1

National Park Service (NPS) Comments on

Oregon Department of Environmental Quality (OR DEQ)’s proposed

Best Available Retrofit Technology (BART) Determination for the

Boardman Power Plant

October 1, 2010

Present Unit Operation

The Boardman Power Plant (Boardman) is operated by Portland General Electric (PGE) 

and includes one dry-bottom, wall-fired boiler burning pulverized sub-bituminous coal

(8,020 Btu/lb, 0.3% sulfur, 9% ash) and is rated at 617 MW. This electric generating unit

is equipped with an electrostatic precipitator to control particulate matter. 

Current Actual NOx Emission Rates

Baseline emission rates proposed by the Oregon Department of Environmental Quality 

(OR DEQ) for the cost evaluation steps are 14,902 tons per year (tpy) SO2 (0.61 lb 

SO2/mmBtu) and 10,349 tpy NOX (0.43 lb NOx/mmBtu). Based upon our review of 

EPA’s Clean Air Markets (CAM) data for this facility, these estimates of actual SO2 and 

NOx emissions appear reasonable for the annual cost analyses. According to the CAM 

database, facility SO2 emissions have averaged 13,025 tons per year (tpy) and 0.65

lb/mmBtu during 2000 – 2009. Facility NOX emissions have averaged 8,535 tpy and 0.43

lb/mmBtu during the same period. (Because we used the slightly lower average annual 

emissions from the CAM database, our estimates of the amount of emissions that could 

be reduced by various control options are somewhat lower than had we used the OR DEQ 

data.)

BART analysis for NOX

Consistent with the Environmental Protection Agency (EPA)’s BART Guidelines, the 

five steps for a case-by-case BART analysis were followed.

Step 1 – Identify all available retrofit control technologies

OR DEQ: The NOX control technologies that are feasible at Boardman include: LowNOX Burners(LNB), Over-Fire Air (OFA), Selective Non-Catalytic Reduction (SNCR), 

and Selective Catalytic Reduction (SCR).

NPS: OR DEQ evaluated a reasonable suite of options.

Step 2 – Eliminate technically infeasible options

OR DEQ: DEQ eliminated from further analysis those control technology options that could 

not meet the BART presumptive limit (0.23 lb/MMBtu for NOX).

NPS: We agree with OR DEQ’s approach.

Step 3 – Evaluate the control effectiveness of the remaining technologies 
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OR DEQ: The basis for the control effectiveness of new LNB with modified over-fire air, 

SCR...was discussed in the previous report and there is no new information to suggest 

revising the previous conclusions. 

NPS: We are presenting new information that shows that OR DEQ has underestimated 

the ability of SCR to reduce emissions. It is generally understood that NOX reductions 

of approximately 90% or more may be achieved with SCR systems.

1 And, according to 

the June 13, 2009 “Power” magazine article “Air Quality Compliance: Latest Costs for 

SO2 and NOX Removal (effective coal clean-up has a higher–but known–price tag)” by

Robert Peltier, “An excellent example of the significant investment many utilities have 

made over the past decade is American Electric Power (AEP), one of the largest public 

utilities in the U.S. with 39,000 MW of installed capacity with 69% of that capacity coalfired. AEP is under a New Source Review (NSR) consent decree signed in 2007 that 

requires the utility install air quality control systems to reduce NOX by 90%...”

If we assume a 90% reduction by SCR from the 0.23 lbNOX/mmBtu emission rate 

predicted for the LNB+OFA option at Boardman, outlet emissions would be reduced to 

0.02 lb/mmBtu. Instead, for the LNB+OFA+SCR option, OR DEQ assumed 0.07

lb/mmBtu; this represents only a 70% reduction from the LNB+OFA emission estimate. 

We are now including (in Appendix A) new 2009 CAM data that shows that SCR can 

achieve year-round emissions of 0.05 lb/mmBtu or lower2at 27 coal-fired EGUs, nine of 

which are wall-fired units like Boardman. Although we believe that SCR is capable of 

even lower annual NOx emissions at Boardman, we will continue to assume 0.05 

lb/mmBtu in our analyses to reflect our understanding of vendor guarantees.3

STEP 4 –Evaluate Impacts and Document the Results

OR DEQ: PGE calculated the capital investment and annual operating cost for each 

technically feasible add-on control option based on the following: 

 CUECost Workbook, Version 1.0 

 EPA Air Pollution Control Cost Manual – Sixth Edition 

 Budgetary quotes from equipment vendors 

 Quotes or cost estimation for previous design/build projects or in-house engineering 

estimates 

NPS: Both OAQPS and EPA Region 8 have advised against the use of CUECost. 

Instead, the BART Guidelines recommend use of the OAQPS Control Cost Manual: 

The basis for equipment cost estimates also should be documented, either with data supplied by an 

equipment vendor (i.e., budget estimates or bids) or by a referenced source (such as the OAQPS 

 

1 According to the Institute of Clean Air Companies white paper titled “Selective Catalytic Reduction 

(SCR) Control of NOx Emissions from Fossil Fuel-Fired Electric Power Plants” (published in May 2009), 

“By proper catalyst selection and system design, NOX removal efficiencies exceeding 90 percent may be 

achieved.”

2 Our review of operating data suggests that a NOX limit of 0.06 lb/mmBtu is appropriate for 

LNB/SOFA+SCR for a 30-day rolling average, and 0.07 lb/mmBtu for a 24-hour limit and for modeling 

purposes, but a lower rate (e.g., 0.05 lb/mmBtu or lower) should be used for annual average and annual cost 

estimates.

3

For example, Minnesota Power has stated in its Taconite Harbor BART analysis that “The use of an SCR 

is expected to achieve a NOX emission rate of 0.05 lb/mmBtu based on recent emission guarantees offered 

by SCR system suppliers.”
3

Control Cost Manual, Fifth Edition, February 1996, 453/B-96-001). In order to maintain and improve 

consistency, cost estimates should be based on the OAQPS Control Cost Manual, where possible. The 

Control Cost Manual addresses most control technologies in sufficient detail for a BART analysis. 

The cost analysis should also take into account any site-specific design or other conditions identified 

above that affect the cost of a particular BART technology option.

EPA’s belief that the Control Cost Manual should be preferred over CUECost for 

developing cost analyses that are transparent and consistent across the nation and provide 

a common means for assessing costs is further supported by this November 7, 2007, 

statement from EPA Region 8 to the North Dakota Department of Health:

The SO2 and PM cost analyses were completed using the CUECost model. According to 

the BART Guidelines, in order to maintain and improve consistency, cost estimates 

should be based on the OAQPS Control Cost Manual. Therefore, these analyses should 

be revised to adhere to the Cost Manual methodology.

NPS: OR DEQ has overestimated the cost of LNB, OFA, and SCR. OR DEQ 

“discussed PGE’s cost estimates in the previous report and agreed with their estimates. PGE 

has revised the costs to reflect 2010 dollars rather than 2007 dollars, as used in the previous 

report.” OAQPS has advised4use of the Chemical Engineering Plant Cost Index (CEPCI) to 

adjust costs for inflation. The CEPCI for 2007 was 525.4 and 521.9 for 2009, which indicates 

a decrease in costs. PGE should explain and justify its escalated costs.

According to PGE, “The cost estimates are consistent in format with the guidance from

the EPA’s Office of Air Quality Planning and Standards Cost Manual.” However, PGE’s 

estimation methods bear no resemblance to the Cost Manual methods for estimating 

SNCR and SCR costs. And, PGE’s cost estimates for LNB+OFA were 47% higher than 

the estimates provided by ERG (OR DEQ’s consultant) in its June 26, 2008 “Technical 

Memorandum #2” to OR DEQ. We have accordingly used the ERG estimate of $36/kW 

in our cost calculations for LNB+OFA.

PGE did not provide adequate justification or documentation for its cost estimates. We 

were not provided with any vendor estimates or bids, and PGE did not use the Control 

Cost Manual. As a result, we believe that capital and annual costs are overestimated. For 

example, the PGE estimate for SCR equates to a capital cost of $246/kW5for the routine6

SCR installation compared to the $50 - $267/kW cost of SCR found in survey data 

(Appendix B). 

In the absence of adequate cost estimates by PGE, we applied the methods described in 

the Cost Manual, with some modifications to compensate for what we believe to be a 

tendency to underestimate Direct Capital Costs (DCC). All of the Indirect Capital Costs 

 

4

E-mail from Larry Sorrels, EPA OAQPS, to Don Shepherd dated 7/21/10. “On cost indexes, I prefer the 

CEPCI for escalating/deescalating costs for chemical plant and utility processes since this index 

specifically covers cost items that's pertinent to pollution control equipment (materials, construction labor, 

structural support, engineering & supervision, etc.). The Marshall & Swift cost index is useful for industrylevel cost estimation, but is not as accurate at a disaggregated level when compared to the CEPCI. Thus, I 

recommend use of the CEPCI as a cost index where possible.”

5

($227.4 million for SCR – $40 million boiler modifications – $35.7 million LNB+OFA)/617,000 kW) 

6 No unusual installation issues were noted aside from the boiler modifications that have already been 

accounted for.
4

estimated by the Cost Manual method are proportional to the DCC, so DCC becomes a 

very important parameter. While the Excel Workbook (“NPS SCR modified Cost manual 

approach for Boardman”) in Appendix B estimates DCC = $27 million (in 2009 dollars), 

we will instead use the PGE estimate of $91 million for DCC. By applying the Cost 

manual ratios to the PGE DCC estimate, we arrive at a Total Capital Investment (TCI) of 

$129 million (versus PGE’s estimate of $192 million), or $209/kW (versus PGE’s 

estimate of $246/kW), exclusive of the combustion controls and boiler modifications.

Our estimates are more commensurate with industry data, as discussed below.

Further evidence that PGE has overestimated its SCR costs can be found in a June 2009 

article in “Power” magazine:

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“One more current data set is the historic capital costs reported by AEP averaged over 

several years and dozens of completed projects. For example, AEP reports that their 

historic average capital costs for SCR systems are $162/kW for 85% to 93% NOX

removal...”

“...historical data finds the installed cost of an SCR system of the 700MW-class as 

approximately $125/kW over 22 units with a maximum reported cost of $221/kW in 

2004 dollars. This data was reported prior to the dramatic increase in commodity prices 

of 14% per year average experienced from 2004 to 2006 (from the FGD survey results). 

Applying those annual increases to the 2004 estimates for three years (from the date of 

the survey to the end of 2007) produces an average SCR system installed cost of 

$185/kW...”

“Overall, costs were reported to be in the $100 to $200/kW range for the majority of the 

systems, with only three reported installations exceeding $200/kW.”

Five industry studies conducted between 2002 and 2007 have reported the installed unit 

capital cost of SCRs, or the costs actually incurred by owners, expressed in dollars per 

kilowatt. These actual costs are generally lower than estimated by PGE for Boardman. 

The first study evaluated the installed costs of more than 20 SCR retrofits from 1999 to 

2001. The installed capital cost ranged from $106 to $213/kW, converted to 2007

dollars.8 Costs are escalated through using the CEPCI. 

The second survey of 40 installations at 24 stations reported a cost range of $76 to 

$242/kW, converted to 2007 dollars.9

 

7

June 13, 2009 “Power” magazine article “Air Quality Compliance: Latest Costs for SO2 and NOx 

Removal (effective coal clean-up has a higher–but known–price tag)” by Robert Peltier. 

http://www.masterresource.org/2009/06/air-quality-compliance-latest-costs-for-so2-and-nox-removaleffective-coal-clean-up-has-a-higher-but-known-price-tag/

8 Bill Hoskins, Uniqueness of SCR Retrofits Translates into Broad Cost Variations, Power Engineering, 

May 2003. Ex. 2. The reported range of $80 to $160/kW $123 - $246/kW was converted to 2008 dollars 

($116 - $233/kW) using the ratio of CEPCI in 2008 to 2002: 575.4/395.6. 

9

 J. Edward Cichanowicz, Why are SCR Costs Still Rising?, Power, April 2004, Ex. 3; Jerry Burkett, 

Readers Talk Back, Power, August 2004, Ex. 4. The reported range of $56/kW - $185/kW was converted to 

2008 dollars ($83 - $265/kw)using the ratio of CEPCI for 2008 to 1999 (575.4/.390.6) for lower end of the 

range and 2008 to 2003 (575.4/401.7) for upper end of range, based on Figure 3. 
5

The third study, by the Electric Utility Cost Group, surveyed 72 units totaling 41 GW, or 

39% of installed SCR systems in the U.S. This study reported a cost range of $118/kW to 

$261/kW, converted to 2007 dollars.10

A fourth study, presented in a course at PowerGen 2005, reported an upper bound range 

of $180/kW to $202/kW, converted to 2007 dollars.11

A fifth summary study, focused on recent applications that become operational in 2006 or 

were scheduled to start up in 2007 or 2008, reported costs in excess of $200/kW on a 

routine basis, with the highest application slated for startup in 2009 at $300/kW.12

Thus, the overall range for these industry studies is $50/kW to $300/kW. The upper end 

of this range is for highly complex retrofits with severe space constraints, such as Belews 

Creek, reported to cost $265/kW,

13 or Cinergy's Gibson Units 2-4. Gibson, a highly

complex, space-constrained retrofit in which the SCR was built 230 feet above the power 

station using the largest crane in the world,14 only cost $251/kW in 2007 dollars.15

PGE has overestimated Direct Annual Costs (DAC) for SCR. For example, PGE states 

(in its Appendix D) that Maintenance & Labor materials cost 3% of the DCC, while the 

Cost Manual assumes 1.5% of the TCI; this results in about a $1 million annual 

overestimate. Other examples of PGE’s higher-than-Cost Manual estimates can be found 

in the “Ann Cost” tab of the “NPS SCR modified Cost manual approach for Boardman” 

workbook. All told, PGE estimates $5.7 million/yr versus $3.8 million using the Cost 

Manual.

We agree with OR DEQ that “remaining useful life” is a very important factor in the 

economics of the BART analysis. For example, if we assume a remaining useful life of 

20 years (the SCR default) in cell C38 in the “Given/Assume” tab of the “NPS SCR 

modified Cost manual approach for Boardman” workbook, our estimate (“Ann Cost” tab 

cell D50) of Indirect Annual Cost (to amortize the SCR investment) is $16 million/yr and 

 

10 M. Marano, Estimating SCR Installation Costs, Power, January/February 2006. Ex. 5. The reported range 

of $100 - $221/kW was converted to 2008 dollars ($130 - $286/kW) using the ratio of CEPCI for 2008 to 

2004: 575.4/444,2. 

http://findarticles.com/p/articles/mi_qa5392/is_200602/ai_n21409717/print?tag=artBody;col1 

11 PowerGen 2005, Selective Catalytic Reduction: From Planning to Operation, Competitive Power 

College, by Babcock Power, Inc. and LG&E Energy, December 2005, Ex. 6. The reported range of $160 -

$180/kW) was converted to 2008 dollars ($197 - $221/kW) using the ratio of CEPCI for 2008 to 2005 

(575.4/468.2). 

12 J. Edward Cichanowicz, Current Capital Cost and Cost-Effectiveness of Power Plant Emissions Control 

Technologies, June 2007, pp. 28-29, Figure 7-1 (Ex. 1). 

13 Steve Blankinship, SCR = Supremely Complex Retrofit, Power Engineering, 

November 2002, Ex. 7. The unit cost: ($325,000,000/1,120,000 kW)(608.8/395.6) = 

$290/kW. http://pepei.pennnet.com/display_article/162367/6/ARTCL/none/none/1/SCR-

=-Supremely-Complex-Retrofit/ 

14

 Standing on the Shoulder of Giants, Modern Power Systems, July 2002, Ex. 8. 

15 McIlvaine, NOX Market Update, August 2004, Ex. 9. SCR was retrofit on Gibson Units 2-4 in 2002 and 

2003 at $179/kW. Assuming 2002 dollars, this escalates to ($179/kW)(608.8/395.6) = $275.5/kW. 

http://www.mcilvainecompany.com/sampleupdates/NoxMarketUpdateSample.htm 
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the cost/ton of the LNB+OFA+SCR system becomes $3,000/ton (cell D64 of the “Ann 

Cost” tab). However, if one enters a shorter life, e.g., five years, into cell C38 in the 

“Given Assume” tab of the workbook, the Indirect Annual Cost (“Ann Cost” tab cell 

D50) rises to $41 million and the cost/ton rises to almost $7,000/ton (cell D64 of the 

“Ann Cost” tab) over five years. Nevertheless, based upon OR DEQ’s cost-effectiveness 

threshold of $7,300/ton, one would conclude that SCR would be cost-effective if used for 

only five years before plant shut-down.

There is a wide discrepancy between SCR cost estimates presented by PGE and by NPS 

using the EPA Control Cost Manual. Following is a breakdown of the specific areas 

where PGE's results differ substantially from ours:

 PGE’s estimates are based upon achieving 0.07 lb/mmBtu, which represents 70% 

NOx reduction from the 0.23 lb/mmBtu to be achieved by combustion controls. 

Although modern SCR systems are typically designed to achieve 90+% NOx

reductions, we assumed a 0.05 lb/mmBtu (a 78% reduction) “target” for SCR 

based upon the performance of the eastern boiler retrofits discussed above.

 PGE estimated that SCR would have a Total Capital Investment (TCI) of $192

million. When we modified the Cost Manual approach to produce a more realistic

estimate, we estimated a TCI of $129 million. PGE’s estimate of $246/kW is 

excessive when compared to real-world industry data, while our $209/kW appears 

reasonable. PGE should provide detailed descriptions of how its SCR TCI costs 

were derived.

 PGE has overestimated Direct Annual Costs and should provide detailed 

descriptions of how these costs were derived.

 The combination of overestimates for Total Capital Investment and Direct Annual 

Costs had resulted in inflated costs from PGE without the supporting justifications 

required by the BART Guidelines.

 For remaining useful life of five years or more, LNB+OFA+SCR meets OR 

DEQ’s $7,300/ton criterion.

A similar situation exists with respect to SNCR, and PGE’s estimates are even more 

devoid of detail and apparently inflated. Once again, we applied the Cost Manual method 

to OR DEQ’s expected emission rates and our results are summarized in the “Boardman 

SNCR” tab in the “NPS version of OAQPS Cost Manual SNCR for Boardman” 

workbook in Appendix B. Even if the remaining useful life of the LNB+OFA+SNCR 

system is only two years (cell C27 of the “Given/Assume” tab), the cost-effectiveness is 

still well below OR DEQ’s $7,300 ton threshold.

STEP 5 – Evaluate Visibility Impacts

Base Case: According to OR DEQ, Mt. Hood is the most-impacted Class I area with a

98th percentile value of 4.98 deciview (dv), and the cumulative impact across all 14 Class 

I areas is 31.46 dv. (Boardman ranks as having the fourth-highest cumulative impact of 

any BART source we have reviewed to date.)
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LNB+OFA+SCR would result in a 12.5 dv cumulative improvement. Assuming a five 

year remaining useful life, the cost-effectiveness expressed in $/dv would be $4 million, 

well below the OR DEQ threshold of $10 million/dv.

LNB+OFA+SNCR would result in a 9.9 dv cumulative improvement. Assuming a two 

year remaining useful life, the cost-effectiveness expressed in $/dv would be $2 million, 

well below the OR DEQ threshold of $10 million/dv.

BART analysis for SO2

Consistent with EPA’s BART Guidelines, the five steps for a case-by-case BART 

analysis were followed.

Step 1 – Identify all available retrofit control technologies

OR DEQ: The SO2 control technologies that are feasible at Boardman include: ReducedSulfur Coal, Dry Sorbent Injection (DSI), Ultra-Low-Sulfur Coal, Semi-Dry FGD 

(SDFGD), Wet FGD (WFGD)

NPS: OR DEQ evaluated a reasonable suite of options.

Step 2 – Eliminate technically infeasible options

OR DEQ: DEQ eliminated none of the above from further analysis.

NPS: We agree with OR DEQ’s approach.

Step 3 – Evaluate the control effectiveness of the remaining technologies 

OR DEQ: The basis for the control effectiveness of...semi-dry FGD, wet FGD...was 

discussed in the previous report and there is no new information to suggest revising the 

previous conclusions.

NPS: We call attention to the permit issued by Nevada to Newmont Nevada requiring its 

SDFGD to meet the following limits:

Section V. Specific Operating Conditions (continued)

A. Emission Unit #S2.001 - Pulverized Coal Fired Boiler (continued)

2. NAC 445B.3405

a. Emission Limits (continued)

(7) Article 8.2.1.2 Federally Enforceable SIP - The discharge of sulfur to the atmosphere 

will not exceed 1,218.0 pounds per hour.

(8) NAC 445B.305 BACT Emission Limit – The discharge of SO2 to the atmosphere will 

not exceed:

(i) While combusting coal with a Sulfur content equal to or greater than 0.45 percent (30-

day rolling period), based on daily ASTM sampling:

(a) 0.09 pound per million Btu, based on a 24-hour rolling average period.

(b) 95% minimum SO2 removal efficiency will be maintained across the system, based on 

a 30-day rolling period.

(ii) While combusting coal with a Sulfur content less than 0.45 percent (30-day rolling 

period), based on daily ASTM sampling:

(a) 0.065 pound per million Btu, based on a 24-hour rolling average period.

(b) 91% minimum SO2 removal efficiency will be maintained across the system, based on 

a 30-day rolling period.
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STEP 4 –Evaluate Impacts and Document the Results

NPS: According to PGE, “The cost estimates are consistent in format with the guidance 

from the EPA’s Office of Air Quality Planning and Standards Cost Manual.” However, 

while PGE’s estimation methods resemble the Cost Manual method for estimating 

scrubber costs, the values and estimation factors actually used by PGE are consistently 

higher than those used by the Cost Manual. PGE has also included a $37 million 

Allowance for Funds During Construction (AFUDC) which may not be creditable.16 As a 

result, PGE has estimated a TCI of $247 million versus a straightforward application of 

the Cost Manual method which yields $168 million.

For Direct Annual Costs, PGE estimated $13.0 million versus the Cost Manual estimate 

of $8.5 million.

Again, we agree with OR DEQ that “remaining useful life” is a very important factor in 

the economics of the BART analysis. For example, if we assume a remaining useful life 

of 15 years (the scrubber default) in cell C29 in the “Given/Assume” tab of the 

“Boardman dry scrubber cost effectiveness” workbook, our estimate (“Ann Cost” tab cell 

K31) of Indirect Annual Cost (to amortize the scrubber investment) is $25 million/yr and 

the cost/ton of the LNB+OFA+SCR system becomes $2,900/ton (cell C11 of the “$T” 

tab). However, if one enters a shorter life, e.g., three years, into cell C29 in the “Given 

Assume” tab of the workbook, the Indirect Annual Cost rises to $71 million and the 

cost/ton rises to almost $7,000/ton over three years. Nevertheless, based upon OR DEQ’s 

cost-effectiveness threshold of $7,300/ton, one would conclude that SDFGD would be 

cost-effective if used for only three years before plant shut-down.

STEP 5 – Evaluate Visibility Impacts

Base Case: According to OR DEQ, Mt. Hood is the most-impacted Class I area with a

98th percentile value of 4.98 deciview (dv), and the cumulative impact across all 14 Class 

I areas is 31.46 dv. (Boardman ranks as having the fourth-highest cumulative impact of 

any BART source we have reviewed to date.)

Addition of the SDFGD would result in a 10.6 dv cumulative improvement. Assuming a 

three year remaining useful life, the cost-effectiveness expressed in $/dv would be $7.5 

million, well below the OR DEQ threshold of $10 million/dv.

The BART Determination

Cost-Effectiveness Metrics

BART is not necessarily the most cost-effective solution. Instead, it represents a broad 

consideration of technical, economic, energy, and environmental (including visibility

 

16 E-mail from Larry Sorrels, EPA OAQPS, to Don Shepherd dated 7/21/10. “I agree with including 

AFUDC in a capital cost estimate if this is already included in the base case as per a utility commission 

decision. Otherwise, I do not agree with its inclusion.”
9

improvement) factors. We agree with OR DEQ that it is appropriate to consider both the 

degree of visibility improvement in a given Class I area as well as the cumulative effects 

of improving visibility across all of the Class I areas affected. It simply does not make 

sense to use the same metric to evaluate the effects of reducing emissions from a BART 

source that impacts only one Class I area as for a BART source that impacts multiple 

Class I areas. And, it does not make sense to evaluate impacts at one Class I area, while 

ignoring others that are similarly significantly impaired. If we look at only the mostimpacted Class I area, we ignore that the other Class I areas are all suffering from 

impairment to visibility “caused” by the BART source. It follows that, if emission from 

the BART source are reduced, the benefits will be spread well beyond only the most 

impacted Class I area, and this must be accounted for.17

The BART Guidelines represent an attempt to create a workable approach to estimating 

visibility impairment. As such, they require several assumptions, simplifications, and 

shortcuts about when visibility is impaired in a Class I area, and how much impairment is 

occurring. The Guidelines do not attempt to address the geographic extent of the 

impairment, but assume that all Class I areas are created equal, and that there is no 

difference between widespread impacts in a large Class I area and isolated impacts in a 

small Class I area. To address the problem of geographic extent, we have been looking at 

the cumulative impacts of a source on all Class I areas affected, as well as the cumulative 

benefits from reducing emissions. While there are certainly more sophisticated 

approaches to this problem, we believe that this is the most practical, especially when 

considering the modeling techniques and information available. 

We note that OR DEQ has established a cost/ton threshold of $7,300 based upon actions 

in other states (e.g., MN, NM), and upon the premise that improving visibility in multiple 

Class I areas warrants a higher cost/ton than where only one Class I area is affected. We 

support this premise, and add that Wisconsin is using $7,000 - $10,000/ton as its BART 

threshold.18

One of the options suggested by the BART Guidelines to evaluate cost-effectiveness is 

cost/deciview. Compared to the typical control cost analysis in which estimates fall into 

the range of $2,000 - $10,000 per ton of pollutant removed, spending millions of dollars 

per deciview (dv) to improve visibility may appear extraordinarily expensive. However, 

our compilation19 of BART analyses across the U.S. reveals that the average cost per dv

proposed by either a state or a BART source is $14 - $18 million,

20 with a maximum 

 

17 For example, our analysis, which is described later, indicates that the cumulative benefits of reducing 

NOx emissions from NGS are seven times greater than the benefit at the most-impacted Class I area.

18 “The Department used cost-per-ton reduced as the primary metric for determining the BART level of

control. The upper limit for this metric was $7,000 to $10,000 per ton, which reflects historical low-end 

costs for controls required under BACT.” BEST AVAILABLE RETROFIT TECHNOLOGY AT NONEGU FACILITIES April 19, 2010, WISCONSIN DEPARTMENT OF NATURAL RESOURCES

19 http://www.wrapair.org/forums/ssjf/bart.html

20 For example, PacifiCorp has stated in its BART analysis for its Bridger Unit #2 that “The incremental 

cost effectiveness for Scenario 1 compared with the baseline for the Bridger WA, for example, is 

reasonable at $580,000 per day and $18.5 million per deciview.”
10

of $51 million per dv proposed by South Dakota at the Big Stone power plant. We note 

that OR DEQ has chosen $10 million/dv as a cost criterion, which is somewhat below the 

national average. 

We have a concern with the way in which the incremental cost analysis is used by OR 

DEQ. According to EPA’s BART Guidelines, “You should consider the incremental cost 

effectiveness in combination with the average cost effectiveness [emphasis added] 

when considering whether to eliminate a control option...You should exercise caution 

not to misuse these [average and incremental cost effectiveness] techniques... [but 

consider them in situations where an option shows]...slightly greater emission 

reductions...” However, incremental costs are rarely estimated and evaluated, so the 

much higher numbers that result appear quite high at first glance. For example, all of the 

incremental costs estimated by OR DEQ are much higher than the average costs, yet OR 

DEQ is using the same $10 million/dv threshold for both average and incremental costs. 

However, a rigid use of incremental cost effectiveness will always result in the choice of 

the cheapest option if carried to the extreme. (For example, if only incremental costs were 

used to evaluate PM controls, it is likely that all controls more expensive than a multiple 

cyclone would be rejected.) To use incremental costs properly, they must be compared to 

incremental costs for similar situations. We do not have data on incremental cost/dv, nor 

has OR DEQ presented any data to show how its $10 million/dv threshold for 

incremental cost-effectiveness compares to other BART determinations.

Option 1: Plant closure by 12/31/20 

Sulfur dioxide: 

OR DEQ: The SDFGD control technology is considered BART because it provides 

significant visibility improvement and is cost effective even with plant closure on 

12/31/20.

NPS: We agree.

Nitrogen oxides: 

OR DEQ has determined that LNB with SNCR is BART if the plant closes on 12/31/20. 

At a cost of $8,337/ton, SCR is not considered cost effective for the purposes of BART. 

NPS: We have shown that PGE has overestimated the costs of SCR and underestimated 

its effectiveness. The analyses which we are now providing demonstrate that, if SCR is 

operated for at least five years, its cost meets the OR DEQ $7,300/ton threshold, and that 

the cost/dv of $4 million is also well below the OR DEQ threshold of $10 million/dv.

Option 2: Plant closure by 12/31/18 

Sulfur dioxide: 

DEQ has determined that DSI is BART if the plant closes on 12/31/18. This conclusion is 

based on the following information: 

 WFGD and SDFGD are not cost effective if the Boardman Plant closes on 

12/31/18. The cost of SDFGD is approximately $7,300/ton, which is not 

considerable reasonable. WFGD is even more costly than SDFGD. 
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 Dry sorbent injection (DSI) is a demonstrated technology, albeit on smaller units 

than the Boardman Plant. DSI can achieve 70 to 90% emission reductions. Taking 

into consideration the size of the Boardman Plant, it is estimated that a DSI 

system could achieve a 35% emission reduction. DSI is cost effective and 

provides 0.84 deciview improvement in the Mt. Hood Wilderness area and greater 

than 7 deciview improvement for all Class I areas. DSI was considered feasible in 

at least one other BART analysis (Stanton Station Unit 1). The effectiveness of 

the control was also estimated at 35%. 

NPS: Not only has PGE overestimated the cost and underestimated the effectiveness of

SDFGD, OR DEQ is using the PGE estimates in an inconsistent manner by stating that 

SDFGD at $7,300/ton is not cost-effective in this specific instance, while $7,300/ton was 

accepted in other cases. We have demonstrated that, even if SDFGD is used for only

three years, its $6,800/ton and $7.4 million/dv costs would meet OR DEQ’s acceptance 

criteria.

If OR DEQ decides that DSI is BART, it should require PGE to design and install the 

DSI system to achieve 90% efficiency and require that PGE optimize its effectiveness for 

the duration of its operation.

Nitrogen oxides: 

OR DEQ evaluated the same control technologies for Option 2 as for Option 1 and 

concluded that BART is the same for both Options. Even with an earlier closure date, 

LNB with SNCR is still considered cost effective. PGE determined that SNCR can achieve 

an emission rate of 0.19 lb/mmBtu. LNB with SNCR will result in a 1.62 deciview 

improvement in the Mt. Hood Class I area and 9.87 deciview improvement for all Class I 

areas. 

NPS: We agree.

Option 3: Plant closure 5 years from when EPA approves the revisions to the SIP. 

OR DEQ recommends adding an option to the regional haze requirements that would exempt 

PGE from complying with the emission limits and standards effective on and after 7/1/14, if

the coal-fired plant is shut down within 5 years of the date EPA approves DEQ’s regional 

haze plan as a revision to the state implementation plan. This option is based on 40 CFR 

51.302(c)(4)(iv): 

(iv) The plan must require that each existing stationary facility required to install and 

operate BART do so as expeditiously as practicable but in no case later than five years after 

plan approval. 

NPS: The cited portion of the BART Guidelines cited by OR DEQ contains a 

requirement that BART be implemented “as expeditiously as practicable.” We have 

demonstrated that, even if the remaining useful life of the LNB+OFA+SNCR system is 

only two years, its cost-effectiveness is still well below OR DEQ’s $7,300 ton threshold. 

Although OR DEQ has not provided sufficient data on the costs of Dry Sorbent Injection 

(DSI), it is possible that DSI could also meet OR DEQ’s cost-effectiveness threshold 

even if used for only a few years. OR DEQ should require that Boardman install those 

emission controls that can be expected to meet its acceptance criteria over the remaining 
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useful life of the plant if those controls are, indeed, installed “as expeditiously as 

practicable.”

Conclusions & Recommendations

OR DEQ has produced one of the best BART analyses we have seen to date. 

Nevertheless, we believe that improvements could be made:

 Use real-world CAM data to estimate the effectiveness of SCR.

 Consider the permit issued by NV to Newmont Nevada as a strong indicator that 

SDFGD can achieve lower emission than assumed by PGE.

 Give preference to costs estimated in accordance with the BART Guidelines 

instead of those presented by PGE.

 Do not use incremental costs unless a basis for comparison to other incremental 

costs is also used.

 Require that Boardman install those emission controls that can be expected to 

meet the OR DEQ acceptance criteria over the remaining useful life of the plant 

“as expeditiously as practicable.”