline of 0.614 lbs

SO 2 /mmbtu is used. Hence, 95% control would achieve a n 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#1694Comments on the PGE Boardman BART Analysis – USDA F orest Service

4 PGE states that its baseline SO 2 emissions are 0.61 lbs/mmbtu and that semi-dry flu e gas desulfurization (FGD) SO 2 will be controlled to 0.15 lbs/mmbtu (75% control) and with a wet FGD system, SO 2 will be controlled to 0.10 lbs/mmbtu (84%) control

.

However, the EPA Clean Air Technology Center has do cumented that more stringent control efficiencies are typically achieved. In it s Air Pollution Control Technology Fact

Sheet for FGD 8 states that SO 2 control efficiencies for wet systems are between 9 0 and 95%, depending upon whether limestone or lime is us ed as the sorbent material. SO 2 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 cou ld 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. Th e lowest reported SO 2 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 Uta h, as indicated in the EPA 2006 Clean Air Markets database. The preliminary report s 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 SO 2 emission rate using dry FGD is 0.091 lbs/mmbtu at the Hawthorne Power Plant, Unit 5A, in Missouri. This d iffers from the value reported for

the same emission unit in the Black & Veatch memora ndum, which reports emission rates for 2001. Preliminary results from 2007 indi cate that 0.072 lbs SO2/mmbtu were achieved at the Holcomb Power SGU1 unit in KS. Aga in, these are substantially less

than the 0.15 lbs/mmbtu SO 2 emission rate proposed by PGE.

Emission Rates use in the Visibility Modeling The emission rates used in the BART modeling are no t 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 affec ted.

Analysis of Control Technologies in the Visibility Modeling The analysis presents a comparison of modeled impac ts for wet and dry FGD based upon

SO 2 controls alone, NOx emissions were modeled at thei r baseline value (according to Table E-1 in the report). Because ammonia preferen tially reacts with sulfuric acid (of

which SO 2 is a precursor) as compared with nitric acid (of w hich NOx is a precursor),

both the NOx and SO 2 emissions reductions must be modeled together to g et a more accurate depiction of ammonium sulfate and ammonium nitrate, the two primary haze causing pollutants. As modeled, any reduction in S O 2 between wet and dry FGD, could simply free up the residual ambient ammonia to reac t with the nitric acid, thereby only resulting in a shift from one haze causing pollutan t 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.pdfComments on the PGE Boardman BART Analysis – USDA F orest Service

5 impact analysis needs to be remodeled using NOx emi ssions representative of BART to more accurately assess the impacts.

Visibility Modeling Results The PGE Boardman facility represents a unique emiss ion source in the Pacific Northwest, in that no other facility affects so man y federal Class I areas. Table 1 presents the cumulative impacts for all 14 federal Class I a reas 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 model ed impacts incorporate both SO 2 and NOx control technologies. SO 2 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 techn ologies. Both scenarios assume

new LNB and modified OFA NOx combustion control. H owever, 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 t he highest impacts (as presented by PGE), one can better understand the regional implic ations of the existing and proposed control technologies.

Table 1. Cumulative Impacts
Number of Days > 1.0 dv Number of Days > 0.5 dv Control Technologies

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 contri bute to a combined total of 960 days of adverse haze impacts in these areas (i.e., 960 d ays 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, Boar dman may only contribute up to 138 days (a decrease of 822 days/yr across the r egion.). 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 red uced from Boardman contributing

to haze. The Forest Service views this as a subst antial difference.

Cost Analysis – General Does Oregon allow for any sales tax relief as was d one for the FGD retrofit for the Centralia power plant in Washington State? If so, was this included in the cost analysis?

NO

x Cost Analysis The Forest Service was not able to replicate the ca pital 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 F orest Service

6 level cost analyses. Comparisons with estimates fro m the World Bank for SCR retrofit 9

and LNB with OFA 10 show a large discrepancy in costs. SCR retrofits are estimated between $80 to 100/kW (post FGD). Adding in the ca pital cost associated with a retrofit LNB and OFA ($10-25/kW), and applying this to the g ross 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 EPA 11 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 l evel of 0.28 lbs/mmbtu (i.e., combustion controls only). Again, these costs are substantially lower than that proposed by PGE.

SO 2 Cost Analysis The capital cost of the wet FGD retrofit ($382 mill ion) is nearly double the $200 million capital costs for the wet FGD at the Centralia powe r plant 12 . The World Bank states that “recent cost estimates (1995-1997) of FGD systems i n 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 t o the reduction in haze in these locals,

haze will be reduced elsewhere as well. Additional ly, the reductions in emissions will no doubt help to diminish the adverse ecological effec ts 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 sel ected control technology.

Selection of SO 2 BART The dismissal of wet FGD based upon the visibility modeling is not substantiated due to the issues identified previously. The model must b e run using the BART-controlled NOx emission rate, and the most stringent SO 2 emission rate for each the wet and dry FGD scenario, before one can quantify the differences i n visibility (see the section on

“ Visibility Impacts – Control Technologies” for issu es 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/mitig atn/aqnoscr.stm

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

11 Cost of Selective Catalytic Reduction (SCR) Applic ation 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/miti gatn/aqsowet.stmComments on the PGE Boardman BART Analysis – USDA F orest 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 par t on the dismissal of new low NOx burners with overfire air and selective catalytic r eduction (SCR+). Although SCR+ results in lower NOx emissions, PGE argues that thi s technology was not selected because of economics, hazardous material disposal, additional energy requirements, with only slightly better visibility improvements. Howe ver, when visibility is considered across all 14 federal Class I areas and the CRGNSA, the difference in impacts is substantial. Additionally, the capital costs assoc iated with the SCR control technology are in question. Hence, SCR+ should not be dismiss ed based upon these arguments.