ALASKA CALIFORNIA FLORIDA MID-PACIFIC NORTHEAST NORTHERN ROCKIES 

NORTHWEST ROCKY MOUNTAIN WASHINGTON, DC INTERNATIONAL 

705 SECOND AVENUE, SUITE 203 SEATTLE, WA 98104-1711 

T: 206.343.7340 F: 206.343.1526 E: eajuswa@earthjustice.org W: www.earthjustice.org

November 15, 2010 

Via email: 

Brian Finneran 

Oregon Department of Environmental Quality 

811 SW 6th Avenue 

Portland, OR 97204 

Re: Comment: Portland General Electric Boardman Plant BART Analysis Revision 3--

2020 Alternative Analysis

Dear Mr. Finneran: 

These comments are submitted on behalf of Sierra Club, Friends of the Columbia Gorge, 

Northwest Environmental Defense Center, Columbia Riverkeeper and Hells Canyon 

Preservation Council (the “Coalition”). The Coalition urges the Oregon Department of 

Environmental Quality (the “Department”) to: (1) reject the Regional Haze Best Available 

Retrofit Technology (“BART”) Approach outlined by Portland General Electric’s (PGE) letter of 

October 22, 2010 as not in compliance with federal law and regulation; and (2) retain BART 

compliance alternatives consistent with the earlier cessation of coal-fired operations at the 

Boardman plant (the “Plant”). 

The Coalition generally applauds the Department's interest in securing PGE's assent to 

closure of the Boardman Plant as part of the BART process. That assent should not, however, be 

purchased at the cost of following the law, nor the cost of continued impermissible air pollution 

in our National Parks and wilderness areas. The Department should not accept PGE's 2020 

proposal. 

INTRODUCTION AND BACKGROUND 

The Department’s existing Regional Haze Plan, adopted in 2009, requires: new low 

Nitrogen Oxides (NOx) burners, with a modified over-fire air control system to be installed in 

2011, and selective catalytic reduction (“SCR”) devices to be installed in 2017, to control the 

Plant’s NOx emissions; as well as semi-dry flue gas desulfurization (“FGD”) to be installed in 

2014 to control the Plant’s sulfur dioxide (“SO2”) emissions. 

This year, the Department proposed amendments to that Plan that would accommodate 

the closure of the Boardman Plant by 2015/16, 2018 or 2020. The Department’s 2020 closure 

alternative relaxes the existing requirements, instead prescribing: low-NOx burners and a 

modified over-fire air control system in 2011, and a selective non-catalytic reduction (SNCR) 

system in 2014, to reduce the Plant’s NOx emissions to 0.19 lb/MMBtu; and a semi-dry FGD 

system in 2014 to control SO2 emissions to a level of 0.12 lb/MMBtu. The Department’s 2018 
Brian Finneran 

Oregon Department of Environmental Quality 

November 15, 2010 

Page - 2 - 

closure alternative includes the same NOx controls, but requires only Dry Sorbent Injection 

(“DSI) by 2014, to reduce the Plant’s SO2 emissions to 0.04 lb/MMBtu. See DEQ BART Report 

for the Boardman Power Plant (September 1, 2020) (“BART Report”) 20-21. The Department 

also allowed PGE to close the Boardman plant in 2015 without complying with 2014 BART 

requirements. Id. at 21. 

PGE has in turn proposed even less stringent requirements: a “BART Approach” that 

would allow it to continue coal-fired operations until December 31, 2020, employing only DSI to 

control the Plant’s SO2 emissions to a level of 0.4 lb/MMBtu in 2014, and 0.3 lbs/MMBtu in 

2018, contingent upon “testing . . . of the installed SO2 control system to confirm the applicable 

SO2 emissions limit is achievable without causing an exceedance of PM10 or PM2.5 ambient 

standards, preventing PGE from meeting mercury reduction goals, or causing significant 

operational issues.” Letter from Stephen Quennoz to Dick Pedersen dated October 22, 2010 

(“PGE Letter”); Portland General Electric Boardman Plant Best Available Retrofit Technology 

Reasonable Progress Analysis Revision 3: Boardman 2020 Alternative (“PGE 2020 Alternative 

Analysis”). 

For the reasons set forth below, PGE’s proposed alternative does not meet the Clean Air 

Act’s Regional Haze requirements, and should be rejected on those grounds. Even if the 

Department chooses to approve PGE’s alternative, it should retain a 2018 alternative (as detailed 

below). The Boardman plant will soon be subject to National Emissions Standards for 

Hazardous Air Pollutants. It is currently in violation of the Act’s Prevention of Significant 

Deterioration and New Source Performance Standard requirements. Impending regulatory or 

judicial actions will, therefore, likely render it impossible for PGE to continue coal-fired 

operations at Boardman until 2021 with the minimal suite of pollution controls it proposes to 

satisfy the Act’s Regional Haze requirements. BART alternatives allowing the earlier closure of 

the Plant, in contrast, may allow PGE to satisfy the Act’s other requirements. The Department 

should, therefore, ensure that those alternatives remain available while PGE’s remaining Clean 

Air Act obligations are established. 

 This letter will first address PGE’s erroneous claim that it can avoid BART should certain 

BART alternatives trigger other Clean Air Act requirements and PGE’s improper use of 

“remaining useful life” in its BART analysis. Second, this letter will demonstrate how PGE and 

the Department’s BART analysis for SO2 and NOx overestimates cost and is incorrect in its 

feasibility determinations for certain BART technologies. Finally, this letter will address how 

the Department’s cost-effectiveness determinations must take into account the very large number 

of Class I areas that are affected by these determinations and the failure of the 2020 Alternative 

to achieve an acceptable level of reasonable further progress required by the law. 
Brian Finneran 

Oregon Department of Environmental Quality 

November 15, 2010 

Page - 3 - 

I. PGE’S 2020 BART ANALYSIS MIS-APPLIES THE GOVERNING LEGAL 

FRAMEWORK. 

A. PGE’s Requested “Feasibility” Exemptions Are Illegal. 

PGE’s proffered 2020 alternative requires PGE only to conduct a pilot study regarding 

DSI at the Plant. Proposed Revisions to DEQ Regional Haze BART Rules for the PGE 

Boardman Plant (October 29, 2010) (“Proposed Revisions”) p.3. It does not require PGE to 

install and operate the system unless: (a) operation of the DSI system triggers no further 

obligations under Oregon’s mercury rule; (b) operation of the DSI system results in no 

significant air quality impacts for PM10 or PM2.5, triggering additional Clean Air Act 

obligations; and (c) the system results in no “significant operational issues.” PGE Letter at 2, 

Proposed Revisions at 4. Unless those conditions are met, PGE need only utilize relatively lowsulfur coal, thereby limiting its SO2 emissions to .6 lb/MMBtu. PGE justifies those conditions – 

effectively, an exemption from BART – by contending that DSI is not technically feasible unless 

they are satisfied. PGE 2020 Alternative Analysis at 4-2. In so doing, PGE mistakes the 

requirements of the Clean Air Act and its implementing regulations. 

First, DSI cannot be discarded as technically infeasible merely because its installation 

triggers additional legal obligations under the Clean Air Act (or state law). As the 

Environmental Protection Agency’s (“EPA”) implementing regulations make clear, “[c]ontrol 

technologies are technically feasible if either (1) they have been installed and operated 

successfully for the type of source under review under similar conditions, or (2) the technology 

could be applied to the source under review.” 40 C.F.R. Pt. 51 App. Y at 590. Where a 

technology is commercially available, and has been used on the same or similar source type, it is 

technically available.” Id. at 590-91. Conversely, in order to discard a commercially available 

technology as technically infeasible, an agency must demonstrate that the technology is 

incapable of addressing the “characteristics of the pollutant-bearing gas stream,” or “that there 

are unresolvable technical difficulties with applying the control to the source.” Id. at 591. 

“Where the resolution of technical difficulties is merely a matter of increased costs, you should 

consider the technology to be technically feasible.” Id. 

The Department cannot, therefore, conclude that DSI is technically infeasible because it 

would interfere with PGE’s compliance with state mercury reduction goals, or result in adverse 

impacts to the particulate matter air quality standards. As a legal matter, the Act demands that 

PGE comply with all of its requirements – both those associated with Regional Haze, and those 

intended to prevent significant deterioration of air quality and any requirements to reduce 

hazardous pollutants such as mercury. The Department cannot excuse PGE from compliance 

with the one requirement (Regional Haze), in order to avoid another (Prevention of Significant 

Deterioration or “PSD”). Moreover, as a practical matter, even if operation of DSI triggers 

additional legal obligations, those obligations will not prevent PGE from continuing to operate 

the Plant. Should DSI result in particulate matter emissions sufficient to trigger Prevention of 

Significant Deterioration Review, and to affect compliance with particulate matter air quality 
Brian Finneran 

Oregon Department of Environmental Quality 

November 15, 2010 

Page - 4 - 

standards, PGE would be required either to install a bag-house at the Plant, or to secure offsetting reductions in particulates. New Source Review Workshop Manual: Prevention of 

Significant Deterioration and Nonattainment Area Permitting (U.S.E.P.A. Draft October 1990) at 

p. C.52-53. While those additional steps might entail additional cost, they do not render DSI 

infeasible – much less technically infeasible. 

Second, even if DSI were genuinely technically infeasible, PGE would not be entitled to 

the de facto exemption from BART that it requests. The Department has an obligation to 

identify, and prescribe, a technically feasible BART limit. 42 U.S.C. § 7491(b)(2)(A). DSI is 

technically feasible, as explained in greater detail below. But if it were not feasible, the 

Department would need to undertake a full five-factor BART analysis that specifies a limit based 

on some other, feasible control technology. PGE instead asks the Department to set a limit of 0.6 

lb/mmBTU, based on the reductions available through only the use of coal with a (moderately) 

low sulfur content.1 It has not, and cannot, justify that limit as satisfying BART. 

The Coalition objects to PGE’s artificial “feasibility” exemption from compliance with 

full BART requirements. PGE must comply with all applicable Clean Air Act requirements. 

B. The Department Cannot Give “Remaining Useful Life,” or Other Statutory 

Factors, Consideration That Conflicts With EPA’s Implementing Regulations. 

PGE asks the Department to adopt its 2020 Alternative based on application of the 

concept of “remaining useful life” of the Plant, in addition to modifying costs of compliance to 

reflect the remaining life.2 The Department may not do so. EPA has established the manner in 

which remaining useful life is to be considered: “the ‘remaining useful life’ of a source, if it 

represents a relatively short time period, may affect the annualized costs of retrofit controls.” 40 

C.F.R. Pt. 51 App. Y at 597. No further consideration is required – or permitted – to satisfy the 

Clean Air Act’s directive to consider the “remaining useful life” of the Plant. By translating the 

capital-related costs of compliance into annualized figures reflecting the useful life of the 

facility, EPA’s regulations accomplish the consideration required by the statute. The Act does 

not allow Department to double-count the remaining useful life factor by adjusting the costs of 

compliance, and then further discounting PGE’s BART obligations. See also See United States v. 

Cinergy Corp., 458 F.3d 705, 707-8 (7th Cir. 2006). 

PGE includes similar impermissible double-counting throughout its proposal. For 

example, it suggests that even after calculating annualized costs over a limited time-frame, the 

Department should limit its BART obligations because DSI has lower capital costs, and higher 

operating costs, than an FGD system. PGE 2020 Alternative Analysis at 8-2. The Department 

 

1

 While this has been described as a “50% reduction in permitted emissions,” in fact it is a 2% 

reduction in actual emissions during the baseline period. 

2

 PGE 2020 Alternative Analysis at 6-4. 
Brian Finneran 

Oregon Department of Environmental Quality 

November 15, 2010 

Page - 5 - 

may not do so; the full suite of BART alternatives presented by its Regional Haze plan present 

no threat to viability of plant, and the relative capital costs are effectively incorporated into 

PGE’s annualized costs.3

 

II. PGE’S 2020 ALTERNATIVE ANALYSIS DOES NOT MEET THE REQUIREMENTS 

FOR BART. 

A. The BART Requirement. 

Federal regulations mandate that states’ regional haze SIPs include emission limitations 

representing BART for each BART-eligible source. 40 C.F.R. §51.308(e). BART is defined as 

follows: 

an emission limitation based on the degree of reduction achievable through the 

application of the best system of continuous emission reduction for each pollutant 

which is emitted by an existing stationary facility. The emission limitation must 

be established, on a case-by-case basis, taking into consideration the technology 

available, the costs of compliance, the energy and non-air quality environmental 

impacts of compliance, any pollution control equipment in use or in existence at 

the source, the remaining useful life of the source, and the degree of improvement 

in visibility which may reasonably be anticipated to result from the use of such 

technology. 

40 C.F.R. § 51.301. 

BART is to be determined based on a five factor analysis. 40 C.F.R. Part 51, Subpart Y, 

Section I.F.1. EPA’s five factor analysis requirements stems from statutory and regulatory 

requirements regarding how BART is to be determined. Specifically: 

The determination of BART must be based on an analysis of the best system of 

continuous emission control technology available and associated emission 

reductions achievable for each BART-eligible source that is subject to BART 

within the State. In this analysis, the State must take into consideration the 

technology available, the costs of compliance, the energy and nonair quality 

environmental impacts of compliance, any pollution control equipment in use at 

the source, the remaining useful life of the source, and the degree of improvement 

in visibility which may reasonably be anticipated to result from the use of such 

technology. 

40 C.F.R. § 51.308(e)(1)(ii)(A). See also, 42 U.S.C. § 7491(g). 

 

3

 In fact, PGE consistently includes impermissible costs in its analysis. For example, it includes 

the costs of replacement power in its analysis. Id. at 8-2. 
Brian Finneran 

Oregon Department of Environmental Quality 

November 15, 2010 

Page - 6 - 

These requirements are similar to how best available control technology (“BACT”) is 

determined for new and modified sources subject to the prevention of significant deterioration 

permitting requirements. EPA guidance requires that in evaluating BACT for a particular 

source, if similar sources have had to bear certain costs to meet BACT, such costs should be 

presumed reasonable for the source in question.4

 The Department, along with many other state 

agencies, the Federal Land Managers (“FLMs”), and EPA, have applied this same concept to 

BART determinations. This helps to ensure that BART is interpreted consistently across similar 

source categories. 

Cost is only one of the factors to be taken into account in determining BART. Another is 

the degree of visibility improvement expected from the controls being evaluated as BART. The 

Department, along with many other states and the FLMs, have evaluated the cost per deciview of 

visibility improvement ($/dv) in its BART analysis. And, again, comparing this to the costs that 

have been required to be borne by similar sources helps to ensure BART is interpreted 

consistently across similar source categories. 

EPA has also published BART guidelines to ensure consistency in BART determinations 

across similar source categories. 40 C.F.R. Part 51, Appendix Y. EPA’s regional haze 

regulations only mandate that the guidelines be followed for plants with generating capacity of 

750 megawatts or greater, see, 40 C.F.R. §51.308(e)(1)(ii)(B). Regardless, states are required to 

have a reasoned basis for their case-by-case BART determinations and the methodology laid out 

in the BART guidelines provides a solid framework for such reasoned determinations. 

BART is only one component of the regional haze program, but it is a very significant 

part of the program. The intent of the regional haze requirements is to restore natural visibility 

conditions to the nation’s national parks and wilderness areas. EPA’s regional haze regulations 

set a target date for natural visibility conditions of 2064. 40 C.F.R. §51.308(d)(1)(i)(B). States’ 

regional haze plans are supposed to provide for sufficient emission reductions by the first 

reasonable progress milestone to be on the “glide path” to reach natural background visibility 

conditions by 2064. The first reasonable progress milestone is 2018. 40 C.F.R. §51.308(f). 

Indeed, EPA refers to the BART requirements as one of the “principal elements of the visibility 

protection provisions.” See, e.g., 64 Fed. Reg. 35737 (July 1, 1999). And given the timeframe 

within which BART must be implemented, i.e., as expeditiously as practicable no later than five 

years from the date which EPA approves the SIP (pursuant to 40 C.F.R. §51.308(e)(1)(iv)), the 

BART requirements will greatly help states in achieving the first reasonable progress milestone 

in 2018. 

B. A Semi-Dry FGD System Is a Cost-Effective BART Control For SO2 Even if 

Boardman Shuts Down or Ceases Burning Coal by December 31, 2020.

1. The Department’s estimates and analysis. 

 

4 See EPA’s New Source Review Workshop Manual, October 1990, at B.29. 
Brian Finneran 

Oregon Department of Environmental Quality 

November 15, 2010 

Page - 7 - 

The Department earlier found that a semi-dry FGD system designed to meet an SO2

emission limit of 0.12 lb/MMBtu was cost-effective as BART even if the system was only used 

for 6.5 years until Boardman either shuts down or stops using coal in December 2020. See DEQ 

2010 BART Report for the Boardman Power Plant at 18. Specifically, the Department 

determined that a semi-dry FGD system designed to meet an SO2 limit of 0.12 lb/MMBtu at 

Boardman but with a 6.5 year life would cost $5,535/ton of SO2 removed. Id. at 11. The 

Department found this cost was within the range of costs required as BART for SO2 at other 

sources. Id. at 18. The Department also determined that a semi-dry FGD system would be costeffective when evaluated on a dollar per deciview improvement basis. Specifically, the 

Department found semi-dry FGD would cost $6.25 million per deciview on a cumulative basis, 

and that such costs were reasonable. Id. at 16. 

While the Department found semi-dry FGD is cost-effective, it is actually more costeffective than the Department’s analysis indicates; the Department’s costs estimates for the 

system are far too high and include costs not allowed by the Control Cost Manual.5 The 

Department increased the cost estimates in its revised 2010 BART report to reflect 2010 dollars. 

A comparison of the Department’s 2010 cost estimates for semi-dry FGD to the cost estimates 

provided in its December 2008 report (which were in 2007 dollars) shows that the increase 

reflected in the Department’s 2010 cost estimates is not justified. Specifically, the capital cost of 

a semi-dry FGD in the Department’s 2010 BART analysis was $270.2 million which is 9.2% 

higher than the assumed capital cost provided in the Department’s December 2008 BART report 

(which reflected 2007 dollars).6 Economic indicators show a much lower rate of cost increases 

since 2007. Specifically, based on the Chemical Engineering Plant Cost Index (CEPCI), there 

was only a 5.9% increase in plant costs between 2007 and June 2010.7 

The Department also included in the capital costs “owner’s costs” and “Allowance for 

Funds Used During Construction (AFUDC).” EPA’s Control Cost Manual does not include 

AFUDC costs in determining capital costs of pollution controls.8

 

There is also no justification for including owner’s costs, which will be covered in the 

costing of engineering and home office fees. While owners do incur some costs, owners 

generally do not manage and implement capital projects, but rather retain engineering firms, 

 

5

 The EPA’s BART guidance specifically recommends the use of the EPA Control Cost Manual. 

See 70 Fed. Reg. 39166. 

6 See Attachment B DEQ 2010 BART data spreadsheet as compared to December 2008 DEQ 

BART Report at 19 (Table 15). 

7

 In June 2010, the CEPCI index was 556.4, as compared to the 2007 annual CEPCI index of 

525.4. 

8 See, e.g., EPA’s Control Cost Manual at 2-44. 
Brian Finneran 

Oregon Department of Environmental Quality 

November 15, 2010 

Page - 8 - 

called the owner's engineer, to perform these functions or, more commonly, hire an EPC 

contractor to perform the project for a fixed cost. Owner's cost is part of the factored estimate 

for engineering and home office fees, calculated as 10% of total direct cost, procurement, and 

construction management. Owner's costs are not separately included in BART cost effectiveness 

analyses and have been more than double counted here. In its May 10, 2010 formal comments to 

the North Dakota Department of Health, for example, EPA rejected the inclusion of "owner's 

costs" in a cost analysis for the Milton R. Young facility.9 

Revising the Department’s cost estimates for an semi-dry FGD by increasing its former 

2007 capital cost estimate by only 5.9% consistent with the CEPCI rates (rather than the 9.2% 

capital cost increase assumed by the Department) and excluding the owner’s costs and AFUDC 

costs, results in capital costs of an semi-dry FGD in 2010 dollars reduced to $215.7 million. At a 

6.5 year life, the annualized cost is $42.4 million/year. With this lower capital cost but making 

no other changes in the Department’s cost estimates, the total annualized cost of an semi-dry 

FGD in 2010 dollars would be $56.3 million, and the dollar per ton of SO2 removed costs is 

reduced to $4,697/ton of SO2 removed.10 The Department’s cost effectiveness numbers 

presented in its 2010 BART report for an semi-dry FGD with a 6.5 year life are too high. 

2. PGE’s estimates and analysis. 

In contrast to both the Department’s analysis and the proper analysis set forth above, on 

July 30, 2010, PGE submitted information to the Department indicating that the cost of 

installation of semi-dry FGD, based on a new analysis done by Sargent & Lundy, would be even 

higher than the Department’s 2010 estimate. Specifically, PGE found that an semi-dry FGD 

would cost over $6,500/ton of SO2 removal at Boardman. See PGE’s July 30, 2010 Letter to the 

Department at 13. Given the CEPCI index data for 2006 and June 2010, PGE’s projected cost 

increase is not justified. 

A closer evaluation of the details that went into PGE’s new semi-dry FGD cost analysis 

shows that PGE improperly included costs that are not supported by EPA’s Control Cost 

Manual. For example, the revised semi-dry FGD cost analysis provided by PGE includes $21.4 

 

9

 Letter from Andrew M. Gaydosh, Assistant Regional Administrator, EPA Region 8, to Terry 

O'Clair, Director, Division of Air Quality, North Dakota Department of Health, Re: EPA's 

Comments on the North Dakota Department of Health's April 2010 Draft BACT Determination 

for NOx for the Milton R. Young Station, May 10, 2010. 

10 These cost figures are based on the Department’s cost data, Attachment B to its 2010 

Boardman BART Analysis Boardman. The Department’s projections of annual operating 

expenses or the assumed SO2 removed per year were not revised. Only the capital costs have 

been revised as described. 
Brian Finneran 

Oregon Department of Environmental Quality 

November 15, 2010 

Page - 9 - 

million in the capital cost estimate as due to “owner’s costs.” See August 27, 2010 PGE 

Boardman BART/Reasonable Progress Analysis, Revision 3: Boardman 2020 Alternative, 

Appendix D at D-8. As noted above, the Department also improperly included such owner’s 

cost, but at a much lower amount ($6.4 million per year11). PGE’s analysis also includes $72.7 

million for AFUDC. The Department had also improperly included costs of AFUDC, but again 

at a much lower amount ($41.2 million12). PGE’s revised semi-dry FGD cost analysis also 

includes $9.8 million in property taxes in the capital cost estimate. Id. Pollution control 

equipment is typically exempt from property and sales taxes, which are usually assumed to be 

zero.13 

These discrepancies with the EPA’s Control Cost Manual, and with the CEPCI data, 

show that PGE’s cost estimates for semi-dry FGD are improperly elevated. PGE’s revised semidry FGD costs effectiveness estimate of $6,500/ton is not justified. 

Further, both the Department’s and PGE’s cost estimates are based on an achievable SO2

emission rate of 0.12 lb/MMBtu, which only reflects approximately 80% SO2 removal from 

current coal used at Boardman. Semi-dry FGD system can achieve 90-95% SO2 removal.14 

Proper consideration of the SO2 reductions that can actually be achieved with a semi-dry FGD 

system would thus show an even lower level of cost effectiveness than $4,697/ton. 

Finally, a review of the SO2 control costs required in other BART determinations shows 

that even an SO2 control cost of $6,500/ton is not out of the range of other SO2 BART 

determinations. According to the National Park Service’s summary data of SO2 BART 

determinations, the costs for SO2 BART determinations ranges up to $7,309/ton of SO2

removed.15 And it must be noted that the National Park Service summary spreadsheet does not 

include the cost data for the San Juan Generating Station which the Department relied upon, in 

which the New Mexico Environment Department proposed to find that costs ranging from 

$5,946/ton to $7,398/ton of SO2 removed were reasonable.16 

 

11 See Attachment B of the Department’s 2010 BART Report. 

12 Id.

13 OAQPS Control Cost Manual, 2002, Section 4.2, p. 2-48 ("In many cases property taxes do 

not apply to capital improvements such as air pollution control equipment...") 

14 See, e.g., discussion of this issue in the January 30, 2009 comment letter from Environmental 

Defense Fund and National Parks Conservation Association at 12-13. 

15 See National Park Service Spreadsheet EGUs with Proposed BART SO2 Controls, Updated 

August 2010, Exhibit 1. 

16 As discussed in the Department’s BART Report for the Boardman Power Plant, September 1, 

2010, at 18. 
Brian Finneran 

Oregon Department of Environmental Quality 

November 15, 2010 

Page - 10 - 

Because the properly calculated cost effectiveness of a semi-dry FGD at Boardman with 

a 6.5 year life would be lower than PGE’s assumed $6,500/ton and even lower than the 

Department’s estimate of $5,535/ton, semi-dry FGD is cost effective even if PGE agrees to shut 

down or stop burning coal at Boardman by December 31, 2020. 

 

C. DSI is BART both for a 2020 or a 2018 Alternative.

1. DSI is a technically feasible control technology at Boardman. 

A review of DSI technology demonstrates it to be technically feasible for Boardman. 

Although PGE questions the technical feasibility of DSI at Boardman, that claim is without 

merit. United Conveyor Corporations, a vendor of DSI systems, indicates that “DSI can be 

applied to any coal-fired unit for SO2 control.”17 PGE claimed DSI was not technically feasible 

for Boardman because it has not been used on a boiler of the type and size of Boardman. That is 

not the case. DSI has been tested on a 650 MW boiler burning Powder River Basin coal and 

achieved 83-86% SO2 removal.18 DSI has been proposed as BART for Dominion’s Kincaid 

power plant. This facility has two 660 MW units equipped with electrostatic precipitators 

(ESPs), and the units burn low sulfur Powder River Basin coal.19 DSI has also been proposed on 

numerous Edison Mission Energy electric utility generating units which range in size from 240 

to 890 MW.20 

The size of the Boardman unit is inconsequential as to whether DSI is technically feasible 

at Boardman. The factors that affect SO2 removal with DSI include: 

 Sorbent injection rate/Normalized Stoichiometric Ratio (NSR) 

 Sorbent particle size 

 Sorbent residence time in flue gas stream 

 Sorbent penetration and mixing with flue gas 

 Particulate control device used (ESP or baghouse) 

 Flue gas temperature 

o Minimum 275°F 

 

17 See United Conveyor Corporation, UCC Dry Sorbent Injection, Dry Sorbent Injection as an 

Alternative to Scrubbers, 8th slide (Exhibit 12). 

18 See Davidson, Heidi E., Solvay Chemicals Inc., SOLVAir® Select 150 Solution, presented at 

12th Annual Electric Power Conference, May 18-20, 2010, Baltimore, MD at 12 (Exhibit 2). 

19 See ENSR Corporation, BART Analysis for the Kincaid Power Plant, January 2009, at 1-2 

(Exhibit 3). 

20 See “Edison Mission Energy to Use Trona for SO2 Control on Illinois Power Plants,” FGD 

and DeNox Newsletter, October 2010, No. 390, Exhibit 4. 
Brian Finneran 

Oregon Department of Environmental Quality 

November 15, 2010 

Page - 11 - 

o The higher, the better up to 1500oF21 

Most of these factors are irrelevant to the boiler type or size. While the flue gas 

temperature can impact the SO2 removal efficiency with DSI, sorbent injection can work at a 

wide range of flue gas temperatures. The question is not whether DSI is technically feasible with 

the 600 MW Boardman boiler. It is more a matter of the level of SO2 removal efficiency that is 

achievable at Boardman with DSI. 

While DSI is not in widespread use on larger boilers like Boardman, that is most likely 

due to availability of sorbents, costs, and SO2 control effectiveness when compared to other SO2

control technologies like semi-dry or wet scrubbers, not technical feasibility. Because more 

sorbent is required with higher SO2 emissions from larger boilers, the cost of sorbent for DSI and 

potential need for additional particulate controls or upgrades likely make other SO2 control 

technologies like dry scrubbers more cost effective. These factors do not render DSI technically 

infeasible for SO2 control at Boardman. It is feasible for use at a boiler like Boardman, and DSI 

can achieve a much higher level of SO2 removal than assumed by PGE as will be discussed 

further below. 

2. PGE overstated the costs of DSI. 

a. Percentage of pollutant removed.

In PGE’s alternative 2020 BART analysis for SO2, PGE claimed that it would reduce SO2

to 0.6 lb/MMBtu with the use of lower sulfur coal and that DSI could reduce SO2 to a rate of 0.4 

lb/MMBtu.22 That is, the DSI evaluated by PGE would only reduce SO2 by 33% from the 

uncontrolled emission rate that would be achieved through the burning of lower sulfur coal.23 

PGE’s baseline SO2 emission rate is 0.61 lb/MMBtu, which is already based on burning lowsulfur coal at Boardman.24 Thus, an SO2 limit of 0.4 lb/MMBtu only reflects a 34% SO2 removal 

efficiency with DSI. To achieve this rate, PGE assumed a sorbent injection rate of 4 tons per 

hour.25 Presumably this amount of sorbent injection was used as the basis for the cost of sorbent 

 

21 See Kong, Yougen et al., Comparison of Sodium Bicarbonate and Trona for SO2 Mitigation at 

A Coal-Fired Power Plant, Electric Power 2009, Rosemont, Illinois, May 12-14, 2009 at 15 

(Exhibit 5). 

22 Id. at 3-17, 4-3, Table 5-3 at 5-2, Table 6-1 at 6-8. 

23 PGE indicates that the proposed 0.4 lb/MMBtu limit is a 67% decrease in Boardman’s 

“allowable” SO2 emission rate. PGE’s August 2010 BART Alternative Submittal at 8-3. Given 

that Boardman does not emit SO2 at its current allowable SO2 emission rate, this comparison is 

irrelevant for visibility protection purposes and is misleading. 

24 Id. at 2-7,5-2. 

25 Id. at 3-16. 
Brian Finneran 

Oregon Department of Environmental Quality 

November 15, 2010 

Page - 12 - 

in the DSI cost analysis in Appendix D of PGE’s August 2010 BART alternative submittal to the 

Department. However, PGE failed to provide the details behind its costs estimates. The design 

and cost details must be obtained and analyzed by the Department in order for the state and the 

public to fully evaluate its estimates of control costs and in order for this analysis to be 

considered a proper BART analysis and determination. 

b. Operating costs overstated.

PGE assumed that reagent would cost $8.3 million per year and disposal would cost $4.1 

million per year, although PGE’s cost analysis did not give the details of which type of sorbent 

or how much of it would be used.26 Presumably the costs of the sorbent and waste disposal was 

based on the assumed 4 tons per hour of sorbent that PGE stated would be needed to achieve the 

proposed 0.40 lb/MMBtu SO2 emission limit. 

Based on available information, 4 tons per hour is a very high sorbent injection rate to 

achieve 33-34% SO2 removal. According to information from Solvair, a vendor of trona and 

sodium bicarbonate, an SO2 removal rate of 33-34% should be achievable with trona injection at 

a normalized stoichiometric ratio (NSR) of 0.5.27 At an NSR of 1.0, it takes 2.41 pounds of trona 

per pound of SO2.

28 Thus, an NSR of 0.5 equates to 1.21 pounds of trona per pound of SO2 to 

achieve a 33-34% SO2 removal rate. The amount of SO2 emitted per hour on average by 

Boardman would range from 1.66 to 1.99 tons per hour, depending on capacity factor29 and 

whether lower sulfur coal was utilized. To achieve 33-34% SO2 removal with trona injection at 

Boardman should take approximately 2 to 2.4 tons per hour of sorbent injection. Yet, PGE 

assumed 4 tons per hour of sorbent injection, which is correlated with an NSR of 1.0 and which 

should obtain an SO2 removal efficiency of approximately 60%.30 Thus, PGE overestimated the 

amount of sorbent to be injected based on its claimed SO2 removal efficiency and/or it 

underestimated the amount of SO2 that would be removed with DSI at Boardman. Either way, 

the result is that the costs of DSI per ton of SO2 removed were overstated. 

Assuming only 33-34% removal of SO2 needed and an average of 2.2 tons per hour of 

trona with operations at an 85% capacity factor, that would mean 16,400 tons of trona would be 

 

26 Id., Appendix D at D-8. 

27 See SOLVAir® Select 200 Application Guide, Exhibit 6, at 4th page, available at 

http://www.solvair.us/medialibrary/1,,59154-2-1,00.html#brochures. 

28 Id. at 3rd page. 

29 Note that PGE assumed 100% capacity factor as the design basis for DSI, while it only 

assumed an 85% capacity factor as the design basis for evaluation of other BART controls. See

Appendix C of PGE’s August 27, 2010 PGE Boardman BART/Reasonable Progress Analysis, 

Revision 3: Boardman 2020 Alternative and, in particular, page C-13. 

30 See SOLVAir® Select 200 Application Guide, Exhibit 6, at 4th page 
Brian Finneran 

Oregon Department of Environmental Quality 

November 15, 2010 

Page - 13 - 

needed per year at Boardman to meet the proposed 0.40 lb/MMBtu SO2 limit. According to 

information from Solvair, the current delivered cost of milled trona would be $85 to $95/ton 

delivered.31 Thus, 16,400 tons of trona would cost $1.4 million to $1.6 million per year for trona 

delivered to the Boardman plant site. Yet, PGE indicated that reagent would cost $8.3 million 

per year, more than five times higher. While milled trona costs $40-$50 more per ton,32 this 

would only add $656,000 to $820,000 more per year for a total of $2.06 to $2.42 million per year 

– which is still much less than PGE’s assumed $8.3 million for sorbent. And trona does not have 

to be milled.33 Given the low removal efficiency that would need to be met to achieve the 

proposed 0.4 lb/MMBtu emission limit, it does not seem justifiable to add in the cost of milling 

the trona for PGE’s proposed SO2 limit. 

If sodium bicarbonate is used instead of trona, the cost per ton is higher but less has to be 

used to achieve the same level of SO2 removal. The sodium bicarbonate costs $155-$165/ton but 

it has to be milled.34 It can be milled on site, but if not, the milled price adds $40-$50/ton.35 So 

if sodium bicarbonate is used at Boardman and assuming PGE does not plan to install equipment 

to mill the sorbent on-site, then the cost would be $195 - $215/ton. Although less sodium 

bicarbonate would need to be used than trona, even if we assume the same amount would have to 

be used (i.e., 16,400 tons per year), the maximum yearly sorbent costs would be $3.5 million per 

year. This is less than half of the $8.3 million assumed by PGE for sorbent costs. 

Given the low SO2 removal efficiency that would be required to meet a 0.40 lb/MMBtu 

limit, trona seems likely to be the choice for sorbents at Boardman.36 Assuming a more 

appropriate amount of trona to be used to achieve 33-34% SO2 reduction, the sorbent costs 

would be $1.6 million per year. Simply taking into account lower annual costs for sorbent at 

Boardman of $1.6 million (rather than PGE’s assumed $8.3 million), would reduce PGE’s 

assumed annual costs (direct and indirect) to $10.84 million per year rather than PGE’s assumed 

$17.54 million per year. This more realistic operating cost based solely on the amount and costs 

of sorbent improves cost-effectiveness of DSI from PGE’s estimate of $3,380/ton to $2,090/ton 

of SO2 removed.37 

 

31 Personal communication between P. Fox and SOLVAir Solutions, November 4, 2010. 

32 Id. 

33 See Kong, Yougen et al., Proper System Design for Handling Fine Powder Sorbents, Electric 

Power 2009, Rosemont, Illinois, May 12-14, 2009, at 3 (Exhibit 7). 

34 Pers. Comm. P. Fox and SOLVAir Solutions, November 4, 2010. 

35 Id.

36 See Norman, Jon et al., Decision Matrix for Dry Sorbent Duct Injection for Control of Sulfur 

Oxide Emissions from Combustion Processes, Figure 1 at 2 (Exhibit 8). If less than 50% control 

of SO2 is required, then use of trona or hydrated lime is recommended. 

37 This dollar per ton SO2 removed figure assumes, as PGE did, that sorbent injection would 
Brian Finneran 

Oregon Department of Environmental Quality 

November 15, 2010 

Page - 14 - 

The costs for waste disposal are also overestimated, especially given the overstatement of the 

amount of sorbent needed to achieve 34% SO2 removal. PGE assumed $4.06 million per year 

for waste disposal.38 Assuming 16,400 tons of trona are required to achieve 34% SO2 removal at 

Boardman, this cost for waste disposal is $240 per ton of trona injected. This seems exorbitantly 

high. PGE did not provide any details that went in to its cost calculations, but one could assume 

that PGE overestimated the amount of waste for disposal costs by the same ratio that it 

overestimated the amount of trona needed, i.e., 16,400 tons as compared to PGE’s 4 ton per hour 

estimate which equates to 29,800 tons per year at 85% capacity factor. Adjusting for this likely 

error brings the cost of waste disposal to $2.2 million per year. This would reduce the annual 

cost of DSI to $8.82 million per year, or a cost effectiveness of $1,700/ton of SO2 removed. 

However, this still assumed it costs $240/ton to landfill the increased ash from 16,400 tons of 

trona injected. EPA’s Control Cost Manual indicates that landfilling fly ash costs about $20-

$30/ton, not including transportation.39 EPA has relied on similar numbers in determining costs 

of carbon injection systems for mercury control.40 PGE did not indicate where the waste ash 

would be disposed of or sold, whether it would be disposed of on-site or hauled to a landfill offsite. But even if the increased ash from trona injection was hauled off-site, a disposal cost of 

$120/ton – half of what it appears PGE assumed - seems like a very high ceiling. Assuming 

waste costs for 16,400 tons of trona at a cost of $120 per ton equates to $1.97 million per year. 

A recent presentation by a DSI vendor, United Conveyor Corporation, provided an 

operational cost estimate for a DSI system achieving 50% SO2 removal at a 600 MW unit 

burning PRB coal with an ESP to be $2/MW-hr.41 For Boardman, that would equate to 

approximately $8.9 million per year for operational costs including ash disposal and auxiliary 

power. Yet, PGE estimated annual operational costs of DSI to be $13 million at Boardman. 

Clearly, PGE has significantly overstated the operational costs of DSI. 

c. Capital costs overstated.

PGE has also included capital costs that are not to be included as pollution control costs 

pursuant to EPA’s Control Cost Manual, including owner’s costs, allowance for funds used 

during construction (AFUDC), and taxes. These costs that were improperly included in the 

 

reduce SO2 by 5,188 tpy. See PGE’s August 27, 2010 Boardman BART/Reasonable Progress 

Analysis, Revision 3: Boardman 2020 Alternative, Appendix C at C-13. 

38 Id., Appendix D at D-8. 

39 See EPA’s Control Cost Manual, Section I, at 2-33. 

40 See U.S. EPA, Performance and Cost of Mercury and MultiPollutant Emission Control 

Technology Applications on Electric Utility Boilers, EPA-600/R-03-110 (October 2003) at 52-

53. 

41 See United Conveyor Corporation, UCC Dry Sorbent Injection, Dry Sorbent Injection as an 

Alternative to Scrubbers, 44th slide (Exhibit 12). 
Brian Finneran 

Oregon Department of Environmental Quality 

November 15, 2010 

Page - 15 - 

capital costs sum up to $3.9 million. Further, PGE assumed a total of $1.3 million for purchase 

and installation of a rail spur. Given that the Boardman plant currently receives its coal by train, 

it is unclear why a rail spur would need to be added to the capital costs of a DSI system at 

Boardman. 

The capital costs also appear overstated for the purchase of the sorbent injection 

equipment. SOLVAir has indicated that the capital costs for the sorbent injection equipment for 

a 600 MW unit would be $5 - $6 million.42 Yet, PGE assumed direct capital costs of purchased 

equipment to be $7.7 million.43 Even subtracting $875,000 for the rail spur, PGE’s assumed 

direct capital costs are still high at $6.8 million. 

Reducing the capital costs by the amounts as required by EPA’s Control Cost Manual 

does not provide for (owner’s costs, AFUDC, and taxes), as well as the cost for the rail spur 

which seems unwarranted, PGE’s capital costs for the dry sorbent injection reduce to $17.7 

million. At a 6.5 year life, this equates to $3.48 million per year (compared to PGE’s assumed 

$4.51 million per year). 

This amount for capital costs of equipment purchase and installation is still too high. A 

2007 paper indicates the costs of DSI to achieve 50-60% SO2 reduction were projected to be 

$15-25/kW.44 A recent presentation by United Conveyor Corporation states that capital costs for 

installation of a DSI system designed to achieve 50% SO2 control at a 600 MW unit burning 

Powder River Basin coal with an ESP would be $8 to $15 million dollars.45

3. PGE should have assumed a longer life for DSI than 6.5 years.

It is a flawed assumption that a dry sorbent injection system could not be installed until 

July 2014. BART is to be met as expeditiously as practicable, no later than five years from the 

date EPA approves the SIP. A dry sorbent injection system could be readily installed in a years’ 

time.46 Thus, a December 2011 installation date and thus a 9 year life (i.e., with a 2020 

shutdown date) should have been assumed, rather than a July 2014 installation timeframe and a 

6.5 year life. Taking into account a 9 year life, the cost recovery factor is 0.1534. This means 

 

42 Pers. Comm. P. Fox and SOLVAir Solutions, November 4, 2010. 

43 See PGE’s August 27, 2010 PGE Boardman BART/Reasonable Progress Analysis, Revision 3: 

Boardman 2020 Alternative, Appendix D at D-9. 

44 See Day, Keith C., Duct Injection for Controlling SO3, SO2, CO2, Hg & NOx, Electric Power, 

May 2007, at 13 (Exhibit 9). 

45 See United Conveyor Corporation, UCC Dry Sorbent Injection, Dry Sorbent Injection as an 

Alternative to Scrubbers, 44th slide (Exhibit 12). 

46 See Day, Keith C., Duct Injection for Controlling SO3, SO2, CO2, Hg & NOx, Electric Power, 

May 2007, at 13 (Exhibit 9). 
Brian Finneran 

Oregon Department of Environmental Quality 

November 15, 2010 

Page - 16 - 

that our previously re-calculated capital cost of $17.7 million capital cost47 would equate to an 

annualized capital cost of $2.7 million per year with a 9 year life. 

In summary, adjusting PGE’s cost estimates of DSI taking into account just the following 

aspects of PGE’s dry sorbent injection costs which overstated the cost of this equipment: 

amount and cost of sorbent injection, amount and cost of waste to be landfilled, excluding the 

cost for a rail spur, removing owners’costs, AFUDC, and taxes, along with a 9 year life, results 

in a total annual cost of DSI at Boardman no higher than $6.92 million. At 34% control of SO2, 

an annual cost of $6.92 million reflects a cost effectiveness of $1,334 per ton of SO2 removed at 

Boardman. However, as set forth below, DSI can achieve even greater SO2 control than 34%, 

which would correspondingly lower the costs per ton of SO2 removed with DSI even more. 

4. DSI can achieve greater SO2 emission reductions than assumed by 

PGE. 

As previously noted, PGE assumed that DSI could remove 33-34% of the SO2. This 

assumption was on the low end of the SO2 removal efficiency that can be achieved with DSI. 

The removal efficiency of sorbent injection typically increases as more sorbent is injected. For 

example, trial testing with Solvair Select 200 (trona) shows that 90% SO2 removal can be 

achieved with a NSR of 1.8-2.0.48 Tests from a permanent installation of unmilled trona showed 

70-85% SO2 removal achieved with trona injected at an NSR of 1.5 to 3.0.49 Sodium 

bicarbonate injection was able to achieve 70-85% SO2 removal but at an NSR of 0.5 to 1.5.50

As previously discussed, dry sorbent injection is planned as BART for SO2 for the 

Dominion Kincaid power plant units, which are similar in size to Boardman’s boiler, burn 

Powder River Basin coal, and are equipped with ESPs for particulate control. The company 

indicated the baseline SO2 emission rate of the two units was 0.623 lb/MMBtu and 0.638 

lb/MMBtu for Units 1 and 2, respectively, and the company proposed SO2 BART limits of 0.18 

– 0.20 lb/MMBtu with DSI.51 The Illinois EPA has proposed a 0.18 lb/MMBtu SO2 limit as 

 

47 Reducing PGE’s estimated capital costs by the amounts EPA’s Control Cost Manual does not 

allow (owner’s costs, AFUDC, and taxes) as well as the cost for the rail spur. 

48 See SOLVAir® Select 200 Application Guide, at 4 (Exhibit 6). 

49 See Kong, Yougen et al., Dry Sorbent Injection of Sodium Bicarbonate for SO2 Mitigation, 

Power-Gen International 2008, Orlando, December 2-4, 2008 at 21 (Exhibit 11). 

50 Id. In fact, Solvay indicates that about half the amount of sodium bicarbonate is needed to 

achieve the same level of SO2 control achieved with unmilled trona Select 200 and that the 

difference would be less if the trona was milled to the same particle size as the milled sodium 

bicarbonate. Id. 

51 See ENSR Corporation, BART Analysis for the Kincaid Power Plant, January 2009, at 2-3, 3-

3 to 3-4 (Exhibit 3). 
Brian Finneran 

Oregon Department of Environmental Quality 

November 15, 2010 

Page - 17 - 

BART for these units in its regional haze SIP.52 This limit reflects 71-72% SO2 control with 

DSI from baseline emissions, more than double the removal efficiency that PGE assumed could 

be obtained with DSI at Boardman. 

Edison Mission Energy in Illinois recently announced plans to use trona for SO2 control 

at several Illinois power plants. The SO2 reductions are required pursuant to a 2006 Illinois EPA 

agreement and also under the forthcoming Transport Rule requirements. The company has 

proposed trona injection to be installed in the next few years at numerous of its electrical 

generating units including Waukegan 7 and 8, Fisk 19, Crawford 7 and 8, Joliet 6, 7, and 8, 

Powerton 5 and 6, and Will County 3 and 4.53 The size of these electrical generating units range 

from 240 MW to 890 MW. The Illinois Compliance Agreement emission rates include SO2 

emission limits as low as 0.13 lb/MMBtu for several units including the 890 MW Will County 

Units 3 and 4.54 All of these units burn Powder River Basin coal and are equipped with ESPs. 

Thus, these units are similar to Boardman, but much lower SO2 emission rates are being required 

than PGE’s proposed 0.40 lb/MMBtu with the same SO2 pollution controls. 

The Gallagher Units 2 and 4 are required pursuant to a consent decree with EPA to install 

a dry sorbent injection system and meet SO2 emission limits of 0.800 lb/MMBtu.55 These units 

are smaller than Boardman at 150 MW each, but the units burn higher sulfur coal. Based on 

emissions information available in EPA’s Clean Air Markets Database, Gallagher Units 2 and 4 

had an uncontrolled SO2 emission rate of approximately 3 lb/MMBtu in 2009. According to 

testimony provided on behalf of Duke Energy Indiana to the Indiana Utility Regulatory 

Commission, the dry sorbent injection system would achieve at least 50% SO2 removal based on 

coal with an average SO2 content of 1.6 lb/MMBtu.56 These DSI systems are to be installed by 

January 2011. It must be noted that the 0.800 lb/MMBtu does not reflect a limit determined 

through BACT or BART.57 Yet, the units will still achieve a higher SO2 removal efficiency than 

 

52 See Illinois EPA, Draft Technical Support Document Regional Haze State Implementation 

Plan for Illinois, October 7. 2010, at 22, available at http://www.epa.state.il.us/air/. 

53 See “Edison Mission Energy to Use Trona for SO2 Control on Illinois Power Plants,” FGD 

and DeNox Newsletter, October 2010, No. 390, Exhibit 4. 

54 Id.

55 See Partial Consent Decree between United States of America and Cynergy Corp., et al., 2009, 

at 17 (paragraph 51), available at 

http://www.epa.gov/compliance/resources/cases/civil/caa/dukeenergy-infosht.html. 

56 See September 8, 2010 Approval by Indiana Utility Regulatory Commission, Petition of Duke 

Energy Indiana, Inc., 1) for Issuance of a Certificate of Public Convenience and Neccessity for 

Use of Clean Coal Technology for a Project, Dry Sorbent Injection, at Petitioners’ Gallagher 

Generating Station; and 2) To Conduct Ongoing Review of the Implementation of the Project, 

Cause No. 43873, at 5 (Exhibit 10). 

57 Units 1 and 3 at Gallagher were not part of the United States’ complaint against the owners of 
Brian Finneran 

Oregon Department of Environmental Quality 

November 15, 2010 

Page - 18 - 

what PGE has proposed for Boardman as BART. 

Dry sorbent injection is currently used at the Mirant Potomac River Generating Plant. 

These units range from 88-102 MW in size, and they typically burn Central Appalachian coal. 

Testing of sorbent injection at these units showed up to 80% SO2 removal was achieved.58 Trona 

and sodium bicarbonate injection both achieved 70-80%+ SO2 removal, but the sodium 

bicarbonate achieved 80% SO2 removal at lower injection rates.59 A comparison of SO2

emissions data from 2004, before sorbent injection was tested or installed, to 2009 emissions 

shows that the units are achieving 77% SO2 removal on average. The 2009 annual average SO2

emission rates for these units ranged from 0.24 to 0.26 lb/MMBtu.60

All of the above information and attached exhibits demonstrate that DSI can achieve 

much greater levels of SO2 emission reductions at Boardman than the 33-34% control assumed 

by PGE. Indeed, based on emission limits that have been proposed for several of the Edison 

Mission Energy electrical generating units, an SO2 emission limit of 0.13 lb/MMBtu should be 

required if DSI is adopted by the Department as BART for Boardman with a 2020 shutdown 

date. 

An emission limit of 0.13 lb/MMBtu reflects 79% SO2 removal from baseline SO2

emission rates at Boardman. Such levels of SO2 removal have been proposed and achieved at 

coal-fired boilers with DSI. 

In addition, by combining DSI with use of lower sulfur coal, PGE should readily be able 

to reduce SO2 emissions down to 0.13 lb/MMBtu. This is especially true given that there is 

lower sulfur coal available than assumed by PGE in projecting a reduced sulfur coal SO2

emission rate of 0.60 lb/MMBtu. 

If Boardman was subject to an SO2 BART emission limit of 0.13 lb/MMBtu rather than 

its proposed limit of 0.40 lb/MMBtu, its emissions would be reduced to 3,098 tpy61 or 11,804 tpy 

of SO2 reduced from baseline emissions. This is much lower than the 9,714 tpy that would be 

emitted under PGE’s proposed SO2 BART limit of 0.40 lb/MMBtu, which only reflects 5,100 

 

the Gallagher units. See Partial Consent Decree between United States of America and Cynergy 

Corp., et al., 2009, at 3, available at 

http://www.epa.gov/compliance/resources/cases/civil/caa/dukeenergy-infosht.html. 

58 See Kong, Yougen et al., Dry Sorbent Injection of Sodium Bicarbonate for SO2 Mitigation, 

Power-Gen International 2008, Orlando, December 2-4, 2008, at 5 (Exhibit 11). 

59 Id. at 21. 

60 Based on a review of emissions data in EPA’s Clean Air Markets Database. 

61 This assumed 6,400 MMBtu/hr heat input capacity, per Table 1-1 of PGE’s August 2010 

BART alternative submittal, and operations at 85% capacity factor. 
Brian Finneran 

Oregon Department of Environmental Quality 

November 15, 2010 

Page - 19 - 

tpy of SO2 reduced.62 

5. An installation date for DSI of July 2014 does not meet BART 

compliance requirements. 

 

As previously discussed, BART is required to be met “as expeditiously as practicable” 

but no later than the date EPA approves the states’ regional haze SIP. If DSI is determined to be 

BART, it can be readily implemented at Boardman, likely within 6 months.63 Yet, PGE’s 2020 

shutdown proposal identifies a July 2014 compliance timeframe for meeting SO2 emission limits 

it deemed reflective of DSI and reduced sulfur coal. While PGE claimed it cannot accelerate the 

date to meet its proposed 0.40 lb/MMBtu SO2 limit because its coal supplies do not expire until 

the end of 2011, that is not sufficient justification to delay implementation of DSI. PGE does not 

need to burn reduced sulfur coal in order to install and begin using a DSI system. If DSI is 

required as BART, the Department should require it to be installed no later than December 2011. 

D. Selective Catalytic Reduction Technology is BART for NOx in the 2020 

Alternative.

 The Coalition adopts and supports the comments of the National Park Service (“NPS”) 

dated October 1, 2010 regarding BART for NOx generally and under either a 2020 or 2018 

alternative. Specifically, Selective Catalytic Reduction technology (“SCR”) is BART for NOx 

control under at least the 2020 alternative. As set forth in the NPS comments, PGE and the 

Department significantly overestimate the costs of LNB/OFA/SCR controls and improperly 

increased the estimated costs by including costs not allowed under the Control Cost Manual. See

pages 4-6 of the NPS Comments. Under the detailed NPS analysis, using proper and allowable 

costs, SCR is a cost-effective alternative. 

 The NPS also demonstrated that SCR can and should be installed sooner than 2017 and 

that with just five years of useful life (installation in 2015) SCR will produce significant air 

quality benefits for Class I areas and make it much more likely that Oregon’s Haze SIP will 

show reasonable further progress in accordance with the 2018 goals. See pages 6-7 of the NPS 

Comments. 

 Based upon the plain errors in PGE and the Department’s analysis of SCR for NOx 

controls and the proper and well-supported analysis in the NPS comments, the Coalition objects 

to PGE’s 2020 proposed alternative for NOx and urge the Department to require SCR for NOx, 

installed in 2015 with a 2020 alternative. 

 

62 PGE’s 2010 Alternative BART Submittal, Table 5-3 at 5-2. 

63 See Day, Keith C., Duct Injection for Controlling SO3, SO2, CO2, Hg & NOx, Electric Power, 

May 2007, at 13 (Exhibit 9). 
Brian Finneran 

Oregon Department of Environmental Quality 

November 15, 2010 

Page - 20 - 

III. THE DEPARTMENT’S COST-EFFECTIVENESS ANALYSIS FOR ANY BART 

PROPOSAL MUST BE INFORMED BY THE LARGE NUMBER OF CLASS I 

AREAS THAT ARE AFFECTED. 

 PGE’s alternative requires the Department to adopt an unusually low threshold in 

weighing the cost-effectiveness of various BART alternatives. That threshold is particularly 

inappropriate in light of two important factors that must drive the Department’s decisions in this 

matter. 

 First, Oregon’s options for meeting haze reduction requirements are very constrained. 

There are truly only two major regional sources of haze pollutants that cause the haze 

impairments in the region’s Class I areas and whose BART controls will largely dictate the 

success of the region’s plans in achieving reasonable further progress on visibility goals and 

requirements: the Boardman Plant and the TransAlta Centralia Generation L.L.C. facility in 

Centralia, Washington. Without strict BART controls at both of these facilities, it is highly 

unlikely that haze in the region’s Class I areas will be reduced enough to comply with the law. 

 Second, the Department must recognize its responsibility to demonstrate reasonable 

further progress in addressing haze impairments in a very large number of Class I areas. Only 

the Four Corners power plant in New Mexico affects more Class I areas than the Boardman and 

TransAlta facilities. As the harm from these facilities is very great in that it affects so many 

Class I areas, so too is the potential benefit from strict application of BART requirements on 

Boardman and TransAlta. As noted in the NPS Comments, cost-effectiveness is not the only 

determinative of BART and it does not make sense to use a metric that fails to account for 

impacts to multiple Class I areas. See page 9 of NPS Comments. 

 Given the limited options for addressing impacts to a large number of Class I areas over a 

large geographic region, the Department must utilize higher cost-effectiveness thresholds for its 

BART determinations for the Boardman plant. In the most recent analyses, the Department uses 

a $7,300/ton threshold for cost-effectiveness in determining BART. This is at the very bottom of 

the $7,000-10,000 range which itself reflects the historical low-end as noted by the NPS. Given 

the unique situation in Oregon and the large number of Class I areas that must be protected with 

BART from a handful of sources, the Department must use a threshold that is at the top end of 

this range. 

 Similarly, Oregon’s threshold when analyzing cost-effectiveness from the “dollars per 

deciview” perspective, is also low at $10 million per deciview. This is far below the average 

cost per deciview range of $14-18 million assessed as cost-effective by either a source or a state. 

See pages 9-10 of NPS Comments. Again, given the large number of Class I areas at risk as 

compared to elsewhere in the nation where much higher thresholds are the norm, the Department 

should revise its cost-effectiveness threshold to the mid-to high end of the national average for 

“dollars per deciview.” 
Brian Finneran 

Oregon Department of Environmental Quality 

November 15, 2010 

Page - 21 - 

 Recognizing the importance and unique situation in Oregon of protecting so large an area 

in the region coupled with so few opportunities to make the necessary reductions, the 

Department has a responsibility to reassess BART and the 2020 proposal with higher thresholds 

for cost-effectiveness determinations and err on the more protective side of the analysis. In 

doing so, the evidence will demonstrate that semi-dry FGD and SCR are well within the costeffectiveness range for a 2020 option (and may very well be even for a 2018 option.) 

 

IV. THE PGE 2020 ALTERNATIVE WILL NOT MEET REASONABLE FURTHER 

PROGRESS REQUIREMENTS. 

 PGE’s 2020 alternative fails to comply with reasonable further progress requirements for 

haze SIPs under federal law. As noted above, states must demonstrate that they are on task for 

meeting natural conditions in the nation’s Class I areas by 2064. To that end, state’s must 

demonstrate progress on goals at periodic milestones to ensure that states are not faced with a 

haze problem that must all be addressed in the waning years before the deadline. 40 C.F.R. § 

51.308. The first milestone is 2018. 

 In its earlier assessments of 2018 and 2020 closure dates for the Boardman Plant with 

relaxed BART requirements, the Department’s own analysis demonstrates that it will fail to meet 

the reasonable progress goals set for 2018.64 Further relaxation of the BART requirements for 

the Boardman Plant as proposed by PGE will only exacerbate the expected failure. While the 

BART regulations do not specifically mandate that BART be determined based upon meeting the 

first milestone, as noted above, the Department has limited other options for demonstrating 

reasonable further progress. Therefore, further relaxation of the BART requirements, proposed 

by PGE, directly interferes with meeting the reasonable further progress goals, will ensure those 

goals are not met by a fairly substantial margin, and should be rejected by the Department. 

V. THE DEPARTMENT SHOULD RETAIN OPTIONS FOR 2018 AND FIVE YEAR 

CLOSURES. 

 The Coalition urges the Department to continue to consider and maintain 2018 and fiveyear options for closure of the Boardman Plant. To that end, the Department should look at 

additional cost-benefit and technical analysis for the 2018 option in particular. The NPS 

Comments suggest that for SO2 control, DSI (and maybe a semi-dry FGD) is BART. The 

Coalition encourages the Department to fully assess DSI installed in 2014, both with and without 

a baghouse as a viable BART option with a 2018 closure date. It appears from the NPS 

Comments that this alternative would be amply supported and therefore it should be fullyexamined. 

 For NOx, the NPS Comments suggest that SCR may be BART, but that 

LNB/OFA/SNCR certainly is. The Coalition urges the Department to fully assess SNCR, 

 

64 DEQ 2008 Regional Haze Plan, finalized June, 2009; amended September 9, 2010.