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 el ectrostatic precipitator to control particulate matter. Current Actual NO x 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 ye ar (tp y)S O 2 (0. 61 lb SO 2/mmBtu) and 10,349 tpy NO X (0.43 lb NO x/mmBtu)
. Based upon our review of EPA’s Clean Air Markets (CAM) data for this facility, these estimates of actual SO 2 and NO x emissions appear reasonable for the annual cost analyses . According to the CAM database, facility SO 2 emissions have averaged 13,025 tons per ye ar (tpy) and 0. 65 lb/mmBtu during 2000

– 200 9 . F acility NO X 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 b y various control options are somewhat lower than had we used the OR DEQ data.) BART analysis for NO X Consistent with the Environmental Protection Agency (EPA) ’s BART Guidelines , the five steps for a case
-by
- case BART analys is were followed. Step 1
– Identify all available retrofit control technologies OR DEQ : The NO X control technologies that are feasible at Boardman include: LowNO X 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 NO X)

. NPS: We agree with OR DEQ’s approach. Step 3
– Evaluate the control effectiveness of the remaining technologies2

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 i s 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. Iti s generally understood that NO X reductions of approximately

9 0% or more may

b e achieved with SCR systems . 1 And, according to the June 13, 2009 “Power” magazine article “Air Quality C ompliance: Latest Costs for SO 2 and NO X 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 c oal
fired. AEP is under a New Source Review (NSR) consent decree signed in 2007 that requires the utility

install air quality

control systems to reduce NO X by 90%...” If we assume a 90% reduction by S CR f rom the 0.23 lbNO X/mmBtu emiss ion 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 0.0 7 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 lower2 at 27 coal
- fired EGUs, nine of which are wall
- fired units like Boardman
. Although we believe that SCR is capable of even lower annual NO x 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 advis ed 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 areferenced source (such as the OAQPS

1 According to the Institute of Clean Air Com panies white paper titled “Selective Cataly tic Reduction (SCR) Control of NO x Emissions from Fossil Fuel
-Fired Electric Power Plants” (published in May 2 009), “By proper catalyst selection and system design, NO X removal efficiencies exceeding 90 perc ent may be achieved.” 2 Our review of

operating data suggests that a NO X 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 mo deling 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 NO X emission rate of 0.05 lb/mmBtu based on recent emission guarantees of fered by SCR system suppliers.”3 Control Cost Manual, Fifth Edition, February 1996, 453/B
- 96 - 001). In order to maintain and im prove consistency, cost estimates should be based on the OAQPS Control Cost Manual, where possible. The Control Cost Manual addresses mo st control technologies in sufficient detail for a BART analysis. The cost analysis should also take into account any s ite
- 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 analys es 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 SO 2 and PM cost analyses were com pleted using the CUECost mo del. 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 D EQ 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 advised4 us e 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 M anual methods for estimating SNCR and SCR co sts. 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 L NB+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 equate s to a capital cost of $ 246/kW 5 for the routine 6 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 P GE, we app lied 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 O AQPS , to Don Shepherd dated 7/21/10. “On cost indexes, I prefer the CEPCI for escalating/deescalating costs f or chemical plant and utility processes since this index sp ecifically c overs 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 industry
level cost estimation, but is not as accurate at a disaggregated level when com pared 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 mo difications 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. B y applyingthe 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 : 7 “One more current data set is the historic cap ital costs reported by AEP averaged over several ye ars 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% NO X 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 ye ar average experienced from 2004 to 2006 (from the FGD survey results). Applying those annual increases to the 2004 estimates for three ye ars (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 o f 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 $1 0 6 to $2 1 3/kW, converted to 200 7 dollars. 8 Costs are escalated through using the CEPCI
. The second survey

o f 40 installations at 24 stations reported a cost range of $ 76 to $2 42/kW , converted to 200 7 dollars. 9

7 June 13, 2009 “Power” magazine article “Air Quality Com pliance: Latest Costs fo r 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
- com pliance
- latest
- costs - for
- so2 - and
-nox-removal
effective
- 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 2 003. 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 2 008 to 2003 (575.4/401.7) for upper end of range, based on Figure 3.5

The third study, by

the Electric Utility

C ost Group, surveyed 72 units totaling 41 GW, or 39% of installed SCR systems in the U.S. This study reported a cost range of $1 18 /kW to $ 261 /kW , converted to 200 7 dollars. 10 A fourth study, presented in a course at PowerGen 2005, reported an upper bound range of $1 80/kW to $2 02/kW , converted to 200 7 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 $2 65 /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 $2 51 /kW in 200 7 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 exampl es 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/y r 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 analys is. For example, if we assume a remaining useful life of 20 ye ars (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/y r and
10 M. Marano, Estimating SCR Installation Costs, Power, January/February 2006. Ex. 5. The reported range of $100
- $221/kW wa s converted to 2008 dollars ($130
- $286/kW) using the ratio o f 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) wa s 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 P ower Plant Emissions Control Technologies, June 2007, pp. 28
-29, Figure 7
- 1 (Ex. 1). 13 Steve Blankinship, SCR = Supremely C omplex 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.htm6

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 ye ars, 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 ye ars. 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 ye ars before plant shut
- down. There is a wide discrepancy b etween 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 % NO x reduction from the 0.2 3 lb/mmBtu to be achieved by c ombustion controls. Although modern SCR systems are ty pically designed to achieve 90+% NO x reductions, we assumed a 0.05 lb/mmBtu (a 7 8 % reduction) “target” for SCR based upon the performance of the eastern boiler retrofits discus sed 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 c ompared to real
-world industry data, while our $209/kW appears reasonable. PGE should provide detailed descriptions of how its SCR TCI c osts 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 b y the BART Guidelines.  For remaining useful life of five ye ars 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 ye ars (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 mo st- impacted Class I area with a 98 th 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.)7

LNB+OFA+SCR would result in a 12.5 dv cumulative improvement. Assuming a five ye ar 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 ye ar 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 SO 2 Consistent with EPA’s BART Guidelines, the five steps for a case -by
- case BART analys is were followed. Step 1
– Identify all available retrofit control technologies OR DEQ : The SO 2 control technologies that are feasible at Boardman include: Reduced
Sulfur Coal, Dry

S orbent In

jection (DSI), Ultra
- Low- Sulfur Coal, Semi
-Dry F GD (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 b asis for the control effectiveness of...semi
- dry F GD, 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 N evada 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 SO 2 to the atmosphere will not exceed: (i) While combusting coal with a Sulfur content equal to or greater than 0.4 5 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 SO 2 removal efficiency will be maintained across the s ystem, 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 SO 2 removal efficiency will be maintained across the s ystem, based on a 30 - day rolling period.8

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 M anual.” However, while PGE’s estimation methods resemble the Cost Manual method for estimating scrubber costs, the values and estimation factors actually used by P GE 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 TCIo f $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 ye ars (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/y r 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 ye ars, 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 mo st- impacted Class I area with a 98 th 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 ye ar 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 vi sibility

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 s ignificantly 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 lo oking 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, espe cially 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 Cl ass 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 ty pical control cost analys is 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 a ppear extraordinarily expensive. However, our compilation 19 of BART analys es across the U.S. reveals that the average cost per dv proposed by either a state or a BART source is $1 4 - $ 18 million , 20 with a maximum

17 For example, our analysis, which is described later, indicate s that the cumulative benefits of reducing NO x 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 wa s $7,000 to $10,000 per ton, which reflects historical low
- end costs for controls required under BACT. ” BEST AVAILABLE RETROFIT TECHNOLOGY ATNONEGU 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 $5 1 million per dv proposed by South Dakota at the Big S tone 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 co st 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 gl ance. 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 compare s to other BART determinations. Option 1: Plant closure by 12/31/20 Sulfur dioxide: OR DEQ: The SDFGD control technology i s 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 ye ars, 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.11

 Dry s orbent injection (DSI) is a demonstrated technology, albeit on smaller units than the Boardman Plant. DSIc an 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. DSIi s 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. DSIwas considered feasible in at least one other BART analys is (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 DSIi s BART, it should require PGE to design and install the DSIsystem 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 ye ars 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 S orbent In

jection (DSI), it is possible that DSIc ould 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 remaining12

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.”